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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
(MARK ONE)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2000
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO
COMMISSION FILE NUMBER 1-3187
RELIANT ENERGY, INCORPORATED
(Exact name of registrant as specified in its charter)
TEXAS
(State or other jurisdiction of incorporation or 74-0694415
organization) (I.R.S. Employer Identification Number)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-3000
(Address and zip code of principal executive (Registrant's telephone number, including area
offices) code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
------------------- ---------------------
Common Stock, without par value, and associated New York Stock Exchange
rights to purchase preference stock Chicago Stock Exchange
HL&P Capital Trust I 8.125% Trust Preferred Securities, New York Stock Exchange
Series A
REI Trust I 7.20% Trust Originated Preferred Securities, New York Stock Exchange
Series C
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: Preferred Stock,
cumulative, no par -- $4 series
COMMISSION FILE NUMBER 1-13265
RELIANT ENERGY RESOURCES CORP.
(Exact name of registrant as specified in its charter)
DELAWARE
(State or other jurisdiction of incorporation or 76-0511406
organization) (I.R.S. Employer Identification Number)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-3000
(Address and zip code of principal executive (Registrant's telephone number, including area
offices) code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(B) OF THE ACT:
NAME OF EACH EXCHANGE
TITLE OF EACH CLASS ON WHICH REGISTERED
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NorAm Financing I 6 1/4% Convertible Trust New York Stock Exchange
Originated Preferred Securities
6% Convertible Subordinated Debentures due 2012 New York Stock Exchange
SECURITIES REGISTERED PURSUANT TO SECTION 12(G) OF THE ACT: None
RELIANT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I(1)(A) AND (B) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K
WITH THE REDUCED DISCLOSURE FORMAT.
Indicate by check mark whether each of the registrants: (1) has filed all
reports required to be filed by Section 13 or 15(d) of the Securities Exchange
Act of 1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]
Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of each of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]
The aggregate market value of the voting stock held by non-affiliates of
Reliant Energy, Incorporated (Company) was $12,387,338,940 as of March 12, 2001,
using the definition of beneficial ownership contained in Rule 13d-3 promulgated
pursuant to the Securities Exchange Act of 1934 and excluding shares held by
directors and executive officers. As of March 12, 2001, the Company had
296,125,961 shares of Common Stock outstanding, including 8,575,565 ESOP shares
not deemed outstanding for financial statement purposes. Excluded from the
number of shares of Common Stock outstanding are 4,511,691 shares held by the
Company as treasury stock. As of March 12, 2001, all 1,000 outstanding shares of
Reliant Energy Resources Corp.'s Common Stock were held by the Company.
Portions of the definitive proxy statement relating to the 2001 Annual
Meeting of Shareholders of the Company, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2000, are incorporated
by reference in Item 10, Item 11, Item 12 and Item 13 of Part III of this Form
10-K.
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THIS COMBINED ANNUAL REPORT ON FORM 10-K IS SEPARATELY FILED BY RELIANT
ENERGY, INCORPORATED AND RELIANT ENERGY RESOURCES CORP. INFORMATION CONTAINED
HEREIN RELATING TO RELIANT ENERGY RESOURCES CORP. IS FILED BY RELIANT ENERGY,
INCORPORATED AND SEPARATELY BY RELIANT ENERGY RESOURCES CORP. ON ITS OWN BEHALF.
RELIANT ENERGY RESOURCES CORP. MAKES NO REPRESENTATION AS TO INFORMATION
RELATING TO RELIANT ENERGY, INCORPORATED (EXCEPT AS IT MAY RELATE TO RELIANT
ENERGY RESOURCES CORP.) AND ITS SUBSIDIARIES, OR ANY OTHER AFFILIATE OR
SUBSIDIARY OF RELIANT ENERGY, INCORPORATED.
TABLE OF CONTENTS
PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 35
Item 3. Legal Proceedings........................................... 36
Item 4. Submission of Matters to a Vote of Security Holders......... 36
PART II
Item 5. Market for Reliant Energy's and RERC Corp.'s Common Equity 37
and Related Stockholder Matters.............................
Item 6. Selected Financial Data..................................... 38
RELIANT ENERGY, INCORPORATED
Item 7. Management's Discussion and Analysis of Financial Condition 40
and Results of Operations...................................
Item 7A. Quantitative and Qualitative Disclosures About Market 71
Risk........................................................
Item 8. Financial Statements and Supplementary Data of the 75
Company.....................................................
RELIANT ENERGY RESOURCES CORP.
Item 7. Management's Narrative Analysis of the Results of Operations 141
of Reliant Energy Resources Corp. and its Consolidated
Subsidiaries................................................
Item 7A. Quantitative and Qualitative Disclosures About Market 145
Risk........................................................
Item 8. Financial Statements and Supplementary Data of RERC......... 146
Item 9. Changes in and Disagreements with Accountants on Accounting 178
and Financial Disclosure....................................
PART III
Item 10. Directors and Executive Officers of Reliant Energy and RERC 178
Corp........................................................
Item 11. Executive Compensation...................................... 178
Item 12. Security Ownership of Certain Beneficial Owners and 178
Management..................................................
Item 13. Certain Relationships and Related Transactions.............. 178
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 179
8-K.........................................................
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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. In some cases, you can
identify our forward-looking statements by the words "anticipates," "believes,"
"continue," "could," "estimates," "expects," "intends," "may," "plans,"
"potential," "predicts," "should," "will" or other similar words.
The following list identifies some of the factors that could cause actual
results to differ from those expressed or implied by our forward-looking
statements:
- state, federal and international legislative and regulatory developments,
including deregulation, re-regulation and restructuring of the electric
utility industry and changes in or application of environmental and other
laws and regulations to which we are subject,
- the timing of the implementation of our business separation plan,
- the effects of competition, including the extent and timing of the entry
of additional competitors in our markets,
- industrial, commercial and residential growth in our service territories,
- our pursuit of potential business strategies, including acquisitions or
dispositions of assets or the development of additional power generation
facilities,
- state, federal and other rate regulations in the United States and in
foreign countries in which we operate or into which we might expand our
operations,
- the timing and extent of changes in commodity prices and interest rates,
- weather variations and other natural phenomena,
- political, legal and economic conditions and developments in the United
States and in foreign countries in which we operate or into which we
might expand our operations, including the effects of fluctuations in
foreign currency exchange rates,
- financial market conditions and the results of our financing efforts,
- the performance of our projects, and
- other factors we discuss in this Form 10-K, including those outlined in
"Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Certain Factors Affecting Our Future Earnings."
We have based our forward-looking statements on management's beliefs and
assumptions based on information available at the time the statements are made.
We caution you that assumptions, beliefs, expectations, intentions and
projections about future events may and often do vary materially from actual
results. Therefore, actual results may differ materially from those expressed or
implied by our forward-looking statements.
The following sections of this Form 10-K contain forward-looking
statements:
- Our Business --
- Deregulation and Competition
- Restructuring
- Electric Operations --
- Electric Operations Assets --
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- Generation
- Texas Genco --
- Texas Genco Operations and Market Framework
- Texas Genco Option
- Fuel and Purchased Power --
- Natural Gas Supply
- Coal and Lignite Supply
- Nuclear Fuel Supply
- Purchased Power Supply
- Natural Gas Distribution --
- Supply and Transportation
- Wholesale Energy --
- Power Generation Operations --
- Southwest Region
- Midcontinent Region
- Florida
- Texas
- Development Activities
- Domestic Trading, Marketing, Power Origination and Risk Management
Operations
- European Energy --
- European Power Generation Operations --
- Market Framework
- European Trading, Marketing and Risk Management Operations
- Other Operations --
- Unregulated Retail Electric Business
- eBusiness --
- Pantellos
- IntercontinentalExchange
- Regulation --
- State and Local Regulations --
- Texas --
- Electric Operations -- The Legislation
- Electric Operations -- Rate Case
- European Regulation
- Environmental Matters --
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- General Environmental Issues
- Air Emissions
- Water Issues
- Mercury Contamination
- Other
- Legal Proceedings
- Management's Discussion and Analysis of Financial Condition and Results
of Operations --
- Results of Operations by Business Segment --
- European Energy
- Certain Factors Affecting Our Future Earnings --
- Business Separation and Restructuring
- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations
- Competitive, Regulatory and Other Factors Affecting Our Wholesale
Energy Operations
- Competitive, Regulatory and Other Factors Affecting Our European
Energy Operations
- Competitive and Other Factors Affecting RERC Operations
- Environmental Expenditures
- Liquidity and Capital Resources --
- Company Consolidated Capital Requirements
- Future Sources and Uses of Cash Flows
- New Accounting Pronouncements
- Quantitative and Qualitative Disclosures About Market Risk.
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PART I
ITEM 1. BUSINESS.
OUR BUSINESS
GENERAL
Reliant Energy, Incorporated, a Texas corporation, was incorporated in
1906. In this Form 10-K, we refer to Reliant Energy, Incorporated as "Reliant
Energy" and to Reliant Energy and its subsidiaries as "we" or "us," unless the
context clearly indicates otherwise. Reliant Energy Resources Corp., a Delaware
corporation and wholly owned subsidiary of Reliant Energy, was incorporated in
1996. In this Form 10-K, we refer to Reliant Energy Resources Corp. as "RERC
Corp." and to RERC Corp. and its subsidiaries as "RERC," unless the context
clearly indicates otherwise. The executive offices of Reliant Energy and RERC
Corp. are located at 1111 Louisiana, Houston, TX 77002 (telephone number
713-207-3000).
We are a diversified international energy services and energy delivery
company that provides energy and energy services in North America and Western
Europe through the following business segments:
- Electric Operations,
- Natural Gas Distribution,
- Pipelines and Gathering,
- Wholesale Energy,
- European Energy, and
- Other Operations.
For information about the revenues, operating income, assets and other
financial information relating to our business segments, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations by Business Segment" in Item 7 of this Form
10-K, Note 18 to our consolidated financial statements, which, together with the
notes related to those statements, we refer to in this Form 10-K as our
"consolidated financial statements," "Management's Narrative Analysis of the
Results of Operations of Reliant Energy Resources Corp. and its Consolidated
Subsidiaries" in Item 7 of the RERC Form 10-K and Note 12 to RERC's consolidated
financial statements, which, together with the notes related to those
statements, we refer to in this Form 10-K as "RERC's consolidated financial
statements."
RERC conducts its operations primarily in the natural gas industry. RERC's
operations are included in our Natural Gas Distribution and Pipelines and
Gathering business segments, and include natural gas gathering, transmission,
marketing, storage and distribution services. In addition, prior to December 31,
2000, RERC provided energy trading, marketing, power origination and risk
management services in North America and Western Europe through our Wholesale
Energy and European Energy business segments. RERC's operations are described
below in the consolidated description of our business segments.
DEREGULATION AND COMPETITION
In June 1999, the Texas legislature adopted the Texas Electric Choice Plan
(Legislation), which substantially amended the regulatory structure governing
electric utilities in Texas in order to allow retail electric competition.
Retail pilot projects for up to 5% of each utility's load in all customer
classes will begin in June 2001, and retail electric competition for all other
customers will begin on January 1, 2002. In preparation for that competition, we
expect to make significant changes in our electric utility operations currently
conducted through our electric utility division, Reliant Energy HL&P. Under the
Legislation:
- beginning on January 1, 2002, retail customers of investor-owned electric
utilities in Texas, including Reliant Energy HL&P, will be entitled to
purchase their electricity from any of a number of "retail
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electric providers," which will have been certified by the Public Utility
Commission of Texas (Texas Utility Commission),
- beginning on January 1, 2002, power generators will sell electric energy
to wholesale purchasers, including retail electric providers, at
unregulated rates, and
- by January 1, 2002, electric utilities in Texas, including Reliant Energy
HL&P, will have restructured their businesses in order to separate power
generation, transmission and distribution, and retail electric provider
activities into separate units.
Reliant Energy filed its initial business separation plan with the Texas
Utility Commission in January 2000 and filed amended plans in April 2000 and
August 2000. In December 2000, the Texas Utility Commission approved Reliant
Energy's amended business separation plan (Business Separation Plan) pursuant to
which its generation, transmission and distribution, and retail operations will
be separated into three different companies, although a final order has not been
issued as of this date.
For additional information regarding the Legislation, retail competition in
Texas and its application to our operations and structure, please read
"-- Restructuring," "Electric Operations," and "Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of
this Form 10-K, "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations" in Item 7 of this Form 10-K and Note 4 to our consolidated financial
statements.
RESTRUCTURING
In anticipation of electric deregulation in Texas, and pursuant to the
Legislation, we submitted our Business Separation Plan to the Texas Utility
Commission. Pursuant to the Business Separation Plan, we will restructure our
businesses into two separate publicly traded companies in order to separate our
unregulated businesses from our regulated businesses. Under the Business
Separation Plan, our wholly owned subsidiary, Reliant Resources, Inc. (Reliant
Resources), holds substantially all of our unregulated businesses, including the
operations conducted by our:
- Wholesale Energy business segment,
- European Energy business segment,
- communications business,
- eBusiness group,
- new ventures group, and
- retail electric business.
In connection with this separation, on December 31, 2000, Reliant Energy
contributed the capital stock of certain of its subsidiaries to Reliant
Resources, including Reliant Energy Power Generation, Inc.; Reliant Energy
Ventures, Inc.; Reliant Energy Communications, Inc.; Reliant Energy Wholesale
Service Company; Reliant Energy Trading Exchange, Inc.; Reliant Energy
Broadband, Inc.; Reliant Energy Net Ventures, Inc.; ReliantEnergy.com, Inc.;
Guidestreet, Inc.; and Reliant Energy Solutions, LLC. In addition, the assets
and operations of Reliant Energy's retail marketing, unregulated retail and
customer care operations were transferred to Reliant Resources.
As further described below and as part of the separation, Reliant Energy
will undergo a restructuring of its corporate organization to achieve a public
utility holding company structure (Restructuring). This holding company, which
we refer to in this Form 10-K as the "Regulated Holding Company," will hold
essentially all of what are currently our regulated businesses.
We expect Reliant Resources will conduct an initial public offering of no
more than 20% of its outstanding common stock (Offering) in 2001. Reliant
Resources has filed a registration statement with the
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Securities and Exchange Commission (SEC) relating to its shares of common stock
to be sold in the Offering that has not yet been declared effective by the SEC.
The shares of Reliant Resources common stock may not be sold, nor may offers to
buy be accepted, prior to the time the registration statement becomes effective.
This Form 10-K does not constitute an offer to sell or the solicitation of an
offer to buy shares of Reliant Resources common stock. After the Offering, we
will own over 80% of Reliant Resources' outstanding common stock. We anticipate
that the Regulated Holding Company will distribute to its shareholders the
remaining shares of Reliant Resources common stock it would own after the
Offering within 12 months of the completion of the Offering (Distribution).
Reliant Energy will agree that $1.9 billion of the indebtedness owed by Reliant
Resources to Reliant Energy and subsidiaries as of December 31, 2000, will be
converted into equity prior to the closing of the Offering, as a capital
contribution that will be recorded as an increase to stockholders' equity of
Reliant Resources.
The Offering and the Distribution are subject to further Board of Director
approvals, market and other conditions, and government actions, and the
Distribution is subject to receipt of a favorable Internal Revenue Service
ruling that the Distribution would be tax-free to Reliant Energy or its
successor and its shareholders for U.S. federal income tax purposes, as
applicable. There can be no assurance that the Offering and the Distribution
will be completed as described or within the time periods outlined above.
Prior to the closing of the Offering, Reliant Energy will enter into a
number of agreements with Reliant Resources relating to the separation of our
unregulated businesses and our regulated businesses. These agreements will
provide for, among other things, the transfer of assets and liabilities related
to our regulated and unregulated businesses, as well as Reliant Energy's interim
and ongoing relationships with Reliant Resources, including the provision by
Reliant Energy of various interim services to Reliant Resources.
Additionally, as part of our Business Separation Plan, and pursuant to
these separation agreements, we will convey regulated electric generating assets
of our Electric Operations business segment to a yet to be formed indirect
wholly owned limited partnership of Reliant Energy, which we refer to in this
Form 10-K as "Texas Genco." Reliant Energy will grant Reliant Resources an
option, exercisable in January 2004, to purchase all of the shares of capital
stock of Texas Genco owned by the Regulated Holding Company after Texas Genco
conducts a public offering or distribution of no more than 20% of its capital
stock (Texas Genco Option). For additional information regarding the Texas Genco
Option, please read "Electric Operations -- Texas Genco -- Texas Genco Option"
in Item 1 of this Form 10-K.
Concurrent with the Distribution, and in order to comply with applicable
regulatory requirements, under our Business Separation Plan, Reliant Energy will
complete the Restructuring and the Regulated Holding Company will be the parent
company of our subsidiaries that own and operate our regulated businesses. We
expect the Regulated Holding Company will have subsidiaries owning and operating
our:
- electric transmission and distribution operations,
- Natural Gas Distribution business segment,
- Texas generating assets (subject to Reliant Resources' option to purchase
exercisable in 2004),
- Pipelines and Gathering business segment, and
- interests in energy companies in Latin America and India until
disposition of these investments.
In this Form 10-K, references to Reliant Energy in connection with events
occurring or the performance of agreements after the Restructuring generally
refer to the Regulated Holding Company. For additional information regarding the
separation of our unregulated and regulated businesses and related agreements,
Reliant Resources, the Offering, the Distribution, Texas Genco, the
Restructuring and our relationship with Reliant Resources, please read Note 4(b)
to our consolidated financial statements. For additional information regarding
our Latin America business segment discontinued operations, please read Note 19
to our consolidated financial statements.
As part of the separation of our unregulated and regulated businesses, on
December 31, 2000, RERC Corp. transferred all of the outstanding capital stock
of Reliant Energy Services International, Inc. (RESI),
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Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe Trading &
Marketing, Inc. (RE Europe Trading), to Reliant Resources. As a result of these
stock transfers, RESI, Arkla Finance and RE Europe Trading each became a wholly
owned subsidiary of Reliant Resources. Also, on December 31, 2000, a wholly
owned subsidiary of Reliant Resources merged with and into Reliant Energy
Services, Inc. (Reliant Energy Services), which was at that time a wholly owned
subsidiary of RERC Corp., with Reliant Energy Services as the surviving
corporation. As a result of this merger, Reliant Energy Services became a wholly
owned subsidiary of Reliant Resources. As consideration for the stock transfers
and the merger, Reliant Resources paid $94 million to RERC Corp.
Reliant Energy Services, RESI and RE Europe Trading conducted RERC's
trading, marketing, power origination and risk management operations. Arkla
Finance holds an investment in marketable equity securities.
DISCONTINUED OPERATIONS
By the end of 2000, our Latin America business segment had sold its
investments in Brazil, Colombia and El Salvador for $790 million in after-tax
proceeds. Our remaining Latin America business segment investments include a
wholly owned cogeneration facility and an electric distribution company in
Argentina and a minority interest in a coke calcining plant in India. We are
engaged in negotiations for the sale of these investments and anticipate the
transactions to be concluded by December 2001. As of December 1, 2000, we began
reporting the results from our Latin America business segment as discontinued
operations. For additional information regarding our discontinued operations,
please read Note 19 to our consolidated financial statements.
As discussed above, RERC Corp. transferred all of the outstanding stock of
RE Europe Trading to Reliant Resources. As a result of the transfer, RERC Corp.
is reporting the results of RE Europe Trading as discontinued operations. For
additional information regarding RERC's discontinued operations, please read
Note 13 to RERC's consolidated financial statements.
ELECTRIC OPERATIONS
Our Electric Operations business segment conducts operations through an
unincorporated division of Reliant Energy under the name "Reliant Energy HL&P."
We are a member of the Electric Reliability Council of Texas, Inc. (ERCOT) and
our electric operations are inter-connected to ERCOT's transmission grid
encompassing most of the state of Texas. We generate, purchase for resale,
transmit, distribute and sell electricity to approximately 1.7 million customers
in a 5,000-square-mile area on the Texas Gulf Coast, including Houston.
Until January 1, 2002, we expect to conduct our electric operations as a
traditional integrated electric utility, including generation, transmission and
distribution, and retail operations. As required by the Legislation, beginning
January 1, 2002, we expect full retail competition will begin in Texas. Prior to
that date, we will have restructured our electric operations into a transmission
and distribution segment, a generation segment and a retail segment. For
additional information regarding the separation of the operations of our
Electric Operations business segment, please read "-- Texas Genco," and
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our
consolidated financial statements. The retail electric function (the sale of
electricity as opposed to distribution and transmission services) will be
conducted by subsidiaries of Reliant Resources. For additional information
regarding these retail operations, please read "Other Operations -- Unregulated
Retail Electric Business."
Reliant Energy HL&P's transmission system carries electricity from the
power plant to the substation and from one substation to another. These
substations serve to connect the power plants, the high voltage transmission
lines and the lower voltage distribution lines. Unlike the transmission system,
which carries high voltage electricity over great distances, distribution lines
carry lower voltage power from the substation to customers. The distribution
system consists of primary distribution lines, transformers, secondary
distribution
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lines and service wires. Rates for our transmission and distribution services
will be set by the Texas Utility Commission during a rate hearing that is
currently in progress, and we will be allowed to provide services only under
authorized tariffs. For additional information regarding those tariffed rates,
read "Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- Rate Case" in Item 1 of this Form 10-K. The transmission and
distribution operations will not own the electricity that it transmits and
therefore will not be subject to commodity risk. After retail competition
begins, our generation operations will be conducted by Texas Genco, which will
generate power for sale to wholesale purchasers, including retail electric
providers, at unregulated rates. For additional information regarding the
operations of Texas Genco, please read "-- Texas Genco -- Texas Genco Operations
and Market Framework" in Item 1 of this Form 10-K and Note 4(b) to our
consolidated financial statements.
ELECTRIC OPERATIONS ASSETS
All of the power generating facilities and other operating properties of
our Electric Operations business segment are located in the state of Texas.
Transmission and Distribution.
Electric Lines -- Overhead. As of December 31, 2000, we owned 25,646 pole
miles of overhead distribution lines and 3,586 circuit miles of overhead
transmission lines, including 480 circuit miles operated at 69,000 volts, 2,061
circuit miles operated at 138,000 volts and 1,045 circuit miles operated at
345,000 volts.
Electric Lines -- Underground. As of December 31, 2000, we owned 12,653
circuit miles of underground distribution lines and 14.9 circuit miles of
underground transmission lines, including 6.8 circuit miles operated at 69,000
volts and 8.1 circuit miles operated at 138,000 volts.
Substations. As of December 31, 2000, we owned 218 major substation sites
(252 substations) having a total installed rated transformer capacity of 58,041
megavolt amperes.
Generation. As of December 31, 2000, Reliant Energy HL&P owned and
operated 12 power generating facilities (62 generating units), with a net
generating capacity of 14,040 megawatts (MW), including a 30.8% interest in the
South Texas Project Electric Generating Station (South Texas Project). The South
Texas Project is a nuclear generating plant with two 1,250 MW nuclear generating
units. For additional information regarding the South Texas Project, please read
Note 6 to our consolidated financial statements.
The following table contains information regarding the system capability at
peak demand of our Electric Operations business segment:
INSTALLED FIRM
NET PURCHASED CALCULATED
CAPABILITY POWER TOTAL NET MAXIMUM HOURLY FIRM DEMAND % CHANGE RESERVE
AT PEAK CONTRACTS CAPABILITY -------------------------- FROM MARGIN
YEAR (MW) (MW) (MW) DATE MW(2)(3) PRIOR YEAR (%)(4)(5)
- ---- ---------- --------- ---------- ------------- ---------- ---------- ----------
1996................. 13,960 445 14,405 July 23 11,694 2.1 23.2
1997................. 13,960 445 14,405 August 21 12,246 4.7 17.6
1998................. 14,040 320 14,360 August 3 13,006 6.2 10.4
1999................. 14,052 320 14,372 August 20 13,053 0.4 10.1
2000................. 14,040 770(1) 14,810 September 5 14,569 11.6 1.7
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(1) Includes 450 MW of firm capacity purchased to meet peak demand.
(2) Excludes loads on interruptible service tariffs, residential direct load
control and commercial/industrial load cooperative capability. Including
these loads, the maximum hourly demand served was 14,272 MW in 1998, 14,642
MW in 1999 and 15,505 MW in 2000.
(3) Maximum hourly firm demand in 1998, 1999 and 2000 were influenced by hotter
than normal weather at the time of the system peak.
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(4) At any given time we have the ability to enter, and have entered, into
non-firm contracts for purchased power on the spot market within ERCOT, to
provide additional total capability. The ERCOT reserve margin for 2000 was
over 10%.
(5) Electric Operations expects to lose approximately 5% of peak load in 2001
due to the implementation of the retail pilot programs. Please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K.
Based on present trends, Reliant Energy estimates that the maximum hourly
firm demand for electricity in Reliant Energy HL&P's service area will grow at a
compound annual rate of approximately 1.5% over the next ten years. Assuming
average weather conditions and including the net effects of demand-side
management programs, we expect to have an adequate reserve margin in excess of
maximum hourly firm demand load requirements in 2001. The reduced reserve
margins for 1998, 1999 and 2000 reflect customer growth, the relatively small
change in total net capacity and the extremely hot weather conditions at peak in
Reliant Energy HL&P's service area during those summers, which increased system
peak loads by approximately 400 MW, 500 MW and 1,100 MW, respectively. Sales of
electricity by our Electric Operations business segment during the summer months
are generally higher, and can be significantly higher, than sales during other
months of the year due to the reliance on air conditioning by customers in
Houston and in other parts of Reliant Energy HL&P's service territory. However,
Texas' approach to deregulation has provided many opportunities for new
generation. Generators in ERCOT added 4,295 MW of new capacity in 2000 and are
expected to add more than 8,400 megawatts by the summer of 2001. This additional
capacity is expected to result in ERCOT reserve margins in excess of 28% for
2001 under normal weather conditions, significantly more than the 15% ERCOT
minimum requirement. Therefore, we expect there to be sufficient generating
resources available in ERCOT for the summer of 2001. With Reliant Energy HL&P's
interconnections with the rest of ERCOT, adequate capacity should be available
to serve Reliant Energy HL&P customers. Although these reserve margins would be
lower under extreme weather conditions, we still expect there to be adequate
capacity to meet peak demand. For additional information regarding our purchases
of power to meet demand, please read "-- Fuel and Purchased Power -- Purchased
Power Supply" below. For additional information regarding capacity auctions of
wholesale energy after retail electric competition begins, please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K.
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TEXAS GENCO
Texas Genco Facilities. In connection with our Business Separation Plan,
we plan to transfer all of our regulated electric generating assets to Texas
Genco at the time of the Restructuring. All of these assets are located in
Texas. The following table describes the electric power generation facilities to
be conveyed by Reliant Energy to Texas Genco:
TEXAS GENCO GENERATION FACILITIES
NET GENERATING CAPACITY AS OF
GENERATION FACILITIES DECEMBER 31, 2000 (IN MW) DISPATCH TYPE(1) PRIMARY FUEL
- --------------------- --------------------------------- ----------------- ------------
W. A. Parish........................ 3,606 Base, Inter, Peak Gas/Coal
Limestone........................... 1,532 Base Lignite
South Texas Project(2).............. 770 Base Nuclear
San Jacinto......................... 162 Base Gas
Cedar Bayou......................... 2,260 Inter Gas/Oil
P. H. Robinson...................... 2,213 Inter Gas
T. H. Wharton....................... 1,254 Inter, Peak Gas
S. R. Bertron....................... 844 Inter, Peak Gas
Greens Bayou........................ 760 Inter, Peak Gas/Oil
Webster............................. 387 Inter, Peak Gas
Deepwater........................... 174 Inter, Peak Gas
H. O. Clarke........................ 78 Peak Gas
------
Total..................... 14,040
======
- ---------------
(1) The designations "Base," "Inter" and "Peak" indicate whether the facilities
described are base-load, intermediate, or peaking facilities, respectively.
(2) We own a 30.8% interest in the South Texas Project electric generating
station, a nuclear generating plant consisting of two 1,250 MW generating
units.
Power generation facilities can generally be categorized by their variable
cost to produce electricity, which determines the order in which they are
utilized to meet electricity demand. "Base-load" facilities are those that
typically have low variable costs and provide power at all times. Base-load
facilities are used to satisfy the base level of demand for power, or "load,"
that is not dependent upon time of day or weather. "Peaking" facilities have the
highest variable cost to generate electricity and typically are used only during
periods of highest demand for power. "Intermediate" facilities have cost and
usage characteristics in between those of base-load and peaking facilities.
Texas Genco Operations and Market Framework. Any wholesale producer of
electricity that can access ERCOT will be allowed to sell in the Texas market.
Transmission capacity, which may be limited, must be utilized to affect such
sales. In the Texas market, buyers and sellers may negotiate bilateral wholesale
capacity, energy and ancillary services contracts. Also, the power generation
facilities of companies that were formerly part of integrated utilities must
auction the output of 15% of their capacity. For additional information
regarding capacity auctions, please read "Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of
this Form 10-K and Note 4(b) to our consolidated financial statements.
Furthermore, buyers and sellers may participate in the spot market. We expect
the Texas wholesale electric market to be a very competitive market. For
additional information regarding purchased power after 2001, please read
"-- Fuel and Purchased Power -- Purchased Power Supply" below.
In the Texas market, ERCOT has been established as the independent system
operator (ISO) to administer and control the open-access transmission system.
ISO responsibilities include ensuring that information relating to a customer's
choice of retail electric provider is conveyed in a timely manner to anyone
needing the information. The ISO also ensures that electricity production and
delivery are accurately accounted for among the generation resources and
wholesale buyers and sellers in the ERCOT region and serves as agent for
suppliers of ancillary services in the ERCOT region.
7
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Power generation assets will continue to be rate-regulated through the end
of 2001 under the Legislation. For additional information regarding the
impairment of the value of regulatory assets and the recovery of these amounts,
please read "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations -- Other Regulatory Factors" in Item 7 of this Form 10-K and Note
4(a) to our consolidated financial statements.
Texas Genco Option. Pursuant to the Business Separation Plan, we expect
the Regulated Holding Company will cause Texas Genco to either issue and sell in
an initial public offering or to distribute to its shareholders no more than 20%
of the common stock of Texas Genco by June 30, 2002. Our Business Separation
Plan contemplates the grant to Reliant Resources of the Texas Genco Option,
exercisable in January 2004. The per share exercise price under the Texas Genco
Option will be:
- the average daily closing price on a national exchange for publicly held
shares of common stock of Texas Genco for the 30 consecutive trading days
with the highest average closing price during the 120 trading days
immediately preceding January 10, 2004, plus
- a control premium, up to a maximum of 10%, to the extent a control
premium is included in the valuation determination made by the Texas
Utility Commission relating to the market value of Texas Genco's common
stock equity.
The exercise price formula is based upon the generation asset valuation
methodology in the Legislation that we have proposed to use. This market value
will be used to determine the amount we will be allowed to recover as stranded
costs if the market value of those assets is less than the book value of those
assets. For additional information regarding the recovery of stranded costs,
please read Notes 4(a) and 14(i) to our consolidated financial statements.
The exercise price is also subject to adjustment based on the difference
between the per share dividends paid during the period there is a public
ownership interest in Texas Genco and Texas Genco's per share earnings during
that period.
If the disposition to the public of common stock of Texas Genco is by means
of a primary or secondary public offering, the public offering may be of as
little as 17% (rather than 19%) of Texas Genco's outstanding common stock, in
which case Reliant Energy will have the right to subsequently reduce its
interest to a level not less than 80%.
If Reliant Resources exercises the Texas Genco Option and purchases the
shares of Texas Genco common stock, Reliant Resources will also be required to
purchase all notes and other receivables from Texas Genco then held by the
Regulated Holding Company, at their principal amount plus accrued interest.
Similarly, if Texas Genco holds notes or receivables from Reliant Energy,
Reliant Resources will assume those obligations in exchange for a payment to
Reliant Resources by Reliant Energy of an amount equal to the principal plus
accrued interest.
Exercise of the Texas Genco Option by Reliant Resources will be subject to
various regulatory approvals, including Hart-Scott-Rodino antitrust clearance
and United States Nuclear Regulatory Commission (NRC) license transfer approval.
The Texas Genco Option will be exercisable only if the Distribution is
completed.
8
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FUEL AND PURCHASED POWER
Our Electric Operations business segment relies primarily on natural gas,
coal and lignite as fuel for the generation of electricity. For information
regarding our fuel contracts, please read Note 14(b) to our consolidated
financial statements. Our Electric Operations business segment's 1999 and 2000
historical energy mix is set forth below. These figures represent the generation
and purchased power used to meet system load and for off-system sales:
HISTORICAL
ENERGY MIX(%)
-------------
1999 2000
---- ----
Natural gas................................................. 35 37
Coal and lignite............................................ 39 35
Nuclear..................................................... 8 8
Purchased power............................................. 18 20
--- ---
Total............................................. 100 100
=== ===
Based on our current assumptions regarding the cost and availability of
fuel, plant operation schedules, load growth, load management and the impact of
environmental regulations, we do not expect the fuel mix used by our Electric
Operations business segment to vary materially during 2001 even though we
anticipate a higher level of plant maintenance and outages in 2001 associated
with the installation of environmental equipment that could affect the fuel mix.
However, as a result of the Legislation and the introduction of retail electric
competition in 2002, we cannot predict how the fuel mix will be affected after
2001. Please read "Environmental Matters" in Item 1 of this Form 10-K.
Natural Gas Supply. In 2000, our Electric Operations business segment
purchased approximately 54% of its natural gas requirements under long-term
contracts, which will expire in 2004. The largest supplier under these contracts
is Kinder Morgan Texas Pipeline, Inc., a unit of Kinder Morgan, L.P. (supplying
28% of our natural gas requirements). Our Electric Operations business segment
purchased the remaining 46% of its natural gas requirements on the spot market.
Substantially all of these natural gas contracts contain pricing provisions
based on fluctuating spot market prices. Based on current market conditions, we
believe we will be able to replace the supplies of natural gas covered under
expiring long-term contracts with gas purchased on the spot market or under
long-term or short-term contracts. The natural gas consumption and cost
information for our Electric Operations business segment in the year 2000 is as
follows:
2000 average daily consumption................ 808 Bbtu(1)
2000 peak daily consumption................... 1,504 Bbtu
Average cost of natural gas................... $ 3.98 per MMBtu(2)
- ---------------
(1) Billion British thermal units (Bbtu).
(2) Compared to $2.47 per million British thermal unit (MMBtu) in 1999 and $2.18
per MMBtu in 1998.
Through December 31, 2001, the Texas Utility Commission provides for
recovery of most fuel and purchased power costs from customers through a fixed
fuel factor included in electric rates. For additional information regarding our
filings to recover these costs from our customers, please read Note 4(d) to our
consolidated financial statements. For additional information regarding fuel
factor adjustments once retail electric competition begins, please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation."
Although natural gas supplies have been sufficient in recent years,
available supplies are subject to disruption due to weather conditions,
transportation constraints and other events. As a result of these factors,
supplies of natural gas may become unavailable from time to time or prices may
increase rapidly in response to temporary supply constraints or other factors.
9
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Coal and Lignite Supply. Our Electric Operations business segment
purchases approximately 80% of the coal for its four coal-fired units under two
long-term contracts from mines in Wyoming. The first of these contracts will
expire in 2010, and the second will expire in 2011. We obtain the remaining coal
required to operate these units under short-term contracts. Burlington Northern
Santa Fe Railroad and Union Pacific Railroad Company transported our coal supply
during 2000 under long-term rail transportation contracts. A new long-term rail
transportation contract with Burlington Northern Santa Fe Railroad went into
effect in March 2000.
We obtain the lignite used to fuel the two units of our Limestone Electric
Generating station from a surface mine adjacent to the plant. We own the mining
equipment, facilities and a portion of the lignite reserves located at this
mine. We believe the lignite reserves we currently own under lease and contract
will be sufficient to provide substantially all of the lignite requirements of
this facility through 2015. During 2000, a test burn of subbituminous coal was
performed at the Limestone station in order to determine its viability as a fuel
for that station. As a component of our nitrogen oxides (NOx) control strategy
for this station, we anticipate utilizing a blend of lignite and Wyoming
subbituminous coal beginning in 2002. We expect that we will obtain Wyoming coal
through spot and long-term contracts at a delivered price equivalent to that of
lignite.
Nuclear Fuel Supply. The South Texas Project satisfies its fuel supply
requirements by acquiring uranium concentrates, converting uranium concentrates
into uranium hexafluoride, enriching uranium hexafluoride, and fabricating
nuclear fuel assemblies.
We have numerous contracts covering a portion of our nuclear fuel needs for
uranium, conversion services, enrichment services and fuel fabrication. These
contracts have varying expiration dates and most are short to medium term (less
than seven years). Management believes that sufficient capacity for nuclear fuel
supplies and processing exists to preclude the impairment of normal operations
of South Texas Project's nuclear generating units.
Purchased Power Supply. Our Electric Operations business segment purchases
power from various qualifying facilities exercising their rights under the
Public Utility Regulatory Policies Act of 1978. These purchases are generally at
the discretion of the qualifying facility and are made pursuant to a pricing
methodology defined in tariffs approved by the Texas Utility Commission. Reliant
Energy HL&P purchased a total of 14.8 million megawatt hours (MWh) and 16.4
million MWh from qualified facilities in 1999 and 2000, respectively. Due to the
Legislation and the commencement of wholesale competition, we anticipate
terminating or renegotiating the contracts requiring us to purchase qualified
facility power by the end of December 2001, as regulation culminates for the
generation portion of our Electric Operations business segment.
From time to time, as market conditions dictate, we also purchase power
under contracts from various wholesale market participants, exempt wholesale
generators, power marketers and other utilities. For additional information
regarding additional generation supply in ERCOT, please read "-- Electric
Operations Assets -- Generation" above. The increase in supply could result in a
lower cost per MWh in the open market, unless demand increases more than
anticipated. As a result, we may purchase more power in the future than we have
in the past.
COMPETITION
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations" in Item 7 of this Form 10-K, which section is incorporated herein by
reference.
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NATURAL GAS DISTRIBUTION
Our Natural Gas Distribution business segment consists of intrastate
natural gas sales to, and natural gas transportation for, residential,
commercial and industrial customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas and some non-rate regulated retail gas marketing
operations.
We conduct intrastate natural gas sales to, and natural gas transportation
for, residential, commercial and industrial customers through three
unincorporated divisions of RERC Corp.: Reliant Energy Arkla (Arkla), Reliant
Energy Entex (Entex) and Reliant Energy Minnegasco (Minnegasco). These
operations are regulated as gas utility operations in the jurisdictions served
by these divisions.
- Arkla. Arkla provides natural gas distribution services in Arkansas,
Louisiana, Oklahoma and Texas. The largest metropolitan areas served by
Arkla are Little Rock, Arkansas and Shreveport, Louisiana. In 2000,
approximately 68% of Arkla's total throughput was attributable to retail
sales of gas and approximately 32% was attributable to transportation
services.
- Entex. Entex provides natural gas distribution services in over 500
communities in Louisiana, Mississippi and Texas. The largest metropolitan
area served by Entex is Houston, Texas. In 2000, approximately 97% of
Entex's total throughput was attributable to retail sales of gas and
approximately 3% was attributable to transportation services.
- Minnegasco. Minnegasco provides natural gas distribution services in
over 240 communities in Minnesota. The largest metropolitan area served
by Minnegasco is Minneapolis, Minnesota. In 2000, approximately 97% of
Minnegasco's total throughput was attributable to retail sales of gas and
approximately 3% was attributable to transportation services.
The demand for intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers is
seasonal. In 2000, approximately 73% of our Natural Gas Distribution business
segment's revenues occurred in the first and fourth quarters. These patterns
reflect the higher demand for natural gas for heating purposes during those
periods.
SUPPLY AND TRANSPORTATION
Arkla. In 2000, Arkla purchased approximately 57% of its natural gas
supply from Reliant Energy Services, 15% pursuant to third-party contracts, with
terms varying from three months to one year, and 28% on the spot market. Arkla's
major third-party natural gas suppliers in 2000 included Oneok Gas Marketing
Company, Marathon Oil Company and Aquila Energy Marketing Corporation. Arkla
transports substantially all of its natural gas supplies under contracts with
our pipeline subsidiaries. These transportation contracts were renegotiated
during 2000 and have been extended to March 2005.
Entex. In 2000, Entex purchased virtually all of its natural gas supply
pursuant to term contracts, with terms varying from one to five years. Entex's
major third-party natural gas suppliers in 2000 included Enron North America
Corp., Kinder Morgan Texas Pipeline, L.P., Gulf Energy Marketing, Island Fuel
Trading and Koch Energy Trading. Entex transports its natural gas supplies on
both interstate and intrastate pipelines under long-term contracts with terms
varying from one to five years.
Minnegasco. In 2000, Minnegasco purchased approximately 81% of its natural
gas supply pursuant to term contracts, with terms varying from one to ten years,
with more than 25 different suppliers. Minnegasco purchased the remaining 18% on
the daily or spot market. Most of the natural gas volumes under long-term
contracts are committed under terms providing for delivery during the winter
heating season, November through March. Minnegasco purchased approximately 64%
of its natural gas requirements from four suppliers in 2000: Pan-Alberta Gas
Ltd., Reliant Energy Services, TransCanada Gas Services Inc. and Duke Energy
Trading and Marketing, LLC. Minnegasco transports its natural gas supplies on
various interstate pipelines under long-term contracts with terms varying from
five to ten years.
For additional information regarding our ability to pass through changes in
natural gas prices to our customers, please read "Management's Discussion and
Analysis of Financial Condition and Results of
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Operations -- Certain Factors Affecting Our Future Earnings -- Competitive and
Other Factors Affecting RERC Operations -- Natural Gas Distribution" in Item 7
of this Form 10-K.
Arkla and Minnegasco use various leased or owned natural gas storage
facilities to meet peak-day requirements and to manage the daily changes in
demand due to changes in weather. Minnegasco also supplements contracted
supplies and storage from time to time with stored liquefied natural gas and
propane-air plant production.
Minnegasco owns and operates a 7.0 billion cubic feet (Bcf) underground
storage facility, having a working capacity of 2.1 Bcf available for use during
a normal heating season and a maximum daily withdrawal rate of 50 million cubic
feet (MMcf) per day. Minnegasco also owns ten propane-air plants with a total
capacity of 191 MMcf per day and on-site storage facilities for 11 million
gallons of propane (1.0 Bcf gas equivalent). Minnegasco owns a liquefied natural
gas facility with a 12 million-gallon liquefied natural gas storage tank (1.0
Bcf gas equivalent) with a send-out capability of 72 MMcf per day.
Although available natural gas supplies have exceeded demand for several
years, currently supply and demand appear to be in balance. Our Natural Gas
Distribution business segment has sufficient supplies and pipeline capacity
under contract to meet its firm customer requirements. However, from time to
time, it is possible for limited service disruptions to occur due to weather
conditions, transportation constraints and other events. As a result of these
factors, supplies of natural gas may become unavailable from time to time or
prices may increase rapidly in response to temporary supply constraints or other
factors.
MARKETING AND SALES
Our Natural Gas Distribution business segment's marketing and sales group
provides comprehensive natural gas products and services to industrial and
commercial customers in the region from Southern Texas to the panhandle of
Florida, as well as in the Midwestern United States. In 2000, approximately 94%
of total throughput was attributable to the sale of natural gas and
approximately 6% was attributable to transportation services. Typical customer
contract terms for natural gas sales range from one day to three years. Our
marketing and sales groups' operations may be affected by seasonal weather
changes, and the relative price of natural gas. In addition, this segment has
performed as a natural gas marketer to residential and small commercial
customers in several states where natural gas deregulation has occurred. In
2000, however, we decided to exit these markets in order to re-focus resources
and efforts on different markets. Accordingly, we divested our retail customer
contracts in non-strategic areas during 2000 and completed the sale of our
Georgia retail agreements in March 2001.
ASSETS
As of December 31, 2000, we owned approximately 60,000 linear miles of gas
distribution mains, varying in size from one-half inch to 24 inches in diameter.
Generally, in each of the cities, towns and rural areas served by our Natural
Gas Distribution business segment, we own the underground gas mains and service
lines, metering and regulating equipment located on customers' premises and the
district regulating equipment necessary for pressure maintenance. With a few
exceptions, the measuring stations at which we receive gas from our suppliers
are owned, operated and maintained by others, and our distribution facilities
begin at the outlet of the measuring equipment. These facilities, including
odorizing equipment, are usually located on the land owned by suppliers.
COMPETITION
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive and Other Factors Affecting RERC Operations -- Natural
Gas Distribution" in Item 7 of this Form 10-K, which section is incorporated
herein by reference.
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PIPELINES AND GATHERING
Our Pipelines and Gathering business segment operates two interstate
natural gas pipelines as well as gas gathering and pipeline services. Our
pipeline operations are conducted by two wholly owned interstate pipeline
subsidiaries of RERC Corp., Reliant Energy Gas Transmission Company (REGT) and
Mississippi River Transmission Corporation (MRT). Our gathering and pipeline
services operations are conducted by a wholly owned gas gathering subsidiary,
Reliant Energy Field Services, Inc. (REFS), and a wholly owned pipeline services
subsidiary, Reliant Energy Pipeline Services, Inc. (REPS). In 2000, we stopped
reporting the results of operations from our gathering operations, assets and
business in our Wholesale Energy business segment and began reporting these
results in our former Interstate Pipelines business segment, which was renamed
the "Pipelines and Gathering" business segment.
Through REFS, we provide natural gas gathering and related services,
including related liquids extraction and other well operating services. As of
December 31, 2000, REFS operated approximately 4,000 miles of gathering
pipelines, which collect natural gas from more than 200 separate systems located
in major producing fields in Arkansas, Louisiana, Oklahoma and Texas. Through
REPS we provide pipeline project management and facility operation services to
affiliates and third parties.
In 2000, approximately 29% of our Pipelines and Gathering business
segment's total operating revenue was attributable to services provided by REGT
to Arkla, and approximately 14% of its total operating revenue was attributable
to services provided by MRT to Laclede Gas Company (Laclede), an unaffiliated
distribution company that provides natural gas utility service to the greater
St. Louis metropolitan area in Illinois and Missouri. An additional 15% of our
Pipelines and Gathering business segment's operating revenues was attributable
to the transportation of gas marketed by Reliant Energy Services. Our Pipelines
and Gathering segment provides service to Arkla and Laclede under several
long-term firm storage and transportation agreements. At the end of 2000, REGT
renewed various contracts for firm transportation and storage services with
Arkla. These renewals extended the term of service in Arkla's major areas to
2005. The expiration dates for the service agreements with Laclede range from
October 2001 through May 2002. We are currently negotiating the terms and
conditions of a renewal of these agreements with Laclede.
The business and operations of our Pipelines and Gathering business segment
may be affected by seasonal changes in the demand for natural gas, the relative
price of natural gas in the Midcontinent and Gulf Coast natural gas supply
regions and, to a lesser extent, general economic conditions.
ASSETS
We own and operate approximately 8,200 miles of gas transmission lines. We
also own and operate six natural gas storage fields with a combined daily
deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 55.8 Bcf. REGT also owns a 10% interest, with Gulf
South Pipeline Company, LP, in the Bistineau storage facility with 68.8 Bcf of
working gas capacity and 1.1 Bcf per day of deliverability. REGT's storage
capacity in the Bistineau facility is 18 Bcf (8 Bcf of working gas) with 100
MMcf per day of deliverability. Most of our storage operations are in north
Louisiana and Oklahoma. We also own and operate approximately 4,000 miles of
gathering pipelines that collect gas from more than 200 separate systems located
in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
COMPETITION
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive and Other Factors Affecting RERC Operations -- Pipelines
and Gathering" in Item 7 of this Form 10-K, which section is incorporated herein
by reference.
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WHOLESALE ENERGY
Our Wholesale Energy business segment provides electricity and energy
services in the competitive segments of the United States electric power
industry. We acquire, develop and operate electric power generation facilities
that are not subject to traditional cost-based regulation. Therefore, under
current statutes and regulations we can sell power at prices determined by the
market. We also trade and market power, natural gas and other energy-related
commodities and provide related risk management services.
POWER GENERATION OPERATIONS
As of December 31, 2000, our Wholesale Energy business segment owned or
leased electric power generation facilities with an aggregate net generating
capacity of 9,231 MW located in five regions of the United States. We also had
2,766 MW of generating capacity under construction as of that date.
The following table describes our Wholesale Energy business segment's power
generation facilities by region as of December 31, 2000:
REGIONAL SUMMARY OF OUR U.S. GENERATION FACILITIES
NUMBER OF TOTAL NET
GENERATION GENERATING
REGION FACILITIES CAPACITY(MW) DISPATCH TYPE(1) PRIMARY FUEL
- ------ ---------- ------------ ----------------- ------------------
MID-ATLANTIC
Operating........... 21 4,262 Base, Inter, Peak Gas/Coal/Oil/Hydro
SOUTHWEST
Operating........... 6 4,045 Base, Inter, Peak Gas
Under
Construction..... 1 563 Base, Peak Gas
-- ------
Combined............ 7 4,608
MIDCONTINENT
Operating........... 1 255 Peak Gas
Under
Construction..... 1 962 Peak Gas
-- ------
Combined............ 2 1,217
FLORIDA
Operating........... 1 619 Inter, Peak Gas/Oil
Under
Construction..... 1 460 Peak Gas/Oil
-- ------
Combined............ 2 1,079
TEXAS(2)
Operating........... 1 50 Base, CoGen Gas
Under
Construction..... 1 781 Base, CoGen Gas
-- ------
Combined............ 2 831
TOTAL
Operating........... 30 9,231
Under
Construction..... 4 2,766
-- ------
Combined............ 34 11,997
== ======
- ---------------
(1) The designations "Base," "Inter," "Peak" and "CoGen" indicate whether the
facilities described are base-load, intermediate, peaking or cogeneration
facilities, respectively. "Cogeneration" means the combined production of
steam and electricity in a generation facility.
(2) Reliant Resources, which holds our Wholesale Energy operations, has an
option exercisable in January 2004 to acquire Reliant Energy's interest in
Texas Genco, a partnership that is expected to own 14,040 MW of net
generating capacity in Texas. For additional information regarding Texas
Genco and this option, please read "-- Electric Operations -- Texas Genco"
in Item 1 of this Form 10-K.
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The following sections describe the power generation operations and
facilities of our Wholesale Energy business segment by region:
Mid-Atlantic Region. As of December 31, 2000, we owned or leased 21
electric power generation facilities with an aggregate net generating capacity
of 4,262 MW located in the Pennsylvania-New Jersey-Maryland market (PJM market).
These facilities are owned or leased by subsidiaries of Reliant Energy Mid-
Atlantic Power Holdings, LLC (REMA) and include 2,009 MW of base-load, 803 MW of
intermediate and 1,450 MW of peaking capacity, and represent approximately 7% of
the total generation capacity in the PJM market. We sell the power generated by
these facilities to customers located in the PJM market and to buyers in
adjacent electricity markets. The PJM market is one of the most mature and
liquid electricity markets functioning in the United States. In the PJM market,
buyers and sellers "clear" their transactions through an hourly auction process.
In addition, buyers and sellers can negotiate their own contracts outside of the
auction process. We sell power in this market both through the hourly auction
process and under negotiated contracts. We purchased our Mid-Atlantic generation
facilities from Sithe Energies, Inc. in May 2000 for an aggregate purchase price
of $2.1 billion. For additional information related to the purchase of the
Mid-Atlantic generation facilities, please read Note 3(a) to our consolidated
financial statements.
Southwest Region. As of December 31, 2000, we owned six electric power
generation facilities with an aggregate net generating capacity of 4,045 MW
located in the states of California and Nevada. These facilities include 240 MW
of base-load, 3,395 MW of intermediate and 410 MW of peaking capacity and
represent approximately 5% of the total generation capacity in the Southwest
region, which encompasses a region in the southwest part of the United States
that includes the states of Arizona and California, and portions of the states
of New Mexico and Nevada. This region contains approximately 15% of the U.S.
population. We sell the power generated by these facilities to customers located
in the Southwest region.
We purchased five plants from Southern California Edison Company (SCE) in
three transactions in 1998 for an aggregate purchase price of $292 million.
Although we exercise management authority over these five plants, we have
contracted with SCE to operate and maintain these plants through March 2003.
However, we have elected to terminate these contracts effective April 2001.
We own a 50% interest in a 490 MW gas-fired, base-load/peaking facility
located near Las Vegas, Nevada. Sempra Energy owns the other 50% interest in
this plant. We invested $77 million to develop this plant, which has been in
commercial operation since May 2000.
In addition, we have a 563 MW gas-fired, base-load/peaking generation
facility under construction in Casa Grande, Arizona. As of December 31, 2000,
the engineering work for this facility had been completed and the construction
work was approximately 65% complete. Based on this status, we expect this
facility will begin commercial operation in the third quarter of 2001.
California was among the first states to restructure its electricity
markets, based on the establishment of a pool-based bidding system for wholesale
energy and the transfer of authority over the transmission system to the
California Independent System Operator (Cal ISO). Although buyers and sellers in
California originally transacted for short-term, day-ahead and day-of power
through the California Power Exchange (Cal PX), the Cal PX suspended its
day-ahead and day-of markets effective January 31, 2001 and filed for bankruptcy
protection on March 9, 2001. Consequently, the majority of power that is not
generated by the utilities' own generation is currently sold through bilateral
contracts or in the Cal ISO's real-time market. For information about the
current market conditions in California, please read "Regulation -- State and
Local Regulations -- California" in Item 1 of this Form 10-K and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our Wholesale Energy
Operations -- California" in Item 7 of this Form 10-K, as well as Notes 14(h)
and 14(g) to our consolidated financial statements.
In the Southwest region, there is presently no regional transmission
organization (RTO) in place to manage the transmission systems or to operate
energy markets on a region-wide basis, although two RTO working groups are
evaluating the establishment of an organization that would assume control,
subject to
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Federal Energy Regulatory Commission (FERC) approval, over the transmission
systems of the utilities operating in this region.
Midcontinent Region. We own two electric power generation facilities in
the Midcontinent region. One gas-fired peaking generation facility is located in
Shelby County, Illinois. As of December 31, 2000, six of the eight generating
units at this facility were in commercial operation. When all of the generating
units at this plant are in commercial operation, it will have an aggregate net
generating capacity of 344 MW. We expect the remaining two units to be
operational by May 2001. We sell the power generated by this facility on the
open market. This facility was placed in commercial operation in June 2000 at an
aggregate cost of $182 million. Upon completion, we anticipate the total cost of
developing this facility will be approximately $210 million.
We also have an 873 MW gas-fired peaking generation facility under
construction in Aurora, Illinois. As of December 31, 2000, the engineering work
for this facility was approximately 79% complete and the construction work was
approximately 54% complete. Based on this status, we expect this facility will
begin commercial operation in the second quarter of 2001.
Our Illinois generating facilities are located in the Midcontinent region
near Chicago and primarily sell their output in the Mid-America Interconnected
Network reliability council. However, they are capable of serving the entire
Midcontinent region. The Midcontinent region encompasses all or a portion of
three reliability councils that include the states of Illinois, Wisconsin,
Missouri, Indiana, Ohio, Michigan, Virginia, West Virginia, Tennessee, Maryland,
Mississippi, Pennsylvania, Alabama, Georgia and Kentucky.
Florida. We own one gas and oil-fired intermediate/peaking generation
facility with an aggregate net generating capacity of 619 MW located near
Titusville, Florida (Indian River plant). This facility can be operated as
either an intermediate or a peaking facility and represents approximately 1.5%
of the total generation capacity in the state of Florida. We sell up to 593 MW
of the power generated by this facility to the Orlando Utilities Commission
(OUC) under a four-year power purchase agreement that was scheduled to terminate
in September 2003. OUC has exercised its option to extend the power purchase
agreement to September 2007 at a base capacity of 500 MW. Any excess power
generated by the plant is sold to other utilities and rural electric
cooperatives within the region. We purchased this facility from OUC in October
1999 for a net purchase price of $188 million.
In addition to our Indian River plant, we are beginning construction on a
460 MW gas- and oil-fired peaking generation facility in Osceola County,
Florida. As of December 31, 2000, the engineering work for this facility was
approximately 56% complete and the construction work was approximately 9%
complete. We expect this facility will begin commercial operation in the third
quarter of 2001.
In the first quarter of 2001, we entered into tolling arrangements with a
third party to purchase the rights to utilize and dispatch electric generating
capacity of approximately 1,100 MW. This electricity is expected to be generated
by two gas-fired, simple-cycle peaking plants, with fuel oil backup, to be
constructed by the tolling partner in Florida, which are anticipated to be
completed by the summer of 2002.
The state of Florida (other than a portion of the western panhandle)
constitutes a single reliability council and contains approximately 5% of the
U.S. population. Florida is in the process of establishing an independent system
operator that will further define the rules and requirements around which a
competitive wholesale market will develop. Transactions in the Florida market
are presently non-standard and highly negotiated for terms and conditions. Until
the rules for system operations are established, we expect the Florida market to
continue to be illiquid.
Texas. We own a 50% interest in a 100 MW gas-fired base/cogeneration
facility in Orange, Texas (Sabine plant). Air Liquide owns the other 50%
interest in this plant. The Sabine plant, in which we invested $32 million, has
been in commercial operation since December 1999. In addition to the Sabine
plant, we currently have a 781 MW gas-fired, combined cycle, cogeneration
facility under construction in Channelview, Texas (Channelview plant). As of
December 31, 2000, the engineering work for this facility was approximately 75%
complete and the construction work of Phase I (which consists of 171 MW) was
approximately 30% complete. Based on this status, we expect this facility will
begin commercial operation in the third quarter
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of 2001. Equistar Chemicals, L.P. has agreed to purchase up to 293 MW of the
Channelview plant's capacity under a 17-year contract. Discussions regarding the
possible sale of a substantial portion of the balance of the output of the plant
on a long-term basis are currently underway.
DEVELOPMENT ACTIVITIES
We intend to continue to grow the generation asset portfolios of our
Wholesale Energy business segment by developing additional capacity either
through building new facilities or expanding existing facilities in our domestic
regional markets. As of December 31, 2000, we had 2,766 MW of projects under
construction. We consider a project to be "under construction" once we have
acquired the necessary permits to begin construction, broken ground at the
project site and contracted to purchase machinery for the project, including the
combustion turbines. In addition, we have a significant number of other projects
that are in various stages of development. These projects may or may not have
received all of the necessary permits and approvals to begin construction. We
cannot assure you that these projects will be completed. As of March 1, 2001, we
had the right to purchase 47 new combustion turbines from General Electric
Company and Siemens Westinghouse Power Corporation scheduled for delivery by the
third quarter of 2003, representing approximately 6,324 MW of generating
capacity for an aggregate purchase price of approximately $1.3 billion. Some of
these combustion turbines will be utilized in both simple cycle and combined
cycle configurations. The combined cycle configurations will result in increased
capacity due to the additional electricity generated by the associated steam
turbines. Consequently as of March 1, 2001, the total maximum plant capacity for
these turbine commitments is approximately 7,991 MW.
DOMESTIC TRADING, MARKETING, POWER ORIGINATION AND RISK MANAGEMENT OPERATIONS
In addition to our power generation operations, we trade and market power,
natural gas and other energy-related commodities and provide related risk
management services to our customers. Our domestic trading, marketing, power
origination and risk management operations complement our domestic power
generation operations by providing a full range of energy management services.
These services include management of the sales and marketing of energy, capacity
and ancillary services from these facilities, and also management of the
purchase and sale of fuels and emissions allowances needed to operate these
facilities. Generally we seek to sell a portion of the capacity of our domestic
facilities under fixed-price sale contracts, fixed-capacity payments or
contracts to sell generation at a predetermined multiple of either gas or oil
prices. This provides us with certainty as to a portion of our margins while
allowing us to maintain flexibility with respect to the remainder of our
generation output. We evaluate the regional forward power market versus our own
fundamental analysis of projected future prices in the region to determine the
amount of our capacity we would like to sell and the terms of sale pursuant to
longer-term contracts. We also take operational constraints and operating risk
into consideration in making these determinations. Generally we seek to hedge a
portion of our fuel costs, which are usually linked to a percentage of our power
sales. We also market energy-related commodities and offer physical and
financial wholesale energy marketing and price risk management products and
services to a variety of customers. These customers include natural gas
distribution companies, electric utilities, municipalities, cooperatives, power
generators, marketers or other retail energy providers, aggregators and large
volume industrial customers.
The following table illustrates the growth of our physical power and gas
trading volumes since 1998:
TRADING VOLUMES
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------
1998 1999 2000
------------- ------------- -------------
Total Power (MWh)........................ 65,227,898 112,133,103 201,938,485
Total Gas (MMBtu)(1)..................... 1,163,124,196 1,820,261,473 2,509,206,281
- ---------------
(1) These figures include sales to RERC's natural gas distribution companies.
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Electric Power Trading and Marketing. We purchase electric power from
other generators and marketers and sell power primarily to electric utilities,
municipalities and cooperatives and other marketing companies. Our trading and
marketing group is also responsible for the marketing of power produced from the
power plants we own. We also provide risk management, physical and financial
fuel purchase and power sales and optimization services to our customers.
Power Origination. We have a specific group of employees focused on
developing and providing customers with long-term customized products (power
origination products). These products are designed and negotiated on a
case-by-case basis to meet the specific energy requirements of our customers.
Our power origination teams work closely with our trading and marketing group
and our power generation group to sell long-term products from our power
generation assets. They also work to leverage our market knowledge to capture
attractive opportunities available through selling products that combine or
repackage energy products purchased from third parties with other third-party
products or with products from our power generation assets. Our efforts to sell
power origination products from our power generation assets have been focused on
longer-term forward sales to municipalities, cooperatives and other companies
that serve end users, as well as sales of near-term products that are not widely
traded. Our power origination products that combine or repackage third-party
products are generally highly structured and therefore require the application
of our commercial capabilities (e.g., power trading and asset positions).
Natural Gas Trading and Marketing. We purchase natural gas from a variety
of suppliers under daily, monthly, variable-load, base-load and term contracts
that include either market-sensitive or fixed pricing provisions. We sell
natural gas under sales agreements that have varying terms and conditions, most
of which are intended to match seasonal and other changes in demand. We sold an
average of 6.9 Bcf per day of natural gas in 2000, an average of 5.0 Bcf per day
in 1999 and an average of 3.2 Bcf per day in 1998, some of which was sold to our
natural gas distribution companies. We plan to continue to purchase natural gas
to supply our power plants.
Our natural gas marketing activities include contracting to buy natural gas
from suppliers at various points of receipt, aggregating natural gas supplies
and arranging for their transportation, negotiating the sale of natural gas, and
matching natural gas receipts and deliveries based on volumes required by
customers. We make transportation arrangements with affiliated and
non-affiliated interstate and intrastate pipelines through a variety of means,
including short-term and long-term firm and interruptible agreements. We also
enter into various short-term and long-term firm and interruptible agreements
for natural gas storage in order to offer peak delivery services to satisfy
winter heating and summer electric generating demands. These services are also
intended to provide an additional level of performance security and backup
services to our customers.
Other Commodities and Derivatives. We trade and market other
energy-related commodities. We use derivative financial instruments to manage
and hedge our fixed-price purchase and sale commitments and to provide
fixed-price or floating-price commitments as a service to our customers and
suppliers. We also use derivative financial instruments to reduce our exposure
relative to the volatility of the cash and forward market prices and to protect
our investment in storage inventories. For additional information regarding our
financial exposure to derivative financial instruments, please read
"Management's Discussion and Analysis of Financial Results and
Operations -- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our Wholesale Energy Operations -- Price
Volatility" in Item 7 of this Form 10-K and "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this Form 10-K.
Risk Management Controls. We control the scope of our trading, marketing,
power origination and risk management operations through a comprehensive set of
policies and procedures involving senior levels of our management. Our Board of
Directors sets the risk limit parameters and the audit committee of the Board
has oversight for the ongoing evaluation of the adequacy of the risk control
organization and policies. A risk oversight committee, comprised of corporate
and business segment officers, oversees all of our activities, which include
commodity price, credit, foreign currency, equity and interest rate risk,
including our trading, marketing, power origination and risk management
operations. The committee also proposes value-at-risk limits to our Board of
Directors. Our Board ultimately sets our aggregate value-at-risk limit. We have
a corporate risk control organization, headed by a chief risk control officer,
which is assigned responsibility for
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establishing and enforcing the policies, procedures and limits and evaluating
the risks inherent in proposed transactions. Key risk control activities include
credit review and approval, credit and performance risk measurement and
monitoring, validation of transactions, portfolio valuation, and daily portfolio
reporting for our trading and asset activities, including mark-to-market
valuation, value-at-risk and other risk measurement metrics. For additional
information regarding our risk management accounting policies, please read
"Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this
Form 10-K.
COMPETITION
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Wholesale
Energy Operations" in Item 7 of this Form 10-K, which section is incorporated
herein by reference.
EUROPEAN ENERGY
Our European Energy business segment includes the operations of N.V. UNA
(UNA) and its subsidiaries and our European trading, marketing and risk
management operations. We created this segment in the fourth quarter of 1999
with the acquisition of UNA and the formation of our European trading, marketing
and risk management operations. For additional information regarding our
acquisition of UNA, please read Note 3(b) to our consolidated financial
statements. Our European Energy business segment generates and sells power from
its generation facilities in the Netherlands and participates in the emerging
wholesale energy trading and marketing industry in Northwest Europe.
EUROPEAN POWER GENERATION OPERATIONS
Facilities. As of December 31, 2000, we owned five electric power
generation facilities with an aggregate net generating capacity of 3,476 MW
located in the Netherlands. These facilities are grouped in three clusters in
the Amsterdam, Utrecht and Velsen regions. UNA is the third largest generating
company in the Netherlands in terms of both installed capacity and electricity
production. In 2000, UNA generated more than 20% of the country's electricity
production, excluding electricity generated by cogeneration or other industrial
processes. In addition to electricity, UNA's generating stations supply a number
of municipalities, including Amsterdam, Nieuwegein, Utrecht and Purmerend, with
hot water for district heating purposes in cooperation with two large Dutch
distribution companies. In 2000, approximately 47% of UNA's generation output
was natural gas-fired, 15% was blast furnace gas-fired, 38% was coal-fired and
less than 1% was oil-fired. UNA procures its gas from Gasunie, the monopoly gas
supplier in the Netherlands. UNA procures its coal from GKE, a coal trading and
supply company owned jointly by UNA and one of the other large Dutch generation
companies.
We acquired UNA, then named N.V. Energieproduktiebedrijf UNA, effective in
October 1999. UNA was the first Dutch generating company to have its stock sold
to investors under a privatization program established under the Dutch
Electricity Act. The total net purchase price of the acquisition was $1.9
billion based on the October 7, 1999 exchange rate of 2.06 Dutch Guilders (NLG)
per U.S. dollar.
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The following table describes the electric power generation facilities we
owned in the Netherlands as of December 31, 2000:
DUTCH GENERATION FACILITIES
NET GENERATING
CAPACITY DISPATCH
GENERATION FACILITIES(1) LOCATION (MW) TYPE(2) PRIMARY FUEL
------------------------ --------- -------------- ----------------- ------------
Hemweg..................... Amsterdam 1,229 Base, Peak Coal/Gas
Velsen..................... Velsen 990 Base, Inter, Peak Gas/Blast
Furnace Gas
Utrecht.................... Utrecht 939 Base, Inter, Peak Gas/Oil
Diemen..................... Amsterdam 249 Base Gas
Purmerend.................. Purmerend 69 Inter Gas
-----
Total............ 3,476
=====
- ---------------
(1) We own a 100% interest in each facility listed. All of these facilities are
operational.
(2) The designations "Base," "Inter" and "Peak" indicate whether the facilities
described are base-load, intermediate or peaking facilities, respectively.
Market Framework. The Netherlands has a peak demand of approximately
14,200 MW. In 1999, UNA and the three other largest Dutch generating companies
supplied approximately 52% of the electricity consumed in the Netherlands.
Smaller Dutch producers supplied about 30% of consumed electricity and the
remainder was imported. The wholesale market opened to competition on January 1,
2001. The retail market has been open to competition for large industrial
customers since January 1, 1999. In 2002, the next retail segment, composed
primarily of commercial customers, will open to competition. The remaining
customers, mainly residential users, are expected to be able to choose their
supplier by early 2003. The timing of the opening of these markets is subject to
change at the discretion of the Dutch Minister of Economic Affairs.
Customers who can select their electric supplier have the choice of
purchasing power through bilateral contracts or on the Amsterdam Power Exchange,
which was the first power exchange in Northwest Europe and has been in operation
since the spring of 1999. Distribution companies, which serve the captive
customers in the Netherlands, are effectively required to purchase a substantial
amount of their requirements through bilateral contracts with a term of at least
one year.
With the start of full-scale wholesale deregulation in January 2001, the
high voltage transmission grid company (TenneT) has taken on the role of
independent system operator. In this role, TenneT is responsible for the
stability of the transmission grid.
EUROPEAN TRADING, MARKETING AND RISK MANAGEMENT OPERATIONS
In October 1999, we established our European trading, marketing and risk
management operations in order to participate in the emerging European energy
trading and marketing businesses. We are initially focusing on trading
opportunities in the Netherlands and Germany and plan to expand into other
European markets in the future. Our marketing operations will initially
concentrate on selling power to large industrial and commercial customers as
well as distribution companies.
Our European trading, marketing and risk management operations utilize a
business model, including risk management and control policies, that is similar
to that utilized in our operations in the United States, while recognizing
relevant differences between these markets. Currently, the primary difference is
a much lower level of liquidity in both gas and power markets in Continental
Europe than in the United States. This difference is largely the result of
market maturity. In the United States, natural gas deregulation preceded power
deregulation and began over a decade ago. In Continental Europe, restructuring
of the power markets began less than two years ago and restructuring of the gas
markets is only just beginning. Given the strides made thus far in Europe and
the lessons learned from energy deregulation in the United States, the United
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Kingdom and other countries around the world, we expect liquidity to increase
steadily in European gas and power markets. We expect to capitalize on these
developments by drawing on our U.S. and European experiences to offer the types
of products and services that customers will need in the new and developing
environment. As of December 31, 2000, our European trading, marketing and risk
management operations had committed to sell the full amount of UNA's targeted
sales through 2001.
COMPETITION
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our European
Energy Operations" in Item 7 of this Form 10-K, which section is incorporated
herein by reference.
OTHER OPERATIONS
Our Other Operations business segment includes:
- the operations of our unregulated retail electric businesses,
- the operations of our communications business (Communications),
- the operations of our eBusiness group,
- the operations of our venture capital division (New Ventures),
- the operations of Reliant Energy Thermal Systems, Inc. (Reliant Energy
Thermal Systems),
- various office buildings and other real estate used in our business
operations,
- unallocated corporate costs, and
- inter-segment eliminations.
UNREGULATED RETAIL ELECTRIC BUSINESSES
We intend to become a provider of retail electric services in Texas through
Reliant Energy Retail Services, LLC (Services) and Reliant Energy Solutions, LLC
(Solutions) when the market opens to retail competition in January 2002.
Beginning with full retail electric competition in Texas on January 1, 2002, we
will provide electricity and related products and services to residential and
small commercial customers through Services, and we will offer customized,
integrated electric commodity, energy management and e-commerce services to the
large commercial and industrial customers through Solutions. Both Services and
Solutions have been certified as retail electric providers by the Texas Utility
Commission, and both are wholly owned, indirect subsidiaries of Reliant
Resources.
Services will provide retail electric services to all of the approximately
1.5 million residential and small commercial customers served by Reliant Energy
HL&P located in its certificated service area who do not take action to select
another retail electric provider. Services will be the affiliated retail
electric provider in Reliant Energy HL&P's certificated service area (both
before and after the Distribution) and will be a non-affiliated retail electric
provider in other parts of Texas. For additional information regarding retail
electric competition, please read "Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of
this Form 10-K.
In preparation for retail electric competition in Texas, we are expanding
an infrastructure of business systems, procedures and practices to meet the
needs of our retail businesses. These include a customer care system module and
wholesale/retail energy supply, risk management, e-commerce,
scheduling/settlement, customer relationship management and sales force
automation systems. As of December 31, 2000, we had spent $50 million on retail
infrastructure development. In addition, we plan to spend approximately $48
million by the end of 2001.
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Market Framework. For additional information regarding the Legislation,
retail competition and its application to our operations and structure, please
read "Our Business -- Restructuring," "Electric Operations," and
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K, "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our Electric Operations" in Item 7 of
this Form 10-K and Note 4 to our consolidated financial statements, which
sections and note are incorporated herein by reference.
Solutions. Solutions provides customized, integrated energy solutions,
including commodity, risk management and energy services products, and demand
side and eBusiness management services to large commercial and industrial
customers. These services include the replacement or upgrade of energy-intensive
capital equipment, infrastructure optimization, substation development,
maintenance and control, and power quality assurance. Solutions targets
institutional, government, manufacturing, industrial and large commercial
customers, including multisite retailers and restaurants, petroleum refineries,
chemical companies, and internet data centers. These customers typically have a
peak electricity demand of greater than one MW for the aggregate of their Texas
facilities. As of December 31, 2000, this customer segment in Texas included
approximately 7,000 customer accounts or metered service points (approximately
2,000 buying organizations) consuming an aggregate of 100 million MWh of
electricity per year.
Since its formation in April 1996, Solutions has completed over 220
projects for large commercial, institutional, governmental and industrial
clients. In November 1999, Solutions acquired the Energy Service Division of
Southland Industries, Inc. for $37 million. This strategic acquisition
strengthened Solutions' engineering and project management expertise and
established a comprehensive marketing arrangement with Southland Industries, a
leading engineering and construction firm. Solutions has also developed an
integrated product offering to serve both the commodity and energy services
needs of its customers.
COMMUNICATIONS
We formed our Communications business to be a single-source, integrated
communications provider, offering web hosting and web design, enhanced data
services, and local and long distance voice services to business customers
within Texas. In November 1999, we began operation as a competitive local
exchange carrier offering resold voice and data services to small and mid-sized
business customers in Houston. In April 2000, we acquired Insync Internet
Services, a business-to-business Internet services provider based in Houston
with an additional presence in Austin and remote facilities in Dallas and San
Antonio. Communications now serves as a facilities-based competitive local
exchange carrier and Internet services provider with switching capacity, access
to a fiber corridor that surrounds the Houston metropolitan area as well as
network operations centers and managed data centers in Houston and Austin. As of
December 31, 2000, we provided enhanced data services and local and long
distance voice services to approximately 2,600 customers in Texas. The voice and
data transmission markets in which we operate are highly competitive. We compete
with a broad range of competitors, including the regional local exchange
incumbent. Our Communications group has been transferred to Reliant Resources.
EBUSINESS
We formed our eBusiness group in November 1999 to manage, expand and
enhance our Internet presence and capabilities. The eBusiness group is charged
with facilitating Internet use by our core businesses and, through Reliant
Energy Net Ventures, Inc., investing in and managing a portfolio of
Internet-related businesses. As of December 31, 2000, our eBusiness group had
invested $18 million in the following new Internet-based businesses:
- Pantellos. In June 2000, we, along with 20 other leading power, gas and
pipeline companies, formed Pantellos, an energy industry e-procurement
marketplace. The newly formed company is beginning to deliver a broad
suite of integrated e-supply chain solutions to the electric, natural gas
distribution, natural gas pipeline and other energy sectors. This
marketplace, located at www.pantellos.com, became
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operational in January 2001. We expect Pantellos' primary competitors
will be online vertical marketplaces, such as Enporion.com and
UtilityFrontier.com.
- IntercontinentalExchange. In July 2000, we, along with five other
natural gas and power companies, American Electric Power, Aquila Energy,
Duke Energy, El Paso Corporation and Mirant (formerly known as Southern
Energy), made an investment in IntercontinentalExchange, a new, web-based
system for trading commodities. These six companies accounted for
approximately 28% of the natural gas volumes and 32% of the power volumes
traded in the U.S. market in 2000. The exchange, www.intcx.com, began
trading precious metals in August 2000 and began trading crude oil, oil
products, natural gas and electricity in October 2000. The potential
benefits of this investment include reducing our cost structure and
facilitating trading activity by combining the liquidity of many of the
large traders. The principal online competitors of
IntercontinentalExchange are EnronOnline, HoustonStreet.com and Altra.com
in addition to more traditional exchanges, such as NYMEX.
The operations of our eBusiness group are conducted, and our ownership
interest in the aforementioned eBusinesses are held, by wholly owned
subsidiaries of Reliant Resources.
NEW VENTURES
In August 1998, we formed our New Ventures division to manage our existing
new technology investments and to identify and invest in promising new
technologies and businesses that relate to our energy services operations. Focus
areas for investment include distributed generation, power quality, clean
energy, energy industry software and systems, and broadband infrastructure.
We make our investments either directly or indirectly as limited partners
in venture capital funds. As of December 31, 2000, we have invested $30 million
in five venture capital funds with an energy, utility and communications focus
and have made commitments to invest an additional $14 million in these funds. As
of December 31, 2000, these funds held investments in 43 companies. Excluding
our investment in Grande Communications, Inc. discussed below, New Ventures'
direct investment portfolio consists of eight companies with a total of $8
million invested as of December 31, 2000.
In September 2000, we agreed to make a $25 million equity investment in
Grande Communications, Inc. Grande Communications is a Texas-based
communications company building a deep fiber broadband network that will offer
bundled services, including high-speed Internet, all-distance telephone and
advanced cable entertainment to homes and businesses. We are also committed,
under specified conditions, to invest a similar amount in a future Grande
Communications equity financing. Grande Communications has announced its
intention to build a broadband network in the Houston area and has secured a
cable franchise from the city of Houston. The Houston buildout will be in
addition to buildouts in the Central Texas cities of Austin, San Marcos and San
Antonio which are already under development.
Our competitors include other large electricity, energy services and
communications companies with venture capital operations and venture capital and
private equity funds. Both we and our competitors are subject to the
fluctuations in the private and public capital markets that may seriously impair
our ability to participate in attractive opportunities for future investments
and/or liquidate investments by private or public market sale.
Our New Ventures operations are wholly owned by Reliant Resources.
RELIANT ENERGY THERMAL SYSTEMS
Reliant Energy Thermal Systems provides a comprehensive range of products
and services, including energy and facility management, engineering,
construction and operation of site-specific heating and cooling plants for
projects, such as buildings, universities and hospitals, as well as district
cooling systems for cities and large metropolitan areas. Reliant Energy Thermal
Systems, in conjunction with Exelon Thermal Systems of Chicago, also operates
the Northwind Houston district cooling plant, which serves downtown Houston's
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central business district with low-temperature chilled water services. Reliant
Energy Thermal Systems is a wholly owned subsidiary of Reliant Energy and will
become a subsidiary of the Regulated Holding Company.
REGULATION
We are subject to regulation by various federal, state, local and foreign
governmental agencies, including the regulations described below.
PUBLIC UTILITY HOLDING COMPANY ACT
Holding Company Status. Reliant Energy is both a public utility holding
company and an electric utility company as defined in the Public Utility Holding
Company Act of 1935 (1935 Act); however, it is exempt from regulation as a
holding company under Section 3(a)(2) of the 1935 Act. Although RERC Corp. is a
gas utility company as defined under the 1935 Act, it is not a holding company
within the meaning of the 1935 Act. Reliant Energy and RERC Corp. remain subject
to regulation under the 1935 Act with respect to certain acquisitions of voting
securities of other domestic public utility companies and utility holding
companies.
Section 33(a)(1) of the 1935 Act exempts foreign utility company affiliates
of Reliant Energy and RERC Corp. from regulation as "public utility companies,"
thereby permitting Reliant Energy and RERC Corp. to invest in foreign utility
companies without registration under the 1935 Act as a holding company or
approval by the SEC. The exemption, however, is subject to the SEC having
received certification from each state commission having jurisdiction over the
retail rates of any electric or gas utility company affiliated with Reliant
Energy or RERC Corp. that such commission has the authority and resources to
protect ratepayers subject to its jurisdiction and that it intends to exercise
its authority. The Texas Utility Commission and the state regulatory commissions
exercising jurisdiction over RERC Corp. (Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas) have provided a certification to the SEC
subject, however, to the right of such commissions to revise or withdraw their
certifications as to any future acquisition of a foreign utility company. The
Texas Utility Commission and the state regulatory commissions of Arkansas and
Minnesota have imposed limitations on the amount of investments by utility
companies (including Reliant Energy and RERC Corp.) in foreign utility companies
and, in some cases, foreign electric wholesale generating companies. These
limitations are based upon a utility company's consolidated net worth, retained
earnings, and debt and stockholders' equity, respectively.
Subject to some limited exceptions, Section 33(f)(1) of the 1935 Act also
prohibits any public utility company from issuing any security for the purpose
of financing the acquisition, ownership or operation of a foreign utility
company, or assuming any obligation or liability in respect of any security of a
foreign utility company.
In connection with the Restructuring, the Regulated Holding Company will
register as a public utility holding company under the 1935 Act. Such
registration will subject the Registered Holding Company to extensive reporting
and accounting requirements mandated by the 1935 Act, including the filing of an
annual report with the SEC and the requirement that recordkeeping is done in
accordance with SEC regulations related to registered holding companies. The
Registered Holding Company will generally be required to obtain SEC approval
prior to the issuance, acquisition and disposition of securities and assets by
it and its subsidiaries and must obtain SEC approval for certain utility mergers
and acquisitions. The entry by the Registered Holding Company and its
subsidiaries into businesses other than electric and/or gas utility businesses
and businesses incidental thereto is also regulated and limited under the 1935
Act.
Proposals to Repeal the 1935 Act. In recent years, several bills have been
introduced in Congress that would repeal the 1935 Act. Repeal or significant
modification to the 1935 Act could have a significant impact on us and the
electric utility industry. At this time, however, we are not able to predict the
outcome of any bills to repeal the 1935 Act or the outlook for additional
legislation in 2001.
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FEDERAL ENERGY REGULATORY COMMISSION
Natural Gas. The transportation and sale for resale of natural gas in
interstate commerce is subject to regulation by the FERC under the Natural Gas
Act and the Natural Gas Policy Act of 1978, as amended. The FERC has
jurisdiction over, among other things, the construction of pipeline and related
facilities used in the transportation and storage of natural gas in interstate
commerce, including the extension, expansion or abandonment of these facilities.
The rates charged by interstate pipelines for interstate transportation and
storage services are also regulated by the FERC.
REGT and MRT periodically file applications with the FERC for changes in
their rates and charges designed to allow them to recover their costs of
providing service to customers (to the extent allowed by prevailing market
conditions), including a reasonable rate of return. These rates are normally
allowed to become effective after a suspension period, and in some cases are
subject to refund under applicable law, until such time as the FERC issues an
order on the allowable level of rates. REGT is currently operating under rates
approved by the FERC that took effect in February 1995, and MRT is currently
providing services pursuant to a negotiated rate settlement approved by the FERC
in October 1997; however, MRT expects to file to change its rates on or before
April 1, 2001.
On February 9, 2000, the FERC issued Order No. 637, which introduces
several measures to increase competition for interstate pipeline transportation
services. Order No. 637 authorizes interstate pipelines to propose
term-differentiated and peak/off-peak rates, and requires pipelines, including
MRT and REGT, to make tariff filings to expand pipeline service options for
customers. Both MRT and REGT made compliance filings in 2000; however, neither
pipeline's Order No. 637 tariff filing has been acted upon by the FERC. On
November 24, 2000, the FERC issued an order authorizing MRT to recover four Bcf
of undercollected fuel over a three-year period. Several customers have sought
rehearing of the FERC's order. Rehearings have not yet been addressed by the
FERC and MRT began recovering the undercollected fuel on February 1, 2001.
Electricity. Under the Federal Power Act, the FERC has exclusive
jurisdiction over wholesale sales of electricity and the transmission of
electricity in interstate commerce by "public utilities." Public utilities that
are subject to the FERC's jurisdiction must file rates with the FERC applicable
to their wholesale sales or transmission of electricity. Most of our generation
subsidiaries sell power at wholesale and are public utilities under the Federal
Power Act. The FERC has authorized these subsidiaries to sell electricity and
related services at wholesale, at market-based rates. In its orders authorizing
market-based rates, the FERC also has granted these subsidiaries waivers of many
of the accounting, record keeping and reporting requirements that are imposed on
public utilities with cost-based rate schedules.
The FERC's orders accepting the market-based rate schedules filed by our
subsidiaries or their predecessors, as is customary with these orders, reserved
the right to revoke or limit our market-based rate authority if the FERC
subsequently determines that any of our affiliates possess excessive market
power. If the FERC were to revoke or limit our market-based rate authority, we
would have to file, and obtain the FERC's acceptance of, cost-based rate
schedules for all or some of our sales. In addition, the loss of market-based
rate authority could subject us to the accounting, record keeping and reporting
requirements that the FERC imposes on public utilities with cost-based rate
schedules. Sales from our Electric Operations business segment are not subject
to FERC jurisdiction because ERCOT is not connected to a national grid.
The FERC issued Order No. 2000 in December 1999. Order No. 2000, which
applies to all FERC jurisdictional transmission companies (Transco), describes
the FERC's intention to oversee the establishment of large regional
transportation organizations (RTOs) and sets forth the minimum characteristics
and functions of RTOs. Among the basic minimum characteristics are that the RTOs
must be independent and must be of sufficient scope and geographical
configuration. Order No. 2000 also encourages RTOs to work with each other to
minimize or eliminate "seams" issues between RTOs in order that inter-regional
transactions will flow more freely. The FERC's goal is to encourage the growth
of a robust competitive wholesale market for electricity. Although Transcos are
not required to join RTOs, they are encouraged to do so. Under Order No. 2000,
RTOs are to be operational by December 15, 2001. However, there can be no
assurance that this timeline or the FERC's goals will be achieved. At least 14
separate organizations, covering the substantial majority of all FERC
jurisdictional Transcos, are in various stages of organization and have
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made at least preliminary filings with the FERC. For additional information
regarding the impact of this FERC order on future earnings, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our Wholesale Energy
Operations -- Regulation" in Item 7 of this Form 10-K.
Trading and Marketing. Our Wholesale Energy business segment's trading and
marketing operations are subject to the FERC's jurisdiction under both the
Natural Gas Act and the Federal Power Act. As a gas marketer, we make sales of
natural gas in interstate commerce at wholesale pursuant to a blanket
certificate issued by the FERC, but the FERC does not otherwise regulate the
rates, terms or conditions of these gas sales. We are also a "public utility"
under the Federal Power Act, and our wholesale sales of electricity in
interstate commerce are subject to a FERC-filed rate schedule that authorizes us
to make sales at negotiated, market-based rates.
In authorizing market-based rates for various of our subsidiaries, the FERC
has imposed some restrictions on these entities' transactions with our Electric
Operations business segment, including a prohibition on the receipt of goods or
services on a preferential basis. The FERC also has imposed restrictions on
natural gas transactions between our Pipelines and Gathering business segment
and our Wholesale Energy business segment's trading and marketing operations to
preclude any preferential treatment. Similar restrictions apply to transactions
between our Electric Operations business segment and our Wholesale Energy
business segment's trading and marketing operations under Texas utility
regulatory laws.
STATE AND LOCAL REGULATIONS
Texas.
Electric Operations -- The Legislation. Reliant Energy HL&P's electric
utility operations are currently subject to traditional cost-of-service
regulation at rates regulated by the Texas Utility Commission. However, in June
1999, the Texas legislature adopted the Legislation which substantially amended
the regulatory structure governing electric utilities in Texas in order to allow
retail competition. Retail pilot projects for up to 5% of each utility's load in
all customer classes will begin in June 2001, and retail electric competition
for all other customers will begin on January 1, 2002. While the Legislation
calls for the commencement of retail competition beginning on January 1, 2002,
the Texas Utility Commission may delay the date on which the retail electric
market is opened to competition in any power region in Texas if it determines
that the region is unable to offer fair competition and reliable service to all
retail customer classes on that date.
The Legislation also requires electric utilities in Texas to restructure
their businesses in order to separate power generation, transmission and
distribution, and retail activities into three different units, whether commonly
or separately owned. Generally, the "retail electric providers" that have been
certified by the Texas Utility Commission will procure or buy electricity from
the wholesale generators at unregulated rates, sell electricity at retail to
their customers and pay the transmission and distribution utility a regulated
tariffed rate for delivering the electricity to their customers. For additional
information regarding these tariffed rates, please read "-- Electric
Operations -- Rate Case" below. Retail electric providers will not be permitted
to own or operate generation assets and their prices will not be subject to
traditional cost-of-service rate regulation. Retail electric providers that are
affiliates of, or successors in interest to, electric utilities may compete
substantially statewide for these sales, but prices they may charge to
residential and small commercial customers within the affiliated electric
utility's certificated service territory are subject to limitations, known as
the "price to beat," at the outset of retail competition as described below.
Two of Reliant Resources' indirect wholly owned subsidiaries, Services and
Solutions, have been certified by the Texas Utility Commission as retail
electric providers. Under our Business Separation Plan, these subsidiaries are
the successors to the retail functions formerly performed by Reliant Energy
HL&P. As "affiliated retail electric providers" of Reliant Energy HL&P, these
subsidiaries will become the retail electric provider on January 1, 2002 for all
customers of Reliant Energy HL&P who do not take action to select another retail
electric provider. As of December 31, 2000, Reliant Energy HL&P had
approximately 1.5 million residential and small commercial customers. Pursuant
to Texas Utility Commission regulation, effective January 1, 2002, the retail
rates charged to former Reliant Energy HL&P residential and small
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commercial customers who have not elected service from another retail electric
provider will be fixed at the price to beat, which will be a price equal to 6%
less than Reliant Energy HL&P's average rates, on a bundled basis, in effect on
January 1, 1999, adjusted to take into account a new fuel factor as of December
31, 2001. The retail subsidiary serving residential and small commercial
customers has the right to request the Texas Utility Commission to adjust the
fuel factor included in the price to beat not more than twice a year if it
demonstrates that the existing fuel factor does not adequately reflect
significant changes in the market price of natural gas and purchased energy used
to serve retail customers. It may not sell electricity at a price other than the
price to beat to residential or small commercial customer classes in Reliant
Energy HL&P's former service territory until January 1, 2005, unless before that
date the Texas Utility Commission determines that 40% or more of the amount of
electric power that was consumed in 2000 by the relevant class of customers
within the affiliated transmission and distribution utility's traditional
certificated service territory is committed to be served by other retail
electric providers. In addition, as long as an affiliated retail electric
provider continues to provide retail service, the Legislation requires it to
make the price to beat available to residential and small commercial customers
in the certificated service area of the related affiliated utility through
January 1, 2007.
The price to beat applies only to electric services provided to residential
and small commercial customers. Electric services provided to large commercial
and industrial customers, whether by the affiliated retail electric provider or
a nonaffiliated retail electric provider, may be provided at any negotiated
price. For additional information regarding Solutions, please read "Other
Operations -- Unregulated Retail Electric Businesses -- Reliant Energy
Solutions."
The Legislation also requires the affiliated retail electric provider to
reconcile and credit to the affiliated transmission and distribution utility in
early 2004 any positive difference between the price to beat, reduced by a
specified delivery charge, and the prevailing market price of electricity,
unless the Texas Utility Commission determines that, on or prior to January 1,
2004, 40% or more of the amount of electric power that was consumed in 2000 by
residential or small commercial customers, as applicable, within the affiliated
transmission and distribution utility's certificated service territory is
committed to be served by other retail electric providers. If the 40% test is
not met and a payment by the retail electric provider is required, the amount of
the credit will not exceed, but could be up to, $150 per customer multiplied by
the number of residential or small commercial customers, as the case may be,
served by the affiliated transmission and distribution utility that are buying
electricity from the affiliated retail electric provider at the price to beat on
January 1, 2004, less the number of new retail electric customers that the
affiliated retail electric provider serves in areas of Texas outside of the
affiliated utility's certificated service area. Any such amounts credited to the
transmission and distribution utility will be netted against stranded costs in
the 2004 true-up proceeding.
In order to facilitate a competitive market, each power generation company
that is unbundled from an integrated electric utility in Texas will be required
to sell at auction 15% of the output of its installed generating capacity. The
first auction will be held prior to September 1, 2001 for power to be delivered
after January 1, 2002. This obligation continues until January 1, 2007, unless
before that date the Texas Utility Commission determines that at least 40% of
the electric power consumed in 2000 by residential or small commercial
customers, as applicable, within the affiliated transmission and distribution
utility's certificated service territory as of January 1, 2002 is committed to
be served by other retail electric providers. An affiliated retail electric
provider may not purchase capacity sold by its affiliated power generation
company in the mandated capacity auctions.
The Legislation requires the Texas Utility Commission to determine
procedures and criteria for designating retail electric providers to serve as
providers of last resort in areas of the state in which retail competition is in
effect. A provider of last resort is required to offer a standard retail
electric service package for each class of customers designated by the Texas
Utility Commission at a fixed rate approved by the Texas Utility Commission, and
is required to provide the service package to any requesting retail customer in
the territory for which it is the provider of last resort. The Texas Utility
Commission is required to designate the initial providers of last resort by June
1, 2001. In the event that no retail electric provider applies to be the
provider of last resort in a given area of the state, the Texas Utility
Commission may require a retail electric provider to become the provider of last
resort as a condition to receiving or maintaining its retail electric provider
certificate. In the event that a retail electric provider fails to serve any or
all of its customers, the
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provider of last resort is required to offer that customer the standard retail
service package for that customer class with no interruption of service to the
customer. Pursuant to the Legislation, the transmission and distribution utility
is not required to serve as the provider of last resort.
For additional information regarding the Legislation, retail competition
and the application of the Legislation to our operations and structure, please
read "Our Business -- Restructuring" and "Electric Operations" in Item 1 of this
Form 10-K, and "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations -- Competition and Deregulation" in Item 7 of this Form 10-K as well
as Note 4 to our consolidated financial statements, which are incorporated
herein by reference.
Electric Operations -- Rate Case. On March 31, 2000, Reliant Energy HL&P
filed its "Wires Case" with the Texas Utility Commission as required by the
Legislation. This filing represents the "unbundling" or separating of costs
related to providing transmission and distribution service. The Wires Case will
set the regulated rates of delivering electricity when electric competition
begins, including pilot programs. The regulated wires rate, or non-bypassable
delivery charge, will include the transmission and distribution rate, a system
benefit fund fee, a nuclear decommissioning fund charge, a municipal franchise
fee, a transition charge associated with any securitization of regulatory assets
or a portion of stranded costs and a competition transition charge, if any.
Hearings were conducted in phases and all have been concluded as of January
2001. Reliant Energy HL&P is currently awaiting a "Proposal for Decision" on the
final phase of the case, which is expected in late March 2001. The Texas Utility
Commission is expected to render an interim order in late April 2001
establishing the rates to be charged for the pilot project beginning in June
2001, with the final wires rates anticipated to be established in August 2001.
Electric Operations -- Fuel Filings. For additional information regarding
Reliant Energy HL&P's fuel filings for the recovery of under-recovered fuel
costs, including the recent filing on March 15, 2001, please read Note 4(d) to
our consolidated financial statements.
Electric Operations -- Other. Currently, Reliant Energy HL&P conducts its
electric utility operations under a certificate of convenience and necessity
granted by the Texas Utility Commission. The certificate of convenience and
necessity covers the present service area and facilities of our Electric
Operations business segment. In addition, Reliant Energy HL&P holds
non-exclusive franchises from the incorporated municipalities in the service
territory of our Electric Operations business segment. These franchises give
Reliant Energy HL&P the right to operate its transmission and distribution
system within the streets and public ways of these municipalities for the
purpose of delivering electric service to the municipality, its residents and
businesses. None of these franchises expires before 2007.
California.
California began the deregulation of its electricity market in 1996,
fashioning a wholesale market structure administered by two independent
non-profit corporations: the Cal ISO, responsible for operational control of the
transmission system and the purchase or sale of electricity in "real-time" to
balance actual supply and demand, and the Cal PX, responsible for conducting
auctions for the purchase or sale of electricity on a day-ahead or day-of basis.
As part of the California deregulation, California's public utilities sold
essentially all of their gas-fired plants to third-party generators. The
utilities were required to sell their remaining generation into the Cal PX
markets and purchase all of their power requirements from the Cal PX markets at
market-based rates approved by the FERC. California's regulatory system
initially prohibited the utilities from entering into forward contracts to cover
the bulk of their customers' requirements. Retail electricity rates were frozen
at levels in effect on June 10, 1996, with a 10% rate reduction for residential
and smaller commercial customers. As a result of rising wholesale power costs in
2000 driven by a combination of factors, including higher natural gas prices and
emission allowance costs, reduction in available hydroelectric generation
resources, increased demand, decreases in net imports, structural market flaws,
including over-reliance on the spot market, and limitations on supply as a
result of maintenance and other outages, the utilities have been unable to
recover their purchased power costs through the retail rates they are allowed to
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charge and have accumulated huge debts to wholesale power suppliers, including
us, as a result. The California Legislature is currently considering legislation
under which a state entity would be formed to purchase and operate a substantial
share of the transmission lines in California in an effort to avoid potential
bankruptcy filings by the utilities, and is also considering other actions to
re-regulate power suppliers operating in the state. For additional information
regarding the situation in California, please read "Wholesale Energy -- Power
Generation Operations -- Southwest Region," "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Results of
Operations by Business Segment -- Wholesale Energy" and "-- Certain Factors
Affecting Our Future Earnings -- Competitive, Regulatory and Other Factors
Affecting Our Wholesale Energy Operations -- California" in Item 7 of this Form
10-K, and Notes 14(g) and 14(h) to our consolidated financial statements.
Other States.
Natural Gas Distribution. In almost all communities in which our Natural
Gas Distribution business segment provides service, RERC operates under
franchises, certificates or licenses obtained from state and local authorities.
The terms of the franchises, with various expiration dates, typically range from
10 to 30 years. None of our Natural Gas Distribution segment's material
franchises expire before 2005. In most cases, franchises to provide natural gas
utility services are not exclusive.
Substantially all of our Natural Gas Distribution segment's retail sales
are subject to traditional cost-of-service regulation at rates regulated by the
relevant state public service commissions and, in Texas, by the Texas Railroad
Commission and municipalities we serve. None of our Natural Gas Distribution
segment's local distribution companies are currently a party to any material
pending rate proceeding. For additional information regarding our ability to
recover increased costs of natural gas from our customers, please read
"Management's Discussion and Analysis of Financial Condition and
Operations -- Certain Factors Affecting our Future Earnings -- Competitive and
Other Factors Affecting RERC Operations -- Natural Gas Distribution" in Item 7
of this Form 10-K.
Wholesale Energy. All of our Wholesale Energy business segment's existing
generation facilities sell power only at wholesale. None of the states in which
these facilities are located regulate sales from these facilities under
traditional utility cost-of-service regulation. In the PJM market and in
California, the independent system operators have imposed price caps that limit
the maximum sales prices for wholesale power. In addition, in some states,
including California, proposals have been made to re-regulate the provision of
wholesale power under traditional cost-of-service regulation. In New Jersey,
existing law provides that the relevant regulatory agency may re-impose
cost-of-service regulation if the agency concludes that competition is not
sufficient. In addition, most states regulate the siting or construction of
generation facilities.
NUCLEAR REGULATORY COMMISSION
Under the 1954 Atomic Energy Act and the 1974 Energy Reorganization Act,
the NRC regulates nuclear plants and has the authority to impose fines or shut
down nuclear plants for non-compliance with its requirements.
Under the 1980 Federal Low-Level Radioactive Waste Policy Act and related
Texas legislation, the Texas Low-Level Radioactive Waste Disposal Authority is
authorized to build and operate a low-level waste disposal facility in Texas.
Currently, the South Texas Project disposes of its low-level nuclear waste under
a short-term agreement at the Barnwell facility in South Carolina. In the event
the Barnwell facility stops accepting waste before a Texas disposal site is
opened, the South Texas Project would store its waste in an interim storage
facility located at the nuclear plant. The plant currently has storage capacity
for at least five years of low-level nuclear waste generated by the project.
For information regarding the NRC's regulation of nuclear decommissioning
trust funds, please read Note 14(l) to our consolidated financial statements.
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EUROPEAN REGULATION
In 1998, the Netherlands established a privatization program under the
Dutch Electricity Act. Under this legislation, the Dutch electricity market
opened to limited wholesale and retail competition on January 1, 1999, and
industrial customers who are end users were able to select their electric
suppliers. Beginning January 1, 2001, the wholesale market was completely opened
to competition. The next customer segment, composed primarily of commercial
customers, will be liberalized in 2002. The remaining customers, mainly
residential, are expected to be able to choose their electric supplier by 2003.
The timing of these market openings is subject to change, however, at the
discretion of the Dutch Minister of Economic Affairs. For additional information
regarding the recent stranded costs legislation in the Netherlands, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our European Energy Operations -- Other"
in Item 1 of the Form 10-K and Note 14(i) to our consolidated financial
statements.
Prior to 2001, UNA, the other large Dutch generating companies and the
Dutch distribution companies operated under various agreements that regulated,
among other things, the rates UNA could charge for its generation output.
Pursuant to these agreements, UNA and other generators sold their generating
output to a national production pool operated by a company owned by the
generators and, in return, received a standardized remuneration. The
remuneration included fuel cost, capital cost and operation and maintenance
expenses. UNA also operated under the protocol, which is an agreement under
which the Dutch generators agreed to provide capacity, energy and various other
services to distributors for a total payment of NLG 3.4 billion ($1.45 billion
based on the December 31, 2000 exchange rate of 2.34 NLG per U.S. Dollar) over
the period 1997 through 2000 plus compensation of actual fuel costs. Effective
January 1, 2001, these agreements expired.
ENVIRONMENTAL MATTERS
GENERAL ENVIRONMENTAL ISSUES
We are subject to a number of federal, state and local requirements
relating to the protection of the environment and the safety and health of
personnel and the public.
These requirements relate to a broad range of our activities, including:
- the discharge of pollutants into the air, water and soil,
- the identification, generation, storage, handling, transportation,
disposal, record keeping, labeling and reporting of, and emergency
response in connection with, hazardous and toxic materials and wastes,
including asbestos, associated with our operations,
- noise emissions from our facilities, and
- safety and health standards, practices and procedures that apply to the
workplace and to operation of our facilities.
In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time to:
- construct or acquire new equipment,
- acquire permits and/or marketable allowances or other emission credits
for facility operations,
- modify or replace existing and proposed equipment, and
- clean up or decommission waste disposal areas, fuel storage and
management facilities, and other locations and facilities, including coal
mine refuse piles and generation facilities.
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We anticipate investing up to $711 million in capital and other special
project expenditures between 2001 and 2005 for environmental compliance. If we
do not comply with environmental requirements that apply to our operations,
regulatory agencies could seek to impose on us civil, administrative and/or
criminal liabilities as well as seek to curtail our operations. Under some
statutes, private parties could also seek to impose civil fines or liabilities
for property damage, personal injury and possibly other costs. For additional
information regarding environmental expenditures, please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Earnings -- Environmental
Expenditures" in Item 7 of this Form 10-K and Note 14(g) to our consolidated
financial statements.
AIR EMISSIONS
As part of the 1990 amendments to the Federal Clean Air Act, requirements
and schedules for compliance were developed for attainment of health-based
standards. As part of this process, standards for the emission of NOx, a product
of the combustion process associated with power generation and natural gas
compression, are being developed or have been finalized. The standards require
reduction of emissions from our power generating units in California, Texas and
the Mid-Atlantic Region and some of our natural gas compression facilities. We
believe the reductions will require substantial expenditures in the years 2001
through 2004, with possible additional expenditures after that for our
facilities in Texas. The post-2004 requirements in Texas are currently being
litigated, and the outcome of the litigation cannot be predicted at this time.
Our facilities in the Netherlands are in compliance with applicable Dutch NOx
emission regulations. Discussions are currently ongoing between the Dutch
government and the electric utility sector as to the acceptable level of
emissions. While no outcome can be predicted, we currently believe that a
market-based NOx emissions trading system will be implemented in the 2002 time
frame, and that ultimately some level of emission reductions will be required
from our generating facilities.
The Environmental Protection Agency (EPA) has announced its determination
to regulate hazardous air pollutants (HAPs) from coal-fired and oil-fired steam
electric generating units under Section 112 of the Clean Air Act. The EPA plans
to develop maximum achievable control technology (MACT) standards for these
types of units. The rulemaking for coal- and oil-fired steam electric generating
units must be completed by December 2004. Compliance with the rules will be
required within three years thereafter. The MACT standards that will be
applicable to the units cannot be predicted at this time so the impact on our
facilities is uncertain. In addition, a request for reconsideration of the EPA's
decision to impose MACT standards has been filed with the EPA. We cannot predict
the outcome of the request.
In 1998, the United States became a signatory to the United Nations
Framework Convention on Climate Change (the Kyoto Protocol). The Kyoto Protocol
calls for developed nations to reduce their emissions of greenhouse gases.
Carbon dioxide, which is a major byproduct of the combustion of fossil fuel, is
considered to be a greenhouse gas. The Kyoto Protocol, however, will not become
enforceable law in the United States unless and until the U.S. Senate ratifies
it. If the Senate ultimately ratifies the Kyoto Protocol, any resulting
limitations on power plant carbon dioxide emissions could have a material
adverse impact on all fossil fuel fired facilities, including those belonging to
us. The European Union, of which the Netherlands is a member, has adopted the
Kyoto Protocol as the goal for greenhouse gas emission targets. UNA, through
innovative use of "green fuels" and efficiency improvements, expects to meet its
portion of the target reductions.
The EPA is conducting a nationwide investigation regarding the historical
compliance of coal-fueled electric generating stations with various permitting
requirements of the Clean Air Act. Specifically, the EPA and the U.S. Department
of Justice have initiated formal enforcement actions and litigation against
several other utility companies that operate these stations, alleging that these
companies modified their facilities without proper pre-construction permit
authority. Since June 1998, six of our coal-fired facilities in the Mid-
Atlantic region have received requests for information related to work
activities conducted at those sites. The EPA has not filed an enforcement action
or initiated litigation in connection with these Mid-Atlantic facilities at this
time. Nevertheless, any litigation, if pursued successfully by the EPA, could
accelerate the timing of emission reductions currently contemplated for the
facilities and result in the imposition of penalties.
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In February 2001, the U.S. Supreme Court upheld a previously adopted EPA
ambient air quality standard for fine particulate matter. While attaining this
new standard may ultimately require expenditures for air quality control system
upgrades for our facilities, regulations addressing affected sources and
required controls are not expected until after 2005. Consequently, it is not
possible to determine the impact on our operations at this time. For additional
information regarding clear-air expenditures, please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Environmental
Expenditures -- Clean Air Act Expenditures" in Item 7 of this Form 10-K.
WATER ISSUES
In July 2000, the EPA issued final rules for the implementation of the
Total Maximum Daily Load program of the Clean Water Act (TMDL). The goal of the
TMDL rules is to establish, over the next 15 years, the maximum amounts of
various pollutants that can be discharged into waterways while keeping those
waterways in compliance with water quality standards. The establishment of TMDL
values may eventually result in more stringent discharge limits in each
facility's discharge permit. Such limits may require our facilities to install
additional water treatment, modify operational practices or implement other
wastewater control measures. Subsequent to the issuance of the final rule, the
U.S. Congress acted to prohibit implementation of the rule until at least the
fourth quarter of 2001.
The EPA proposed rules that would impose uniform technology requirements on
new cooling water intake structures. These rules are expected to be finalized,
and rules for existing structures proposed, during the summer of 2001. It is not
known at this time what requirements the final rules for existing intake
structures might impose, whether any of our facilities might require
modification as a result or what the magnitude of our obligations would be.
A number of efforts are under way within the EPA to evaluate water quality
criteria for parameters associated with fossil fuel combustion. These parameters
include arsenic, mercury and selenium. Significant changes in these criteria
could impact station discharge limits and could require our facilities to
install additional water treatment equipment. The impact on us as a result of
these initiatives is unknown at this time. For additional information regarding
environmental expenditures associated with this, please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Environmental
Expenditures -- Water, Mercury and Other Expenditures" in Item 7 of this Form
10-K.
MERCURY CONTAMINATION
Like similar companies, our pipeline and natural gas distribution
operations have in the past employed elemental mercury in measuring and
regulating equipment meters used on our pipelines. It is possible that small
amounts of mercury may have been spilled in the course of normal maintenance and
replacement operations and that these spills may have contaminated the immediate
area around the meters with elemental mercury. This type of contamination has
been found by us in the past, and we have conducted remediation at sites found
to be contaminated. Although we are not aware of additional specific sites, it
is possible that other contaminated sites may exist and that remediation costs
may be incurred for these sites. Although the total amount of these costs cannot
be known at this time, based on our experience and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, we believe that the cost of any remediation of these sites will not
be material to our financial position, results of operations or cash flows. For
additional information regarding environmental expenditures associated with
mercury contamination, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Environmental Expenditures -- Water, Mercury and Other
Expenditures" in Item 7 of this Form 10-K.
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OTHER
We have 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 us. We anticipate that additional claims like those
received may be asserted in the future, and we intend to continue our practice
of vigorously contesting claims that we do not consider to have merit. Although
their ultimate outcome cannot be predicted at this time, we do not believe,
based on our experience to date, that these matters, either individually or in
the aggregate, will have a material adverse effect on our financial position,
results of operations or cash flows.
EMPLOYEES
As of December 31, 2000, we had 15,633 full-time employees. The following
table sets forth the number of our employees by business segment as of December
31, 2000:
SEGMENT NUMBER
- ------- ------
Electric Operations........................................ 6,667
Natural Gas Distribution................................... 4,791
Pipelines and Gathering.................................... 608
Wholesale Energy........................................... 1,776
European Energy............................................ 926
Other Operations........................................... 865
------
Total............................................ 15,633
======
The number of employees of Reliant Energy and its subsidiaries who are
represented by unions or other collective bargaining groups include (i) Electric
Operations, 2,797; (ii) Natural Gas Distribution, 1,544; (iii) Wholesale Energy,
769; and (iv) European Energy, 846.
EXECUTIVE OFFICERS OF RELIANT ENERGY
(AS OF MARCH 12, 2001)
OFFICER
NAME AGE SINCE PRESENT POSITION
- ---- --- ------- ----------------
R. Steve Letbetter(1).......... 52 1978 Chairman, President, Chief Executive Officer
and Director
Robert W. Harvey(1)............ 45 1999 Vice Chairman
David M. McClanahan............ 51 1986 Vice Chairman, and President and Chief
Operating Officer, Reliant Energy Delivery
Group
Stephen W. Naeve(1)............ 53 1988 Vice Chairman and Chief Financial Officer
Joe Bob Perkins(1)............. 40 1996 President and Chief Operating Officer,
Reliant Energy Wholesale Group
Hugh Rice Kelly(1)............. 58 1984 Executive Vice President, General Counsel and
Corporate Secretary
Mary P. Ricciardello(1)........ 45 1993 Senior Vice President and Chief Accounting
Officer
- ---------------
(1) Effective as of the Distribution, these individuals will resign their
positions with Reliant Energy, except that Mr. Letbetter will continue to
serve as non-executive Chairman of the Reliant Energy Board of Directors.
33
39
Mr. Letbetter has served as Chairman of Reliant Energy since January 2000
and as President and Chief Executive Officer of Reliant Energy since June 1999.
He has been a director of Reliant Energy since 1995. He has served in various
executive officer capacities with Reliant Energy since 1978.
Mr. Harvey has served as Vice Chairman of Reliant Energy since June 1999.
Prior to joining Reliant Energy, he served as a director in the Houston office
of McKinsey & Company, Inc.
Mr. McClanahan has served as Vice Chairman of Reliant Energy since October
2000 and as President and Chief Operating Officer of the Reliant Energy Delivery
Group since 1999. Previously, he served as President and Chief Operating Officer
of the Reliant Energy HL&P division from 1997 to 1999. He has served in various
executive officer capacities with Reliant Energy since 1986, including Group
Vice President -- Finance and Regulatory Relations of Reliant Energy HL&P from
1993 to 1996.
Mr. Naeve has served as Vice Chairman of Reliant Energy since June 1999 and
as Chief Financial Officer of Reliant Energy since 1997. Between 1997 and 1999,
he served as Executive Vice President and Chief Financial Officer of Reliant
Energy. He has served in various executive officer capacities with Reliant
Energy since 1988, including Vice President -- Strategic Planning and
Administration between 1993 and 1996.
Mr. Perkins has served as President and Chief Operating Officer, Reliant
Energy Wholesale Group, and as President and Chief Operating Officer, Reliant
Energy Power Generation, Inc. since 1998. In 1998, Mr. Perkins served as
President and Chief Operating Officer of Reliant Energy Power Generation Group.
Between 1996 and 1998, Mr. Perkins served as Vice President -- Corporate
Planning and Development. Prior to joining Reliant Energy, he served as Vice
President of Business Development and Corporate Secretary of Coral Energy
Resources, L.P. and Vice President and General Manager of Coral Power, L.L.C.
Between 1994 and 1995, he was Director of Business Development for Tejas Gas
Corporation.
Mr. Kelly has served as Executive Vice President, General Counsel and
Corporate Secretary of Reliant Energy since 1997. Between 1984 and 1997, he
served as Senior Vice President, General Counsel and Corporate Secretary of
Reliant Energy.
Ms. Ricciardello has served as Chief Accounting Officer of Reliant Energy
since June 2000 and as Senior Vice President since June 1999. Between 1999 and
2000, she served as Senior Vice President and Comptroller of Reliant Energy. She
also served as Vice President and Comptroller of Reliant Energy from 1996 to
1999. She has served in various executive officer capacities with Reliant Energy
since 1993.
EXECUTIVE OFFICERS OF THE REGULATED HOLDING COMPANY AND RELIANT RESOURCES
We currently expect that at the time of the Distribution, the executive
officers of the Regulated Holding Company will include the following:
David M. McClanahan -- President and Chief Executive Officer
Scott E. Rozzell -- Executive Vice President and General Counsel
Stephen C. Schaeffer -- Executive Vice President
James S. Brian -- Senior Vice President and Chief Accounting Officer
Other executive officer positions of the Regulated Holding Company have not
been finalized at this time.
We currently expect that at the time of the Offering, the executive
officers of Reliant Resources will include the following:
R. Steve Letbetter -- Chairman, President and Chief Executive Officer
Robert W. Harvey -- Executive Vice President and Group President,
Emerging Businesses
Stephen W. Naeve -- Executive Vice President and Chief Financial Officer
Joe Bob Perkins -- Executive Vice President and Group President,
Wholesale Businesses
Hugh Rice Kelly -- Senior Vice President, General Counsel and Corporate
Secretary
Mary P. Ricciardello -- Senior Vice President and Chief Accounting
Officer
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ITEM 2. PROPERTIES.
CHARACTER OF OWNERSHIP
We and RERC own our principal properties in fee, except for three plants
previously owned, and currently leased, by REMA that were sold and leased back
under long-term leveraged leases, and except for the land on which two plants of
our Wholesale Energy business segment (one in Nevada and one in Texas) are
located. Also, most electric lines and gas mains are located, pursuant to
easements and other rights, on public roads or on land owned by others.
Substantially all of the real estate, electric distribution system
properties, buildings and franchises owned directly by Reliant Energy (excluding
real estate and other properties of subsidiaries of Reliant Energy) are subject
to a lien created under a Mortgage and Deed of Trust dated as of November 1,
1944 (as supplemented, Mortgage) between Reliant Energy and South Texas
Commercial National Bank of Houston (The Chase Manhattan Bank, as Successor
Trustee). The lien of the Mortgage excludes cash, stock in subsidiaries and
certain other assets. Additionally, the properties owned by REMA, as well as the
two previously mentioned plants in Nevada and Texas in our Wholesale Energy
business segment, are subject to liens of creditors of the respective
subsidiaries.
ELECTRIC OPERATIONS
For information regarding the properties of our Electric Operations
business segment, please read "Electric Operations -- Electric Operations
Assets" in Item 1 of this Form 10-K, which information is incorporated herein by
reference.
NATURAL GAS DISTRIBUTION
For information regarding the properties of our Natural Gas Distribution
business segment, please read "Natural Gas Distribution -- Assets" in Item 1 of
this Form 10-K, which information is incorporated herein by reference.
PIPELINES AND GATHERING
For information regarding the properties of our Pipelines and Gathering
business segment, please read "Pipelines and Gathering -- Assets" in Item 1 of
this Form 10-K, which information is incorporated herein by reference.
WHOLESALE ENERGY
For information regarding the properties of our Wholesale Energy business
segment, please read "Wholesale Energy -- Power Generation Operations" in Item 1
of this Form 10-K, which information is incorporated herein by reference.
EUROPEAN ENERGY
For information regarding the properties of our European Energy business
segment, please read "European Energy -- European Power Generation Operations"
in Item 1 of this Form 10-K, which information is incorporated herein by
reference.
OTHER OPERATIONS
For information regarding the properties of our Other Operations business
segment, please read "Other Operations" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.
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ITEM 3. LEGAL PROCEEDINGS.
(A) RELIANT ENERGY.
For a description of certain legal and regulatory proceedings affecting
Reliant Energy, see Notes 4, 14(g), 14(h) and 14(i) to our consolidated
financial statements, which notes are incorporated herein by reference.
(B) RERC CORP.
For a description of certain legal and regulatory proceedings affecting
RERC, see Notes 9(c) and 9(d) to RERC's consolidated financial statements, which
notes are incorporated herein by reference.
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of Reliant Energy's security holders
during the fourth quarter of the fiscal year ended December 31, 2000.
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42
PART II
ITEM 5. MARKET FOR RELIANT ENERGY'S AND RERC CORP.'S COMMON EQUITY AND RELATED
STOCKHOLDER MATTERS.
As of March 12, 2001, Reliant Energy's common stock was held of record by
approximately 75,089 shareholders. Reliant Energy's common stock is listed on
the New York and Chicago Stock Exchanges and is traded under the symbol "REI."
All of the 1,000 outstanding shares of RERC Corp.'s common stock are held by
Reliant Energy.
The following table sets forth the high and low sales prices of Reliant
Energy's common stock on the New York Stock Exchange composite tape during the
periods indicated, as reported by Bloomberg, and the dividends declared for
these periods. Dividend payout was $1.50 per share in both 1999 and 2000. The
dividend declared during the fourth quarter of 2000 was paid in March 2001.
MARKET PRICE DIVIDEND
--------------- DECLARED
HIGH LOW PER SHARE
------ ------ ---------
1999
First Quarter............................................. $0.375
January 6............................................... $32.25
March 31................................................ $26.06
Second Quarter............................................ $0.375
April 14................................................ $25.50
May 25.................................................. $31.69
Third Quarter............................................. $0.375
September 3............................................. $28.63
September 28............................................ $26.31
Fourth Quarter............................................ $0.375
October 4............................................... $28.44
December 31............................................. $22.88
2000
First Quarter............................................. $0.375
March 7................................................. $19.88
March 16................................................ $24.38
Second Quarter............................................ $0.375
April 7................................................. $22.56
June 23................................................. $29.81
Third Quarter............................................. $0.375
July 3.................................................. $29.81
September 29............................................ $46.50
Fourth Quarter............................................ $0.375
October 2............................................... $48.19
December 6.............................................. $38.06
The closing market price of Reliant Energy's common stock on December 31,
2000 was $43.31 per share.
Future dividends will be subject to determination based upon our results of
operations and financial condition, our future business prospects, any
applicable contractual restrictions and other factors that our Board of
Directors considers relevant.
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43
ITEM 6. SELECTED FINANCIAL DATA.
The following table presents selected financial data with respect to our
consolidated financial condition and results of consolidated operations and
should be read in conjunction with our consolidated financial statements and the
related notes in Item 8 of this Form 10-K. In December 2000, our Board of
Directors approved a plan to dispose of our Latin America business segment
through the sale of its assets. Accordingly, we are reporting the results of our
Latin America business segment as discontinued operations for all periods
presented. The selected financial data includes the financial statement effect
of REMA since the May 2000 acquisition, UNA since the October 1999 acquisition
and RERC since the August 1997 acquisition. These acquisitions were accounted
for under the purchase method. Please read Note 3 to our consolidated financial
statements for additional information regarding the REMA and UNA acquisitions
and Note 19 to our consolidated financial statements for additional information
regarding the discontinued operations.
YEAR ENDED DECEMBER 31,
-----------------------------------------------
1996 1997(1) 1998(2) 1999(3) 2000(4)
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues.......................................... $ 4,033 $ 6,786 $11,230 $15,223 $29,339
------- ------- ------- ------- -------
Income (loss) from continuing operations before
extraordinary items and preferred dividends..... $ 408 $ 390 $ (278) $ 1,674 $ 771
(Loss) income from discontinued operations, net of
tax............................................. (3) 31 137 (9) (172)
Loss on disposal of discontinued operations, net
of tax.......................................... -- -- -- -- (159)
Extraordinary items, net of tax................... -- -- -- (183) 7
------- ------- ------- ------- -------
Net income (loss) attributable to common
stockholders.................................... $ 405 $ 421 $ (141) $ 1,482 $ 447
======= ======= ======= ======= =======
Basic earnings (loss) per common share:
Continuing operations before extraordinary
items........................................ $ 1.67 $ 1.54 $ (0.98) $ 5.87 $ 2.71
(Loss) income from discontinued operations, net
of tax....................................... (0.01) 0.12 0.48 (0.03) (0.61)
Loss on disposal of discontinued operations, net
of tax....................................... -- -- -- -- (0.56)
Extraordinary items, net of tax................. -- -- -- (0.64) 0.03
------- ------- ------- ------- -------
Basic earnings (loss) per common share............ $ 1.66 $ 1.66 $ (0.50) $ 5.20 $ 1.57
======= ======= ======= ======= =======
Diluted earnings (loss) per common share:
Continuing operations before extraordinary
items........................................ $ 1.67 $ 1.54 $ (0.98) $ 5.85 $ 2.68
(Loss) income from discontinued operations, net
of tax....................................... (0.01) 0.12 0.48 (0.03) (0.60)
Loss on disposal of discontinued operations, net
of tax....................................... -- -- -- -- (0.55)
Extraordinary items, net of tax................. -- -- -- (0.64) 0.03
------- ------- ------- ------- -------
Diluted earnings (loss) per common share.......... $ 1.66 $ 1.66 $ (0.50) $ 5.18 $ 1.56
======= ======= ======= ======= =======
Cash dividends declared per common share.......... $ 1.50 $ 1.50 $ 1.50 $ 1.50 $ 1.50
Dividend payout ratio from continuing
operations...................................... 90% 97% -- 26% 55%
Return on average common equity................... 10.2% 9.7% (3.1)% 30.8% 8.3%
Ratio of earnings from continuing operations to
fixed charges................................... 2.82 2.42 -- 5.43 2.35
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YEAR ENDED DECEMBER 31,
-----------------------------------------------
1996 1997(1) 1998(2) 1999(3) 2000(4)
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
At year-end:
Book value per common share..................... $ 16.41 $ 17.28 $ 15.16 $ 18.70 $ 19.10
Market price per common share................... $ 22.63 $ 26.75 $ 32.06 $ 22.88 $ 43.31
Market price as a percent of book value......... 138% 155% 211% 122% 227%
Total assets.................................... $12,277 $18,268 $18,967 $26,456 $32,077
Long-term debt obligations, including current
maturities................................... $ 3,280 $ 5,307 $ 7,049 $ 9,223 $ 6,619
Trust preferred securities...................... -- $ 362 $ 342 $ 705 $ 705
Cumulative preferred stock...................... $ 135 $ 10 $ 10 $ 10 $ 10
Capitalization:
Common stock equity.......................... 53% 46% 37% 35% 43%
Cumulative preferred stock................... 2% -- -- -- --
Trust preferred securities................... -- 3% 3% 5% 5%
Long-term debt, including current
maturities................................. 45% 51% 60% 60% 52%
Business acquisitions........................... $ -- $ 1,423 $ 292 $ 1,060 $ 2,103
Capital expenditures............................ 324 328 712 1,166 1,842
- ---------------
(1) 1997 income includes a non-cash, unrealized accounting loss on our indexed
debt securities of $79 million (after-tax), or $0.31 loss per basic and
diluted share. For additional information on the indexed debt securities,
please read Note 8 to our consolidated financial statements.
(2) 1998 income includes a non-cash, unrealized accounting loss on our indexed
debt securities of $764 million (after-tax), or $2.69 loss per basic and
diluted share. For additional information on the indexed debt securities,
please read Note 8 to our consolidated financial statements. Fixed charges
exceeded earnings by $367 million in 1998.
(3) 1999 income includes an aggregate non-cash, unrealized accounting gain on
our indexed debt securities and our Time Warner (now AOL Time Warner)
investment, of $1.2 billion (after-tax), or $4.09 earnings per basic share
and $4.08 earnings per diluted share. For additional information on the
indexed debt securities and AOL Time Warner investment, please read Note 8
to our consolidated financial statements. The extraordinary item in 1999 is
a loss related to an accounting impairment of some generation related
regulatory assets of our Electric Operations business segment. For
additional information, please read Note 4 to our consolidated financial
statements.
(4) 2000 income includes an aggregate non-cash accounting loss on our indexed
debt securities and our AOL Time Warner investment of $67 million
(after-tax), or $0.23 earnings per basic and diluted share. The
extraordinary item in 2000 is a gain related to the early extinguishment of
$272 million of long-term debt. For additional information on the indexed
debt securities and AOL Time Warner investment, please read Note 8 to our
consolidated financial statements.
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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.
The following discussion and analysis should be read in combination with
our consolidated financial statements included in Item 8 of this Form 10-K.
RELIANT ENERGY, INCORPORATED
We are a diversified international energy services and energy delivery
company that provides energy and energy services in North America and Western
Europe. We operate one of the United States' largest electric utilities in terms
of kilowatt-hour (KWh) sales, and our three natural gas distribution divisions
together form one of the United States' largest natural gas distribution
operations in terms of customers served. We invest in the acquisition,
development and operation of international and domestic non-rate regulated power
generation facilities. We own two interstate natural gas pipelines that provide
gas transportation, supply, gathering and storage services, and we also engage
in wholesale energy marketing and trading.
In this section we discuss our results of operations on a consolidated
basis and individually for each of our business segments. We also discuss our
liquidity and capital resources. Our financial reporting segments include
Electric Operations, Natural Gas Distribution, Pipelines and Gathering,
Wholesale Energy, European Energy and Other Operations. For segment reporting
information, please read Notes 1 and 18 to our consolidated financial
statements. For additional information regarding these segments, please read
"Business" in Item 1 of this Form 10-K.
Effective December 1, 2000 (measurement date), our Board of Directors
approved a plan to dispose of our Latin America business segment and sale of its
assets. Accordingly, we are reporting the results of our Latin America business
segment as discontinued operations for all periods presented in our consolidated
financial statements in accordance with Accounting Principles Board Opinion No.
30. For information regarding the disposal of our Latin America business
segment, please read "Our Business -- Discontinued Operations" in Item 1 of this
Form 10-K and Note 19 to our consolidated financial statements.
In 2000, we submitted our business separation plan to the Texas Utility
Commission. We later amended the plan to contemplate the restructuring of our
businesses into two separate publicly traded companies in order to separate our
unregulated businesses from our regulated businesses. In December 2000, the
Business Separation Plan was approved by the Texas Utility Commission, although
as of March 19, 2001 a final order has not been issued. For additional
information regarding the Business Separation Plan, please read "Our
Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our
consolidated financial statements.
On July 27, 2000, we announced our intention to form a company, Reliant
Resources, to own and operate a substantial portion of our unregulated
operations and to offer no more than 20% of the common stock of this company in
an initial public offering. Reliant Energy incorporated Reliant Resources as a
wholly owned subsidiary in August 2000. Effective as of December 31, 2000,
Reliant Energy transferred substantially all of its unregulated operations to
Reliant Resources. We currently expect Reliant Resources will conduct an initial
public offering in 2001.
On May 12, 2000, one of our subsidiaries purchased entities owning electric
power generating assets and development sites located in Pennsylvania, New
Jersey and Maryland having an aggregate net generating capacity of approximately
4,262 MW. With the exception of development entities that were sold to another
Reliant Energy subsidiary in July 2000, the assets of the entities acquired are
held by REMA. The purchase price for the May 2000 transaction was $2.1 billion.
We accounted for the acquisition as a purchase, and accordingly, our results of
operations include the results of operations for REMA only for the period after
the acquisition date. For additional information about this acquisition,
including our accounting treatment of the acquisition, please read Note 3(a) to
our consolidated financial statements.
Effective October 1999, we acquired UNA, a Dutch electric generation
company, for a total purchase price of $1.9 billion based on the October 7, 1999
exchange rate of 2.06 NLG per U.S. dollar. We accounted
40
46
for this acquisition as a purchase. For additional information about this
acquisition, including our accounting treatment of the acquisition, please read
Note 3(b) to our consolidated financial statements.
All dollar amounts in the tables that follow are in millions, except for
per share and operational data.
CONSOLIDATED RESULTS OF OPERATIONS
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1999 2000
------- -------- --------
Revenues.................................................... $11,230 $ 15,223 $ 29,339
Operating Expenses.......................................... (9,950) (13,965) (27,460)
------- -------- --------
Operating Income............................................ 1,280 1,258 1,879
(Loss) Income of Equity Investments......................... (1) (1) 43
Other Income, net........................................... 68 60 83
Gain (Loss) on AOL Time Warner Investment................... -- 2,452 (205)
(Loss) Gain on Indexed Debt Securities...................... (1,176) (629) 102
Interest Expense and Other Charges.......................... (532) (550) (754)
------- -------- --------
(Loss) Income from Continuing Operations Before Income Taxes
and Extraordinary Items................................... (361) 2,590 1,148
Income Tax Benefit (Expense)................................ 83 (916) (377)
Income (Loss) from Discontinued Operations, net of tax of
($52), $17 and $46........................................ 137 (9) (172)
Loss on Disposal of Discontinued Operations, net of tax of
$13....................................................... -- -- (159)
Extraordinary (Loss) Gain, net of tax of $99 and $0......... -- (183) 7
------- -------- --------
Net (Loss) Income Attributable to Common Stockholders..... $ (141) $ 1,482 $ 447
======= ======== ========
Basic (Loss) Earnings Per Share............................. $ (0.50) $ 5.20 $ 1.57
Diluted (Loss) Earnings Per Share........................... $ (0.50) $ 5.18 $ 1.56
2000 Compared to 1999.
Net Earnings. We reported consolidated earnings of $447 million ($1.57 per
basic share) for 2000 compared to $1.482 billion ($5.20 per basic share) for
1999. The reported income for 2000 included the following extraordinary and
unusual items:
- an aggregate after-tax, non-cash accounting loss of $67 million on our
indexed debt securities and our related AOL Time Warner investment,
- an extraordinary gain of $7 million related to the early extinguishment
of $272 million of long-term debt,
- an after-tax loss of $172 million from discontinued operations of our
Latin America business segment, and
- an after-tax loss of $159 million on the disposal of discontinued
operations of our Latin America business segment.
The 1999 results included the following extraordinary and unusual items:
- an aggregate after-tax, non-cash accounting gain of $1.166 billion on our
indexed debt securities and our AOL Time Warner investment,
- an after-tax extraordinary loss of $183 million relating to an accounting
impairment of some generation related regulatory assets of Electric
Operations, and
- an after-tax loss of $9 million from discontinued operations of our Latin
America business segment.
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In 1997, in order to monetize a portion of the cash value of our investment
in Time Warner Inc. (TW) convertible preferred stock (TW Preferred), we issued
22.9 million of unsecured 7% Automatic Common Exchange Securities (ACES) having
an original principal amount of $1.052 billion and maturing July 1, 2000. The
market value of ACES was indexed to the market value of TW Common Stock (TW
Common). On July 6, 1999, we converted our investment in TW Preferred into 45.8
million shares of TW Common. Prior to the conversion, our investment in the TW
Preferred was accounted for under the cost method at a value of $990 million.
Effective on the conversion date, the shares of TW Common were classified as
trading securities under SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), and an unrealized gain was recorded
in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative
appreciation in the fair value of our investment in Time Warner securities. On
the July 1, 2000 maturity date, we tendered 37.9 million shares of TW Common to
fully settle our obligations in connection with our ACES obligation. On
September 21, 1999, we issued approximately 17.2 million of 2.0% Zero-Premium
Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal
amount of $1.0 billion. At maturity the holders of the ZENS will receive in cash
the higher of the original principal amount of the ZENS (subject to adjustment)
or an amount based on the then-current market value of TW Common, or other
securities distributed with respect to TW Common. We used $537 million of the
net proceeds from the offering of the ZENS to purchase 9.2 million additional
shares of TW Common, which are classified as trading securities under SFAS No.
115. Prior to the purchase of additional shares of TW Common on September 21,
1999, we owned approximately 8 million shares of TW Common that were in excess
of the 37.9 million shares needed to economically hedge our ACES obligation.
Prior to January 1, 2001, an increase above $58.25 (subject to some adjustments)
in the market value per share of TW Common resulted in an increase in our
liability for the ZENS. However, as the market value per share of TW Common
declined below $58.25 (subject to some adjustments), the liability for the ZENS
did not decline below the original principal amount. Our investment in TW (now
AOL Time Warner) securities has been held to facilitate our ability to meet our
obligations under the ACES and ZENS.
The following table sets forth summarized financial information regarding
our investment in TW securities and our ACES and ZENS obligations (in millions):
TW
INVESTMENT ACES ZENS
---------- ------------- ------
Balance at December 31, 1997.......................... $ 990 $ 1,174
Loss on indexed debt securities....................... -- 1,176
------- -------
Balance at December 31, 1998.......................... 990 2,350
Issuance of indexed debt securities................... -- -- $1,000
Purchase of TW Common................................. 537 -- --
Loss on indexed debt securities....................... -- 388 241
Gain on TW Common..................................... 2,452 -- --
------- ------- ------
Balance at December 31, 1999.......................... 3,979 2,738 1,241
Loss (Gain) on indexed debt securities................ -- 139 (241)
Loss on TW Common..................................... (205) -- --
Settlement of ACES.................................... (2,877) (2,877) --
------- ------- ------
Balance at December 31, 2000.......................... $ 897 $ -- $1,000
======= ======= ======
For additional information regarding our investment in AOL Time Warner, our
indexed debt securities and the effect of adoption of SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended, on January 1,
2001 on our ZENS obligation, please read Note 8 to our consolidated financial
statements.
In 1999 in connection with the implementation of the Legislation, we
evaluated the recovery of our generation related regulatory assets and
liabilities. We determined that a pre-tax accounting loss of $282 million
existed because we believed only the economic value of our generation related
regulatory assets (as defined by the Legislation) would be recovered. Therefore,
we recorded a $183 million after-tax
42
48
extraordinary loss in the fourth quarter of 1999. If events were to occur that
made the recovery of some of the remaining generation related regulatory assets
no longer probable, we would write off the remaining balance of such assets as a
non-cash charge against earnings. For information regarding the $183 million
extraordinary loss, please read "-- Certain Factors Affecting Our Future
Earnings -- Competitive, Regulatory and Other Factors Affecting Our Electric
Operations -- Other Regulatory Factors" and Note 4(a) to our consolidated
financial statements.
In the fourth quarter of 2000, prior to the measurement date, our Latin
America business segment sold its investments in El Salvador and a portion of
its investments in Colombia for an aggregate $303 million in after-tax proceeds.
The measurement date is the date we began reporting our Latin America business
segment as discontinued operations. We recorded a $127 million after-tax loss in
connection with the sale of these investments which was included in our
after-tax loss from discontinued operations of $172 million (net of an income
tax benefit of $46 million) in 2000. Subsequent to the measurement date, we sold
our investments in Brazil and our remaining investments in Colombia for an
aggregate $487 million in after-tax proceeds. We recorded a $114 million
after-tax loss in connection with the sale of these investments which was
included in our after-tax loss on disposal of discontinued operations of $159
million (net of income taxes of $13 million) in 2000. Our Latin America business
segment's remaining investments include a wholly owned cogeneration facility and
a distribution company, both located in Argentina, and a minority interest in a
coke calcining plant in India. We anticipate that the sale of the remainder of
these assets will be completed by December 2001. The total provision for the
disposal of discontinued operations of $159 million includes a $5 million
reserve for anticipated operating losses through the completion of the sales,
which includes $4 million of operating losses from the measurement date through
December 31, 2000.
Our consolidated net income, after adjusting for extraordinary and unusual
items (as described above) in both years, was $838 million ($2.94 per basic
share) for 2000 compared to $508 million ($1.78 per basic share) for 1999. The
$330 million increase was primarily due to increased earnings from our Wholesale
Energy and Electric Operations segments and additional earnings from our
European Energy segment, which was established in the fourth quarter of 1999.
The increase was partially offset by lower earnings in 2000 compared to 1999
from our Natural Gas Distribution segment and increased losses from our Other
Operations segment.
Operating Income. For an explanation of changes in our operating income,
please read the discussion below of operating income (loss) by segment.
Income (Loss) of Equity Investments. Our Wholesale Energy segment reported
income from equity investments in 2000 of $43 million compared to equity losses
of $1 million in 1999. The equity income in 2000 primarily resulted from an
investment in an electric generation plant in Boulder City, Nevada. The plant
became operational in May 2000.
Other Income, net. Other income, net was $60 million and $83 million in
1999 and 2000, respectively. The increase in other income in 2000 of $23 million
compared to 1999 was primarily due to the following items:
- an increase in interest income of $57 million primarily related to income
tax refunds received in 2000 and margin deposits on energy trading
activities,
- a pre-tax gain of $18 million in 2000 on the sale of our interest in one
of our development stage electric generation projects,
- partially offset by an impairment loss of $27 million on marketable
equity securities classified as "available-for-sale" in 2000,
distributions of $9 million from venture capital investments in
marketable securities classified as "trading" in 1999 and a decline of
$19 million in dividend income from our AOL Time Warner investment. For
additional information, please read Note 8 to our consolidated financial
statements.
During 2000, we incurred a pre-tax impairment loss of $27 million on
marketable equity securities classified as "available-for-sale" by Other
Operations. Management's determination to recognize this impairment resulted
from a combination of events occurring in 2000 related to this investment. Such
events
43
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affecting the investment included changes occurring in the investment's senior
management, announcement of significant restructuring charges and related
downsizing for the entity, reduced earnings estimates for this entity by
brokerage analysts and the bankruptcy of a competitor of the entity in the first
quarter of 2000. These events coupled with the stock market value of our
investment in these securities continuing to be below our cost basis, caused
management to believe the decline in fair value to be other than temporary. For
additional discussion of this investment, please read Note 2(l) to our
consolidated financial statements.
Interest Expense and Other Charges. In 1999 and 2000, interest expense and
other charges were $550 million and $754 million, respectively. Increased
interest expense and other charges in 2000 compared to 1999 were primarily due
to increased levels of short-term borrowings. These increases were associated in
part with borrowings to fund the purchase obligation for the acquisition of UNA
in the fourth quarter of 1999 and the first quarter of 2000, the acquisition of
the REMA entities in the second quarter of 2000, other acquisitions, capital
expenditures and increased margin deposits on energy trading activities.
Income Tax Expense. The effective tax rate for 1999 and 2000 was 35.4% and
32.8%, respectively. After adjusting for the unrealized accounting gains and
losses on our investment in AOL Time Warner and indexed debt securities, the
adjusted effective tax rate for 1999 and 2000 was 33.9% and 33.0%, respectively.
The decrease in the effective tax rate in 2000 compared to 1999 was primarily
due to a Dutch tax holiday. In 2000 and prior years, under Dutch corporate
income tax laws, the earnings of UNA were subject to a zero percent Dutch
corporate income tax rate as a result of the Dutch tax holiday related to the
Dutch electric industry. In 2002, all of European Energy's earnings in the
Netherlands will be subject to the standard Dutch corporate income tax rate,
which currently is 35%.
1999 Compared to 1998.
Net Earnings. We reported consolidated earnings in 1999 of $1.482 billion
($5.20 per basic share) compared to a consolidated net loss of $141 million
($0.50 per share) for 1998. The 1999 results included the extraordinary and
unusual items discussed above under "-- 2000 Compared to 1999 -- Net Earnings."
The reported loss for 1998 included a $764 million (after-tax) non-cash,
unrealized accounting loss on indexed debt securities (as discussed above) and
after-tax income from discontinued operations of $137 million.
Our consolidated net income, after adjusting for extraordinary and unusual
items (as discussed above) in both years, was $508 million ($1.78 per share) for
1999 compared to $486 million ($1.71 per share) for 1998. The $22 million
increase was primarily due to earnings of our European Energy segment, which
acquired UNA in the fourth quarter of 1999, and lower losses from our Other
Operations segment. These improvements were partially offset by lower earnings
in 1999 for our Natural Gas Distribution, Pipelines and Gathering, and Wholesale
Energy segments.
Operating Income. For an explanation of changes in our operating income,
please read the discussion below of operating income (loss) by business segment.
(Loss) Income of Equity Investments. Our Wholesale Energy segment reported
a loss from equity investments of $1 million in both 1998 and 1999.
Other Income, net. Other income, net was $68 million and $60 million in
1998 and 1999, respectively. The decrease in other income in 1999 of $8 million
compared to 1998 was primarily due to a decline in dividend income from our AOL
Time Warner investment of $15 million from 1998 (please read Note 8 to our
consolidated financial statements), partially offset by distributions of $9
million from a venture capital investment of marketable securities classified as
"trading" in 1999, as discussed above.
Interest Expense and Other Charges. In 1998 and 1999, interest expense and
other charges were $532 million and $550 million, respectively. Increased
interest expense and other charges in 1999 compared to 1998 were primarily due
to higher levels of short-term borrowings, long-term debt and trust preferred
securities. These increases were associated in part with the acquisition of UNA
in the fourth quarter of 1999, our additional investment in AOL Time Warner in
1999, other acquisitions of businesses and capital expenditures. The increase in
1999 was partially offset by a decrease in the average interest rate on our
long-term debt.
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Income Tax Expense. The effective tax rate for 1998 and 1999 was 22.9% and
35.4%, respectively. After adjusting for the unrealized accounting gains and
losses on our investment in AOL Time Warner and indexed debt securities, the
adjusted effective tax rate for 1998 and 1999 was 40.4% and 33.9%, respectively.
The decrease in effective tax rate in 1999 compared to 1998 was primarily due to
the discontinuance of Statement of Financial Accounting Standards (SFAS) No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), for
the generation operations of our Electric Operations segment. For information
regarding the discontinuance of SFAS No. 71 to the generation operations of our
Electric Operations segment, see Note 4(a) to our consolidated financial
statements.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income (loss) for each of our
business segments for 1998, 1999 and 2000 (in millions). Some amounts from the
previous years have been reclassified to conform to the 2000 presentation of the
financial statements. These reclassifications do not affect consolidated
earnings.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
(IN MILLIONS)
Electric Operations........................................ $1,002 $ 981 $1,230
Natural Gas Distribution................................... 167 158 113
Pipelines and Gathering.................................... 146 131 137
Wholesale Energy........................................... 42 27 482
European Energy............................................ -- 32 89
Other Operations........................................... (77) (71) (172)
------ ------ ------
Total Consolidated............................... $1,280 $1,258 $1,879
====== ====== ======
ELECTRIC OPERATIONS
Our Electric Operations segment conducts operations through an
unincorporated division of Reliant Energy under the name "Reliant Energy HL&P."
This segment generates, purchases, transmits and distributes electricity to
approximately 1.7 million customers in a 5,000 square mile area on the Texas
Gulf Coast, including Houston.
In 1999, the Texas legislature adopted the Legislation, which substantially
amended the regulatory structure governing electric utilities in Texas in order
to allow retail competition beginning on January 1, 2002. Prior to adoption of
the Legislation, our Electric Operations segment's earnings were capped at an
agreed overall rate of return formula on a calendar year basis as part of the
transition to competition plan (Transition Plan) approved by the Texas Utility
Commission effective January 1, 1998. As a result of the Transition Plan, any
earnings prior to the Legislation above the maximum allowed return cap on
invested capital were offset by additional depreciation of our Electric
Operations segment's electric generation assets. For more information regarding
the Legislation, please read "Business -- Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1 of
this Form 10-K and Note 4(a) to our consolidated financial statements. For more
information regarding the Transition Plan, please read Notes 2(g) and 4(c) to
our consolidated financial statements.
For a discussion of the factors that may affect the future results of
operations of our Electric Operations segment, please read "-- Certain Factors
Affecting Our Future Earnings -- Competitive, Regulatory and Other Factors
Affecting Our Electric Operations."
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The following table provides summary data regarding the results of
operations of our Electric Operations segment for 1998, 1999 and 2000 (in
millions, except electric sales data):
YEAR ENDED DECEMBER 31,
---------------------------
1998 1999 2000
------- ------- -------
Operating Revenues:
Base revenues(1)...................................... $ 2,969 $ 2,968 $ 3,141
Reconcilable fuel revenues(2)......................... 1,381 1,515 2,353
------- ------- -------
Total operating revenues...................... 4,350 4,483 5,494
------- ------- -------
Operating Expenses:
Fuel and purchased power.............................. 1,455 1,569 2,412
Operation and maintenance............................. 890 916 963
Depreciation and amortization......................... 663 667 507
Other operating expenses.............................. 340 350 382
------- ------- -------
Total operating expenses...................... 3,348 3,502 4,264
------- ------- -------
Operating Income........................................ $ 1,002 $ 981 $ 1,230
======= ======= =======
Electric Sales (gigawatt-hours (GWh)):
Residential........................................... 21,216 21,144 22,727
Commercial............................................ 16,388 16,616 17,594
Industrial -- Firm.................................... 26,542 26,020 27,707
Industrial -- Interruptible........................... 5,115 5,460 5,542
Other................................................. 3,472 2,867 1,724
------- ------- -------
Total......................................... 72,733 72,107 75,294
======= ======= =======
- ---------------
(1) Includes miscellaneous revenues, non-reconcilable fuel revenues and
purchased power-related revenues.
(2) Includes revenues collected through a fixed fuel factor and surcharges net
of adjustments for over/under recovery of fuel.
2000 Compared to 1999. Our Electric Operations segment operating income
for 2000 increased $249 million compared to 1999. The increase was primarily due
to decreased depreciation and amortization expense, strong customer growth and
warmer weather, partially offset by increased operation and maintenance expenses
and other taxes.
Base revenues increased $173 million in 2000 due to continued customer
growth and demand growth from the effects of weather as compared to 1999. Growth
in usage per customer and number of customers contributed $132 million of the
increase in base revenues in 2000.
Our 55% increase in reconcilable fuel revenue in 2000 resulted primarily
from increased fuel costs as discussed below. The Texas Utility Commission
provides for recovery of some fuel and purchased power costs through a fixed
fuel factor included in electric rates. Revenues collected through this factor
are adjusted monthly to equal expenses; therefore, these revenues and expenses
have no effect on earnings unless fuel costs are determined not to be
recoverable. The adjusted over/under recovery of fuel costs is recorded on our
consolidated balance sheets as other liabilities or regulatory assets,
respectively. For information regarding the effect of the Legislation on fuel
recovery beginning in 2002, please read "Business -- Regulation -- State and
Local Regulations -- Texas -- Electric Operations -- The Legislation" in Item 1
of this Form 10-K and Note 4 to our consolidated financial statements for
information regarding Reliant Energy HL&P fuel filings.
Fuel and purchased power expenses in 2000 increased by $843 million, or
54%, over 1999 expenses. The increase is primarily the result of higher
reconcilable costs for natural gas ($2.47 and $3.98 per MMBtu in 1999 and 2000,
respectively), higher costs for purchased power ($26.46 and $44.26 per MWh in
1999 and
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2000, respectively) and higher sales due to customer growth and increased
demand, which led to increased production.
Operation, maintenance and other operating expenses increased $79 million
in 2000 compared to 1999 primarily due to the following items:
- a $25 million increase due to transmission expenses resulting from the
wholesale rates established by ERCOT,
- a $22 million increase in state franchise taxes and municipal franchise
fees due to increased earnings and cash receipts,
- a $24 million assessment for the 1999 and 2000 System Benefit Fund, which
was established by the Legislation to insure that public schools were not
impacted by the loss of taxes related to the lower property values of
generation assets, substantially offset by a decrease in property taxes
of $21 million, and
- a $22 million increase in other operation and maintenance expense.
Depreciation and amortization expense decreased $160 million primarily due
to our discontinuance of recording additional depreciation and redirected
depreciation pursuant to the Transition Plan, the extension of electric
generation assets' depreciable lives, fully amortizing some investments in
lignite reserves associated with a cancelled generation station and ceasing
amortization of regulatory assets pursuant to the Legislation. For additional
information regarding items that affect depreciation and amortization expense of
Electric Operations pursuant to the Legislation and the Transition Plan, please
read Notes 2(g) and 4(a) to our consolidated financial statements.
1999 Compared to 1998. Electric Operations' operating income for the year
ended December 31, 1999 was $981 million compared to $1,002 million for the same
period in 1998. The $21 million decrease was primarily due to the effects of
milder weather and additional base rate credits provided under the Transition
Plan, partially offset by continued strong customer growth.
Electric Operations' base revenues were $2,968 million for 1999, a decrease
of $1 million from 1998. The effects of milder weather in 1999 compared to 1998
and additional base rate credits in 1999 were offset by continued strong
customer growth and increased usage per customer.
Electric Operations' fuel and purchased power expenses in 1999 increased by
$114 million, or 8%, over 1998 expenses. The increase is a result of higher
costs for natural gas ($2.18 and $2.47 per MMbtu in 1998 and 1999, respectively)
and higher costs for lignite ($1.19 and $1.42 per MMbtu in 1998 and 1999,
respectively). The 1998 fuel costs include a $12 million charge to
non-reconcilable fuel due to some fuel costs being determined not to be
recoverable.
Operation, maintenance and other operating expenses increased $36 million
in 1999 compared to 1998, including $38 million due to transmission tariffs
within ERCOT. A portion of these transmission expenses was offset by an increase
of $28 million in transmission tariff revenue. State franchise taxes increased
$13 million in 1999 compared to 1998.
NATURAL GAS DISTRIBUTION
Natural Gas Distribution's operations consist of intrastate natural gas
sales to, and natural gas transportation for, residential, commercial and
industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma
and Texas and some non-rate regulated retail marketing of natural gas.
For a discussion of the factors that may affect future results of
operations of our Natural Gas Distribution segment, please read "-- Certain
Factors Affecting Our Future Earnings -- Competitive and Other Factors Affecting
RERC Operations -- Natural Gas Distribution."
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The following table provides summary data regarding the results of
operations of Natural Gas Distribution for 1998, 1999 and 2000 (in millions,
except throughput data):
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
Operating Revenues......................................... $2,426 $2,788 $4,412
Operating Expenses:
Natural gas.............................................. 1,655 1,936 3,503
Operation and maintenance................................ 378 470 553
Depreciation and amortization............................ 131 137 145
Other operating expenses................................. 95 87 98
------ ------ ------
Total operating expenses......................... 2,259 2,630 4,299
------ ------ ------
Operating Income........................................... $ 167 $ 158 $ 113
====== ====== ======
Throughput Data (in billion cubic feet (Bcf)):
Residential and commercial sales......................... 286 286 318
Industrial sales......................................... 56 53 55
Transportation........................................... 44 47 50
Retail................................................... 347 400 431
------ ------ ------
Total Throughput................................. 733 786 854
====== ====== ======
2000 Compared to 1999. Our Natural Gas Distribution segment operating
income decreased $45 million in 2000 from 1999. Increases in revenues and
natural gas expenses were due primarily to the increase in the price of natural
gas. In addition, operating revenues increased $6 million related to gains from
the effect of a financial hedge of our Natural Gas Distribution segment's
earnings against unseasonably warm weather during peak heating months. Slightly
increased operating margins (revenues less fuel costs) in 2000 were offset by
higher operating expenses and higher depreciation expense in 2000. Operation and
maintenance expenses increased in 2000 primarily due to the following items:
- costs incurred in connection with some non-rate regulated retail natural
gas business activities outside our established market areas, which have
been discontinued,
- additional provisions against receivable balances resulting from the
implementation of a new billing system for Arkla and
- increased employee benefit costs relating to an updated actuarial
valuation of employee benefit plans.
Generally, our utility operations of the Natural Gas Distribution segment
are allowed to flow through the costs of natural gas to our customers through
purchased gas adjustment provisions in rates pursuant to regulations of the
states in which they operate. Differences between actual gas costs and the
amount collected from customers are deferred on the balance sheet so that there
is no impact on operating income.
1999 Compared to 1998. Our Natural Gas Distribution segment operating
income decreased $9 million in 1999 compared to 1998 primarily due to increased
operating expenses, partially offset by slightly improved operating margins in
1999. Operating expenses increased primarily due to increased employee benefit
costs and costs associated with the implementation of an enterprise-wide
information system.
PIPELINES AND GATHERING
Our Pipelines and Gathering segment operates two interstate natural gas
pipelines, as well as provides gathering and pipeline services.
For a discussion of the factors that may affect future results of
operations of our Pipelines and Gathering segment, please read "-- Certain
Factors Affecting Our Future Earnings -- Competitive and Other Factors Affecting
RERC Operations -- Pipelines and Gathering."
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54
The following table provides summary data regarding the results of
operations of our Pipelines and Gathering segment for 1998, 1999 and 2000 (in
millions, except throughput data):
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
Operating Revenues......................................... $ 346 $ 331 $ 384
Operating Expenses:
Natural gas.............................................. 52 41 76
Operation and maintenance................................ 85 91 100
Depreciation and amortization............................ 48 53 56
Other operating expenses................................. 15 15 15
------ ------ ------
Total operating expenses......................... 200 200 247
------ ------ ------
Operating Income........................................... $ 146 $ 131 $ 137
====== ====== ======
Throughput Data (Bcf):
Natural gas sales........................................ 16 15 14
Transportation........................................... 825 836 845
Gathering................................................ 237 270 288
Elimination(1)........................................... (15) (14) (12)
------ ------ ------
Total Throughput................................. 1,063 1,107 1,135
====== ====== ======
- ---------------
(1) Elimination of volumes both transported and sold.
2000 Compared to 1999. Our Pipelines and Gathering segment's operating
income for 2000 increased $6 million, primarily due to increased gas gathering
and processing revenues. Natural gas expense increased $35 million in 2000,
primarily due to the increased cost of natural gas per unit. Operation and
maintenance expense increased $9 million in 2000, primarily due to the
implementation of various projects throughout the year.
1999 Compared to 1998. Our Pipelines and Gathering segment's operating
income for 1999 decreased $15 million, primarily due to the settlement of a
dispute related to some gas purchase contracts that resulted in the recognition
of $6 million of revenues in 1998, a reduction in depreciation and amortization
in 1998 of $5 million related to a rate case settlement and an increase in
operating expenses in 1999, primarily due to employee benefit expenses.
Operating revenue decreased by $15 million in 1999, primarily due to the
settlement of outstanding gas purchase contract litigation in 1998 as discussed
above. Natural gas expense decreased $11 million in 1999, primarily due to
expiration of gas supply contracts. Operation and maintenance expense increased
$6 million in 1999, primarily due to increases in employee benefit expenses.
Depreciation and amortization expense increased $5 million in 1999 due to a rate
settlement recorded in 1998 as discussed above. The rate settlement, effective
January 1998, provided for a $5 million reduction in depreciation rates
retroactive to July 1996.
During 1998 and 1999, our Pipelines and Gathering segment's largest
unaffiliated customer was a natural gas utility that serves the greater St.
Louis metropolitan area in Illinois and Missouri. Revenues from this customer
were generated pursuant to several long-term firm storage and transportation
agreements that begin to expire at various dates beginning October 2001 through
May 2002. We are currently negotiating the terms and conditions of a renewal of
these agreements with the unaffiliated customer.
During 2000, we obtained regulatory approval and REGT renewed various
contracts for firm transportation and storage with Arkla. These renewals
extended the term of service to 2005 in Arkla's market areas.
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WHOLESALE ENERGY
Our Wholesale Energy segment includes our non-rate regulated power
generation operations in the United States and our wholesale energy trading,
marketing, power origination and risk management operations in North America.
As of December 31, 2000, our Wholesale Energy segment owned or leased
electric power generation facilities with an aggregate net generating capacity
of 9,231 MW in the United States. Our Wholesale Energy segment acquired its
first power generation facilities in April 1998, and has increased its aggregate
net generating capacity since then through a combination of acquisitions,
contractual agreements and the development of new generating projects. As of
December 31, 2000, we had 2,766 MW of additional net generating capacity under
construction. For additional information regarding the acquisition of our Mid-
Atlantic generating assets completed in May 2000, including the accounting
treatment of this acquisition, please read Note 3(a) to our consolidated
financial statements.
For a discussion of the factors that may affect the future results of
operations of our Wholesale Energy segment, please read "-- Certain Factors
Affecting Our Future Earnings -- Competitive, Regulatory and Other Factors
Affecting Our Wholesale Energy Operations."
The following table provides summary data regarding the results of
operations of our Wholesale Energy segment for 1998, 1999 and 2000 (in millions,
except operations data).
YEAR ENDED DECEMBER 31,
-------------------------
1998 1999 2000
------ ------ -------
Operating Revenues........................................ $4,416 $7,912 $19,234
Operating Expenses:
Fuel and cost of gas sold............................... 2,421 3,975 10,402
Purchased power......................................... 1,829 3,729 7,825
Operation and maintenance............................... 106 154 403
Depreciation and amortization........................... 14 21 109
Other operating expenses................................ 4 6 13
------ ------ -------
Total Operating Expenses........................ 4,374 7,885 18,752
------ ------ -------
Operating Income.......................................... $ 42 $ 27 $ 482
====== ====== =======
Operations Data:
Net Generating Capacity (MW)............................ 3,800 4,469 9,231
Electricity Wholesale Power Sales (MMWh)................ 65 112 202
Natural Gas Sales (Bcf)................................. 1,163 1,820 2,509
2000 Compared to 1999. Our Wholesale Energy segment's operating income
increased $455 million for 2000 compared to 1999. The increase was primarily due
to increased energy sales volumes, higher prices for energy and ancillary
services, and improved operating results from trading and marketing activities,
as well as expansion of our Wholesale Energy segment's generation operations
into regions other than the Western United States, including the Mid-Atlantic
United States (Pennsylvania, New Jersey and Maryland), Florida and Texas.
Our Wholesale Energy segment's operating revenues increased $11.3 billion
(143%) for 2000 compared to 1999. The increase was primarily due to an increase
in prices and volumes for both gas and power sales in 2000 as compared to 1999.
Our fuel and cost of gas sold and purchased power costs increased $6.4 billion
and $4.1 billion, respectively, in 2000 compared to 1999. The increase in fuel
and cost of gas sold was primarily due to an increase in gas volumes purchased
and to increases in plant output and in the price of gas. The increase in
purchased power cost was primarily due to a higher average cost of power and
higher power volumes purchased. Operation and maintenance expenses increased
$249 million in 2000 compared to 1999. This increase was primarily due to costs
associated with the maintenance of facilities acquired or placed into commercial
operation during the period, lease expense associated with the Mid-Atlantic
generating facilities sale/leaseback transactions, higher run rates at existing
facilities, increased costs associated with developing
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new power generation projects and higher staffing levels to support increased
sales and expanded trading and marketing efforts. Depreciation and amortization
expense for 2000 increased $88 million as compared to 1999, primarily as a
result of our acquisition of the Mid-Atlantic generating facilities and other
generating facilities in 2000.
Our Wholesale Energy segment's operations in California have been affected
by the crisis conditions of California's wholesale market, most significantly
the financial distress of two of California's public utilities and the
subsequent downgrading of those utilities' credit ratings and defaults on
payments for wholesale power purchased in the fourth quarter of 2000. The
California Legislature has passed emergency legislation appropriating funds to
be used by the CDWR for the purchase of wholesale electricity, but these funds
have been used to pay only for some of the electricity currently needed by the
utilities' customers. We have not been paid for much of the power we sold in
November and December 2000 through the Cal PX and to the Cal ISO. In the fourth
quarter of 2000, we recorded a pre-tax provision of $39 million against
receivable balances related to energy sales in the California market. For
additional information regarding the uncertainties in the California wholesale
energy market, please read "Wholesale Energy -- Power Generation
Operations -- Southwest Region," "Regulation -- State and Local
Regulations -- California" in Item 1 of this Form 10-K, "-- Certain Factors
Affecting Our Future Earnings -- Competitive, Regulatory and Other Factors
Affecting Our Wholesale Energy Operations -- California" as well as Notes 14(g)
and 14(h) to our consolidated financial statements.
1999 Compared to 1998. Our Wholesale Energy segment reported operating
income of $27 million in 1999 compared to $42 million in 1998. The $15 million
decrease was due primarily to a decline in market prices for electricity in the
California market caused by milder than normal weather and increased
hydroelectric generation sold by competitors into the California market. This
decline more than offset significant increases in operating income of our
trading and marketing operations in 1999. The increases in trading and marketing
operating income resulted primarily from increases in volumes of gas, power and
heating oil trading and slightly higher margins (revenue less cost of power
sold) on power trading.
Operating revenues were $7.9 billion in 1999, a 79% increase from 1998
revenues of $4.4 billion. The increase in revenues was primarily due to
increased trading volumes for power, gas and heating oil. Higher sales prices
for both power and gas also contributed to increased revenues.
Fuel and cost of gas sold and purchased power costs increased $1.6 billion
and $1.9 billion, respectively, in 1999 compared to 1998. These increases were
primarily due to the corresponding increase in trading sales volumes. An
increase in power and gas prices also contributed to the increase in costs.
Operation and maintenance expenses in 1999 increased $48 million compared to
1998. The increase was primarily due to costs associated with the maintenance of
the assets in California, which we acquired in April and July 1998. Depreciation
and amortization in 1999 increased $7 million from 1998 due primarily to a full
year of depreciation and amortization for our California operations as well as
additional assets placed into operation during 1999.
EUROPEAN ENERGY
Our European Energy segment includes the operations of UNA and its
subsidiaries and our European trading, marketing and risk management operations.
We created this segment in the fourth quarter of 1999 with the acquisition of
UNA and the formation of our European trading, marketing and risk management
operations. Our European Energy segment generates and sells power from its
generation facilities in the Netherlands and participates in the emerging
wholesale energy trading and marketing industry in Northwest Europe.
Effective October 7, 1999, we acquired UNA, for a net purchase price of
$1.9 billion. From October 1, 1999, our operating results include the results of
operations of UNA. The impact of UNA's results of operations from October 1
through October 7, 1999 was immaterial to our consolidated results of
operations. For additional information regarding the acquisition of UNA, please
read Note 3(b) to our consolidated financial statements.
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In connection with our evaluation of the acquisition of UNA, we also began
to assess and formulate an employee severance plan to be undertaken as soon as
reasonably possible post-acquisition. The intent of this plan was to make UNA
competitive in the Dutch electricity market when it became deregulated on
January 1, 2001. This plan was finalized, approved and completed in September
2000. At that time, we recorded the severance liability as a purchase price
adjustment in the amount of $19 million.
UNA and the other major Dutch generators historically have operated under
an agreement, which is referred to as the "Protocol," pursuant to which the
generators provided capacity and energy to distributors for a total combined
payment of NLG 3.4 billion ($1.5 billion, based on the December 31, 2000
exchange rate of 2.34 NLG per U.S. dollar), plus compensation for actual fuel
costs over the period from 1997 through 2000. Effective January 1, 2001, these
agreements expired in all material aspects.
Beginning January 1, 2001, the Dutch wholesale electric market was
completely opened to competition and as a result, we expect a decline in power
prices. Consistent with our expectations at the time we made the acquisition, we
anticipate that UNA will experience a significant decline in revenues in 2001
attributable to the deregulation of the market and termination of the Protocol.
For additional information on these and other factors that may affect the future
results of operations of our European Energy segment, please read "-- Certain
Factors Affecting Our Future Earnings -- Competitive, Regulatory and Other
Factors Affecting Our European Energy Operations."
The following table provides summary data for the results of operations of
our European Energy segment for the three months ended December 31, 1999 and the
year ended December 31, 2000 (in millions, except electric sales data):
THREE MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
1999 2000
------------------ ------------
Operating Revenues..................................... $ 153 $ 579
Operating Expenses:
Fuel and purchased power............................. 68 294
Operation and maintenance............................ 32 121
Depreciation and amortization........................ 21 75
------ -------
Total Operating Expenses..................... 121 490
------ -------
Operating Income....................................... $ 32 $ 89
====== =======
Electric Sales (GWh)................................... 2,846 11,659
For the year ended December 31, 2000, our European Energy segment reported
operating income of $89 million. We reported operating income of $32 million for
the three months ended December 31, 1999.
For information regarding foreign currency matters, please read Note 5 to
our consolidated financial statements and "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this Form 10-K.
OTHER OPERATIONS
Our Other Operations segment includes the operations of our unregulated
retail electric business, a communications business offering enhanced data,
voice and other services to customers in Texas, an eBusiness group,
non-operating investments, certain real estate holdings and unallocated
corporate costs.
Other Operations had an operating loss of $172 million for 2000 compared to
a $71 million operating loss for 1999. This increased loss was primarily due to
increased expenses incurred in preparing for retail competition in Texas
beginning in January 2002 and eBusiness and communications start-up expenses. In
addition, in 2000 we made a contribution to a charitable foundation and incurred
expenses associated with acquiring the naming rights for the new football
stadium for the Houston Texans, the National Football League's newest franchise,
and the entertainment and convention facilities included in the stadium complex.
For additional information about the naming rights, please read Note 14(e) to
our consolidated financial statements.
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Other Operations had an operating loss of $71 million for 1999 compared to
a $77 million operating loss for 1998. The decreased loss was primarily due to
decreased state franchise taxes partially offset by increased general insurance
liability and information system expenses.
CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS
Our earnings for the past three years are not necessarily indicative of our
future earnings and results. The level of our future earnings depends on
numerous factors including:
- state and federal legislative, as well as international regulatory
developments, including deregulation, re-regulation and restructuring of
the electric utility industry and changes in or application of
environmental and other laws and regulations to which we are subject,
- the timing of the implementation of our Business Separation Plan,
- industrial, commercial and residential growth in our service territories,
- our pursuit of potential business strategies, including acquisitions or
dispositions of assets or the development of additional power generation
facilities,
- state, federal and other rate regulations in the United States and in
foreign countries in which we operate or into which we might expand our
operations,
- the timing and extent of changes in commodity prices and interest rates,
- weather variations and other natural phenomena,
- our ability to cost-effectively finance and refinance,
- the determination of the amount of our Texas generating assets' stranded
costs and the recovery of these costs,
- the ability to consummate and the timing of the consummation of
acquisitions and dispositions,
- the performance of our generation projects undertaken,
- the successful operation of deregulating power markets, including the
resolution of the crisis in the California market, and
- risks incidental to our overseas operations, including the effects of
fluctuations in foreign currency exchange rates.
In order to adapt to the increasingly competitive environment, we continue
to evaluate a wide array of potential business strategies, including business
combinations or acquisitions involving other utility or non-utility businesses
or properties, dispositions of currently owned businesses, as well as developing
new generation projects, products, services and customer strategies.
BUSINESS SEPARATION AND RESTRUCTURING
In anticipation of electric deregulation in Texas, and pursuant to the
Legislation, we submitted a business separation plan in January 2000 to the
Texas Utility Commission. Pursuant to the Business Separation Plan, we will
restructure our businesses into two separate publicly traded companies in order
to separate our unregulated businesses from our rate-regulated businesses.
Reliant Resources holds substantially all of our unregulated businesses. We
expect Reliant Resources will conduct the Offering in 2001. Also, we anticipate
that the Regulated Holding Company will conduct the Distribution within 12
months of the completion of the Offering, subject to receipt of a favorable tax
ruling and other regulatory approvals. For additional information regarding the
Business Separation Plan and the Restructuring, please read "Business -- Our
Business -- Restructuring" in Item 1 of this Form 10-K and Note 4(b) to our
consolidated financial statements.
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We have sought a ruling from the Internal Revenue Service that the
Distribution will be tax-free to the Regulated Holding Company and its
shareholders. At this time, we do not have a ruling from the Internal Revenue
Service regarding the tax treatment of the Distribution. If we do not obtain a
favorable tax ruling, the Distribution is not likely to be made in the expected
time frame or, perhaps, at all. In order for the Distribution to be tax-free,
various requirements must be met, including ownership by its parent of at least
80% of all classes of Reliant Resources' outstanding capital stock at the time
of the Distribution.
Additionally, in connection with the Distribution, Reliant Energy plans to
restructure its remaining businesses to achieve a public utility holding company
structure and to register the Regulated Holding Company as a public utility
holding company under the 1935 Act. Creation of the Regulated Holding Company
will require the approval of Reliant Energy's shareholders. For additional
information regarding the Regulated Holding Company, please read
"Business -- Our Business -- Restructuring" in Item 1 of this Form 10-K and Note
4(b) to our consolidated financial statements. The Restructuring will also
require the approval of the Louisiana Public Service Commission and the Nuclear
Regulatory Commission. We cannot assure you that those approvals will be
obtained. After the Restructuring, the Regulated Holding Company will become a
registered public utility holding company under the 1935 Act.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR ELECTRIC OPERATIONS
Competition and Deregulation. In June 1999, the Texas legislature adopted
the Legislation, which substantially amended the regulatory structure governing
electric utilities in Texas in order to allow retail competition. Retail pilot
projects for up to 5% of each utility's load in all customer classes will begin
in June 2001 and retail electric competition for all other customers will begin
on January 1, 2002. Our retail operations will be conducted by indirect wholly
owned subsidiaries of Reliant Resources. Under the market framework established
by the Legislation, we will initially be required to sell electricity to Houston
area residential and small commercial customers at a specified price, which is
referred to in the Legislation as the "price to beat," whereas other retail
electric providers will be allowed to sell electricity to these same customers
at any price. We will not be permitted to offer electricity to these customers
at a price other than the price to beat until January 1, 2005, unless before
that date the Texas Utility Commission determines that 40% or more of the amount
of electric power that was consumed in 2000 by residential or small commercial
customers, as applicable, within the affiliated transmission and distribution
utility's certificated service territory, as of January 1, 2002, is committed to
be served by other retail electric providers. In addition, as long as we
continue to provide retail service, the Legislation requires us to make the
price to beat available to residential and small commercial customers in Reliant
Energy HL&P's service territory through January 1, 2007. Because we will not be
able to compete for residential and small commercial customers on the basis of
price in Reliant Energy HL&P's service area, and because we expect that the
retail market framework established by the Legislation will encourage
competition from new retail electric providers, we could lose a significant
number of these customers to other providers. When the pilot projects begin in
June 2001, and until full retail electric competition begins, the Legislation
provides that 5% of our customers may elect to purchase electricity from other
retail electric providers. Our affiliated retail electric providers cannot
participate in the pilot projects in Reliant Energy HL&P's service area. Reliant
Energy HL&P will collect from retail electric providers the rates approved from
its Wires Case to cover the cost of providing transmission and distribution
service and any other non-bypassable charges.
Generally, retail electric providers will procure or buy electricity from
the wholesale generators at unregulated rates, sell electricity at retail to
their customers and pay the transmission and distribution utility a regulated
tariffed rate for delivering the electricity to their customers. The results of
our retail electric operations will be largely dependent upon the amount of
gross margin, or "headroom," available in the "price to beat." The available
headroom will equal the difference between the price to beat and the sum of the
charges, fees and transmission and distribution utility rate approved by the
Texas Utility Commission and the price we pay for power to meet our price to
beat load. The larger the amount of headroom, the more incentive new market
entrants should have to provide retail electric services in Reliant Energy
HL&P's service territory. The Texas Utility Commission's regulations allow us to
adjust our price to beat fuel factor based on the percentage change in the price
of natural gas. In addition, we may also request an adjustment as a result of
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changes in our price of purchased energy. In such a request, we may adjust the
fuel factor to the extent necessary to restore the amount of headroom that
existed at the time our initial price to beat fuel factor was set by the Texas
Utility Commission. We may not request that our price to beat be adjusted more
than twice a year. Currently, we do not know nor can we estimate the amount of
headroom in our initial price to beat or in the initial price to beat for the
affiliated retail electric provider in each other Texas retail electric market.
Similarly, we cannot estimate with any certainty the magnitude and frequency of
the adjustments required, if any, and the eventual impact of such adjustments on
the amount of headroom.
In preparation for this competition, we expect to make significant changes
in the electric utility operations currently conducted through Reliant Energy
HL&P. For additional information regarding these changes, the Legislation,
retail competition, its application to our Electric Operations segment and the
"price to beat," please read "Business -- Our Business -- Deregulation and
Competition," "-- Restructuring," "-- Electric Operations" and
"Business -- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Legislation" in Item 1 of this Form 10-K and Note 4 to our
consolidated financial statements.
Also, market volatility in the price of fuel for our generation operations,
as well as in the price of purchased power, could have an effect on our cost to
generate or acquire power. For additional information regarding commodity prices
and supplies, please read "-- Competitive, Regulatory and Other Factors
Affecting Our Wholesale Energy Operations -- Price Volatility."
Other Regulatory Factors. Pursuant to the Legislation, Reliant Energy HL&P
will be entitled to recover its stranded costs (i.e., the excess of net book
value of generation assets, as defined by the Legislation, over the market value
of those assets) and its regulatory assets related to generation. The
Legislation prescribes specific methods for determining the amount of stranded
costs and the details for their recovery. However, during the base rate freeze
period from 1999 through 2001, earnings above the utility's authorized rate of
return formula may be applied in a manner to accelerate depreciation of
generation related plant assets for regulatory purposes. In addition,
depreciation expense for transmission and distribution related assets may be
redirected to generation assets for regulatory purposes during that period. The
Legislation also provides for Reliant Energy HL&P, or a special purpose entity,
to issue securitization bonds for the recovery of generation related regulatory
assets and a portion of stranded costs. Any stranded costs not recovered through
the sale of securitization bonds may be recovered through a non-bypassable
charge to transmission and distribution customers. For additional information
regarding these securitization bonds, please read "-- Liquidity and Capital
Resources -- Future Sources and Uses of Cash -- Securitization."
The Texas Utility Commission recently stated on record that it would
consider requiring electric utilities to reverse the amount of redirected
depreciation and accelerated depreciation previously taken if in its estimation
the utility has overmitigated its stranded costs. The reversal could occur
through a lower rate for the transmission and distribution utility and/or
through credits contained in the transmission and distribution utility's rate.
Any order requiring the reversal of these amounts would likely be included in
the Texas Utility Commission proceeding establishing the initial rate of the
transmission and distribution utility or in the case of our Electric Operations
segment, the Wires Case. We do not expect the final transmission and
distribution rate in the Wires Case to be established until August 2001. For
more information regarding the Wires Case, see "Business -- Regulation -- State
and Local Regulations -- Texas -- Electric Operations -- Rate Case."
At June 30, 1999, we performed an impairment test of Reliant Energy HL&P's
previously regulated electric generation assets pursuant to SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" (SFAS No. 121), on a plant specific basis. Under SFAS No. 121,
an asset is considered impaired, and should be written down to fair value, if
the future undiscounted net cash flows expected to be generated by the use of
the asset are insufficient to recover the carrying amount of the asset. For
assets that are impaired pursuant to SFAS No. 121, we determined the fair value
for each generating plant by estimating the net present value of future cash
inflows and outflows over the estimated life of each plant. The difference
between fair value and net book value was recorded as a reduction in the current
book value. We determined that $797 million of electric generation assets were
impaired as of June 30, 1999. Of these amounts, $745 million related to the
South Texas Project and $52 million related to two gas-fired generation plants.
The Legislation provides for recovery of this impairment through regulated cash
flows
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during the transition period and through non-bypassable charges to transmission
and distribution customers. As such, a regulatory asset has been recorded for an
amount equal to the impairment loss. We recorded amortization expense related to
the recoverable impaired plant costs and other assets created from discontinuing
regulatory accounting of $221 million in the third and fourth quarters of 1999
and $329 million in 2000. We expect to fully amortize this regulatory asset as
it is recovered from regulated cash flows in 2001.
The impairment analysis requires estimates of possible future market
prices, load growth, competition and many other factors over the lives of the
plants. The resulting impairment loss is highly dependent on these underlying
assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must
finalize and reconcile stranded costs (as defined by the Legislation) in a
filing with the Texas Utility Commission. Any positive difference between the
regulatory net book value and the fair market value of the generation assets (as
defined by the Legislation) will be collected through future non-bypassable
charges. Any over-mitigation of stranded costs may be refunded through future
non-bypassable charges. This final reconciliation allows alternative methods of
third party valuation of the fair market value of these assets, including
outright sale, stock valuations and asset exchanges. Because generally accepted
accounting principles require us to estimate fair market values on a
plant-by-plant basis in advance of the final reconciliation, the financial
impacts of the Legislation with respect to the final determination of stranded
costs in 2004 are subject to material changes. Factors affecting such change may
include estimation risk, uncertainty of future energy and commodity prices and
the economic lives of the plants. If events occur that make the recovery of all
or a portion of the regulatory assets associated with the generation plant
impairment loss and other assets created from discontinuance of regulatory
accounting pursuant to the Legislation no longer probable, we will write off the
corresponding balance of these assets as a non-cash charge against earnings. One
of the results of discontinuing the application of regulatory accounting for the
generation operations is the elimination of the regulatory accounting effects of
excess deferred income taxes and investment tax credits related to these
operations. We believe it is probable that some parties will seek to return
these amounts to ratepayers and, accordingly, we have recorded an offsetting
liability.
In accordance with the Legislation, beginning on January 1, 2002, and
ending at December 31, 2003, any difference between market power prices received
in the generation capacity auction and the Texas Utility Commission's earlier
estimates of those market prices will be included in the 2004 stranded costs
true-up. The Texas Utility Commission's estimate serves as a preliminary
identification of stranded costs for recovery through securitization. This
component of the true-up is intended to ensure that neither the customers nor we
are disadvantaged economically as a result of the two-year transition period by
providing this pricing structure.
Since the time of our original impairment calculation in June 1999 when we
discontinued application of SFAS No. 71 for our generation operations, natural
gas prices have risen 295% from June 1999 to December 31, 2000 resulting in
increases in estimated market prices for power during 2002 and 2003. Generally,
for Reliant Energy HL&P's generation portfolio, sustained increases in natural
gas prices result in an increase in the fair value of Reliant Energy HL&P's
generation portfolio, due to our mix of lower variable cost of electric
generation. Therefore, as electric power prices increase, the amount of our
estimated stranded costs decline and the estimate of our 2002 and 2003 capacity
true-up amounts which may be owed to customers increases.
For additional information regarding the impairment of regulatory assets
and electric generating plant and equipment as well as the recovery of stranded
costs, please read Note 4(a) to our consolidated financial statements. For
additional information regarding our filings to recover under-recovered fuel
costs, please read Note 4(d) to our consolidated financial statements.
Other. For additional information regarding litigation over franchise
fees, please read Note 14(g) to our consolidated financial statements.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR WHOLESALE ENERGY
OPERATIONS
Competition. As of December 31, 2000, our Wholesale Energy business
segment owned and operated 9,231 MW of electric generation assets that serve
wholesale energy markets located in the Mid-Atlantic, Southwest and Midcontinent
regions of the United States and the states of Florida and Texas. Competitive
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factors affecting the results of operations of these generation assets include
new market entrants and construction by others of more efficient generation
assets.
The wholesale power industry has numerous competitors, some of which may
have more operating experience, more acquisition and development experience,
larger staffs and/or greater financial resources than we do. Like us, many of
our competitors are seeking attractive opportunities to acquire or develop power
generation facilities, both in the United States and abroad. This competition
may adversely affect our ability to make investments or acquisitions.
Also, industry restructuring requires or encourages the disaggregation of
many vertically-integrated utilities into separate generation, transmission and
distribution, and retail businesses. As a result, a significant number of
additional competitors could become active in the wholesale power generation
segment of our industry.
Furthermore, other competitors operate power generation projects in the
regions where we have invested in electric generation assets. While demand for
electric energy services is generally increasing throughout the United States,
the rate of construction and development of new, more efficient electric
generation facilities may exceed increases in demand in some regional electric
markets. Although local permitting and siting issues often reduce the risk of a
rapid growth in supply of generation capacity in any particular region, projects
are likely to be built over time. The commencement of commercial operation of
these new facilities in the regional markets where we have facilities will
likely increase the competitiveness of the wholesale power market in those
regions, which could have a material effect on our business and lower the value
of some of our electric generation assets.
Finally, our trading, marketing, power origination and risk management
operations compete with other energy merchants based on the ability to aggregate
supplies at competitive prices from different sources and locations and to
efficiently utilize transportation from third-party pipelines and transmission
from electric utilities. These operations also compete against other energy
marketers on the basis of their relative skills, financial position and access
to credit sources. This competitive factor reflects the tendency of energy
customers, wholesale energy suppliers and transporters to seek financial
guarantees and other assurances that their energy contracts will be satisfied.
As pricing information becomes increasingly available in the energy trading and
marketing business and as deregulation in the electricity markets continues to
accelerate, we anticipate that our trading, marketing, power origination and
risk management operations will experience greater competition and downward
pressure on per-unit profit margins.
Regulation. The regulatory environment applicable to the electric power
industry has recently undergone substantial changes as a result of restructuring
initiatives at both the state and federal levels. These initiatives have had a
significant impact on the nature of the industry and the manner in which its
participants conduct their business. Our Wholesale Energy segment has targeted
the deregulating wholesale and retail segments of the electric power industry
created by these initiatives. These changes are ongoing and we cannot predict
the future development of deregulation in these markets or the ultimate effect
that this changing regulatory environment will have on our business.
Moreover, existing regulations may be revised or reinterpreted, new laws
and regulations may be adopted or become applicable to us or our facilities, and
future changes in laws and regulations may have a detrimental effect on our
business. Certain restructured markets, particularly California, have recently
experienced supply problems and price volatility. These supply problems and
volatility have been the subject of a significant amount of press coverage, much
of which has been critical of the restructuring initiatives. In some markets,
including California (please read "-- California" below), proposals have been
made by governmental agencies and/or other interested parties to slow the pace
of deregulation or to re-regulate areas of these markets that have previously
been deregulated. If the current trend towards competitive restructuring of the
wholesale and retail power markets is reversed, discontinued or delayed, the
business growth prospects of our Wholesale Energy segment would be slowed and
the financial outlook for our existing positions could be impacted.
If RTOs are established as envisioned by FERC Order 2000, "rate pancaking,"
or multiple transmission charges that apply to a single point-to-point delivery
of energy, will be eliminated within a region, and
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wholesale transactions within the region, and between regions will be
facilitated. The end result could be a more competitive, transparent market for
the sale of energy and a more economic and efficient use and allocation of
resources. For additional information regarding FERC Order 2000 affecting these
RTOs, please read "Business -- Regulation -- Federal Energy Regulatory
Commission" in Item 1 of this Form 10-K.
Price Volatility. Our Wholesale Energy business segment sells electricity
from our non-Texas power generation facilities into the spot market or other
competitive power markets or on a contractual basis. Our Wholesale Energy
business segment is not guaranteed any rate of return on our capital investments
through mandated rates, and our revenues and results of operations are likely to
depend, in large part, upon prevailing market prices for electricity and fuel in
our regional markets and other competitive markets. These market prices may
fluctuate substantially over relatively short periods of time. In addition, the
FERC, which has jurisdiction over wholesale power rates, as well as independent
system operators that oversee some of these markets, may impose price
limitations, bidding rules and other mechanisms to address some of the
volatility in these markets. Most of our Wholesale Energy business segment's
domestic power generation facilities purchase fuel under short-term contracts or
on the spot market. Fuel prices may also be volatile, and the price we can
obtain for power sales may not change at the same rate as changes in fuel costs.
These factors could have an adverse impact on our revenues and results of
operations.
Volatility in market prices for fuel and electricity may result from:
- weather conditions,
- seasonality,
- electricity usage,
- illiquid markets,
- transmission or transportation constraints or inefficiencies,
- availability of competitively priced alternative energy sources,
- demand for energy commodities,
- natural gas, crude oil and refined products, and coal production levels,
- natural disasters, wars, embargoes and other catastrophic events, and
- federal, state and foreign energy and environmental regulation and
legislation.
Trading, Marketing, Power Origination and Risk Management Operations. To
lower our Wholesale Energy business segment's financial exposure related to
commodity price fluctuations, its trading, marketing, power origination and risk
management operations routinely enter into contracts to hedge a portion of its
purchase and sale commitments, weather positions, fuel requirements and
inventories of natural gas, coal, crude oil and refined products, and other
commodities. As part of this strategy, our Wholesale Energy business segment
routinely utilizes fixed-price forward physical purchase and sales contracts,
futures, financial swaps and option contracts traded in the over-the-counter
markets or on exchanges. However, our Wholesale Energy business segment does not
expect to cover the entire exposure of its assets or its positions to market
price volatility and the coverage will vary over time. To the extent our
Wholesale Energy business segment has unhedged positions, fluctuating commodity
prices can impact our financial results and financial position, either favorably
or unfavorably.
At times, our Wholesale Energy business segment has open trading positions
in the market, within established guidelines, resulting from the management of
its trading portfolio. To the extent open trading positions exist, fluctuating
commodity prices can impact our financial results and financial position, either
favorably or unfavorably.
The risk management procedures our Wholesale Energy business segment has in
place may not always be followed or may not always work as planned. As a result
of these and other factors, we cannot predict with precision the impact that our
risk management decisions may have on our businesses, operating results or
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financial position. Although our Wholesale Energy business segment devotes a
considerable amount of management effort to these issues, their outcome is
uncertain.
Our trading, marketing, power origination and risk management operations
are also exposed to the risk that counterparties who owe it money or physical
commodities, such as energy or gas, as a result of market transactions will not
perform their obligations. Should the counterparties to these arrangements fail
to perform, our trading, marketing, power origination and risk management
operations might be forced to acquire alternative hedging arrangements or
replace the underlying commitment at then-current market prices. In this event,
our trading, marketing, power origination and risk management operations might
incur additional losses to the extent of amounts, if any, already paid to the
counterparties.
California. During the summer and fall of 2000, prices for wholesale
electricity in California increased dramatically as a result of a combination of
factors, including higher natural gas prices and emission allowance costs,
reduction in available hydroelectric generation resources, increased demand,
decreases in net electric imports, structural market flaws including
over-reliance on the electric spot market, and limitations on supply as a result
of maintenance and other outages. Although wholesale prices increased,
California's deregulation legislation kept retail rates frozen below 1996
levels. This caused two of California's public utilities, which are our
customers based on our deliveries to the Cal PX and the CAL ISO, to amass
billions of dollars of uncollected wholesale power costs and to ultimately
default in January and February 2001 on payments owed for wholesale power
purchased through the Cal PX and from the Cal ISO.
As of December 31, 2000, we were owed $101 million by the Cal PX and $181
million by the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax
provision of $39 million against receivable balances related to energy sales in
the California market. From January 1, 2001 through February 28, 2001, we have
collected $105 million of these receivable balances. As of March 1, 2001, we
were owed a total of $358 million by the Cal ISO, the Cal PX, the CDWR and
California Energy Resources Scheduling for energy sales in the California
wholesale market from the fourth quarter of 2000 through February 28, 2001.
Management will continue to assess the collectibility of these receivables based
on further developments affecting the California electricity market and the
market participants described herein. Additional provisions to the allowance may
be warranted in the future.
In response to the filing of a number of complaints challenging the level
of wholesale prices, the FERC initiated a staff investigation and issued an
order on December 15, 2000 implementing a series of wholesale market reforms,
including an interim price review procedure for prices above a $150/MWh
"breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not
prohibit sales above the "breakpoint," but the seller is subject to weekly
reporting and monitoring requirements. For each reported transaction, potential
refund liability extends for a period of 60 days following the date any such
transaction is reported to the FERC. On March 9, 2001, the FERC issued a further
order establishing a proxy market clearing price of $273/MWh for January 2001,
and on March 16, 2001 the FERC issued a further order adjusting the proxy market
clearing price to $430/MWh for February 2001. New market monitoring and
mitigation measures to replace the $150/MWh breakpoint and reporting obligation
are being developed by the FERC to take effect on May 1, 2001.
In the FERC's March 9 and March 16 orders, the FERC outlined criteria for
determining amounts subject to possible refund based on the proxy market
clearing price for January and February 2001 and indicated that approximately
$12 million of the $125 million charged by us in January 2001 in California to
the Cal ISO and the Cal PX and approximately $7 million of the $47 million
charged by us in February 2001 in California to the Cal ISO and the Cal PX were
subject to possible refunds. In the March 9 and March 16 orders, the FERC set
forth procedures for challenging possible refund obligations. Because we believe
that there is cost or other justification for prices charged above the proxy
market clearing prices established in the March 9 and March 16 orders, we intend
to pursue such a challenge with respect to our potential refund amounts
identified in such orders. Any refunds we may ultimately be obligated to pay are
to be credited against unpaid amounts owed to us for our sales in the Cal PX or
to the Cal ISO. The December 15 order established that a refund condition would
be in place for the period beginning October 2, 2000 through December 31, 2002.
The December 15 order also eliminated the requirement that California's public
utilities
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sell all of their generation into and purchase all of their power from the Cal
PX and directed that the Cal PX wholesale tariffs be terminated effective April
2001. The Cal PX has since suspended its day-ahead and day-of markets and filed
for bankruptcy protection on March 9, 2001. Motions for rehearing have been
filed on a number of issues related to the December 15 order and such motions
are still pending before the FERC.
In addition to the FERC investigation discussed above, several state and
other federal regulatory investigations and complaints have commenced in
connection with the wholesale electricity prices in California and other
neighboring Western states to determine the causes of the high prices and
potentially to recommend remedial action. In California, the California Public
Utilities Commission, the California Electricity Oversight Board, the California
Bureau of State Audits and the California Office of the Attorney General all
have separate ongoing investigations into the high prices and their causes. None
of these investigations have been completed and no findings have been made in
connection with any of them.
Despite the market restructuring ordered under the December 15 order, the
California public utilities have continued to accrue unrecovered wholesale
costs. As a result, the credit ratings of two of these public utilities were
severely downgraded to below investment grade in January 2001. As their credit
lines became unavailable, the two utilities defaulted on payments due to the Cal
PX and the Cal ISO, which operate financially as pass-through entities,
coordinating payments from buyers and sellers of electricity. As a result, the
Cal PX and Cal ISO were not able to pay final invoices to market participants
totaling over $1 billion.
The default of two of California's public utilities on amounts owed the Cal
PX and the Cal ISO for purchased power has further exacerbated the current
crisis in the California wholesale markets and resulted in substantial
uncollected receivables owed to us by the Cal ISO and the Cal PX. The Cal PX's
efforts to recover the available collateral of the utilities, in the form of
block forward contracts, have been frustrated by the emergency acts of
California's Governor, who seized control of the contracts upon the expiration
of temporary restraining orders prohibiting such action. Although obligated to
pay reasonable value for the contracts, the state of California has not yet made
any payment for the contracts. Various actions have been filed challenging the
Governor's ability to seize these contracts.
Upon the default of the two utilities of amounts due to the Cal PX, the Cal
PX issued "charge-backs" allocating the utilities' defaults to the other market
participants. Proceedings were brought both in federal court and at the FERC
seeking a suspension of the charge-backs and challenging the reasonableness of
the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction
suspending any of its charge-back activities in order to allow the FERC to
address the charge-back issues. Amounts owed to us were debited in invoices by
the Cal PX for charge-backs in the amount of $29 million and, on February 14,
2001, we filed our own lawsuit against the Cal PX in the United States District
Court for the Central District of California, seeking a recovery of those
amounts and a stay of any further charge-backs by the Cal PX. The filing of
bankruptcy by the Cal PX will automatically stay for some period the various
court and administrative cases against the Cal PX.
The two defaulting utilities have both filed lawsuits challenging the
refusal of state regulators to allow wholesale power costs to be passed through
to retail customers under the "filed rate doctrine." The filed rate doctrine
provides that wholesale power costs approved by the FERC are entitled to be
recovered through rates. Additionally, to address the failing financial
condition of the two defaulting utilities and the utilities' potential
bankruptcy, the California Legislature passed emergency legislation, effective
January 18, 2001 and February 2, 2001, appropriating funds to be used by the
CDWR for the purchase of wholesale electricity on behalf of the utilities and
authorizing the sale of bonds to fund future purchases under long-term power
contracts with wholesale generators. The CDWR began the process of soliciting
bids from generators for long-term contracts and continued the purchasing of
short-term power contracts. No bonds have yet been issued by the CDWR to support
long-term power purchases or to provide credit support for short-term purchases.
As noted above, two of California's public utilities have defaulted in
their payment obligations to the Cal PX and the Cal ISO as a result of the
refusal of state regulators to allow them to recover their wholesale power
costs. This refusal by state regulators has also caused the utilities to default
on numerous other financial obligations, which could result in either the
voluntary or involuntary bankruptcy of the utilities. While a bankruptcy filing
would result in further post-petition purchases of wholesale electricity being
considered
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administrative expenses of the debtor, a substantial delay could be experienced
in the payment of pre-petition receivables pending the confirmation of a
reorganization plan. The California Legislature is currently considering
legislation under which a state entity would be formed to purchase and operate a
substantial share of the transmission lines in California in an effort to
provide cash to the utilities and thereby avoid potential bankruptcy filings by
the utilities. A number of the creditors for the two California public utilities
have indicated, however, that unless California moves quickly with such a plan,
an involuntary bankruptcy filing may be made by one or more of such creditors.
Because California's power reserves remain at low levels, in part as a
result of the lack of creditworthy buyers of power given the defaults of the
California utilities, the Cal ISO has relied on emergency dispatch orders
requiring generators to provide at the Cal ISO's direction all power not already
under contract. The power supplied to the Cal ISO has been used to meet the
needs of the customers of the utilities, even though two of those utilities do
not have the credit required to receive such power and may be unable to pay for
it. We have contested the obligation to provide power under these circumstances.
The Cal ISO sought a temporary restraining order compelling us to continue to
comply with the emergency dispatch orders despite the utilities' defaults.
Although the payment issue is still disputed, on February 21, 2001, we and the
CDWR entered into a contract expiring March 23, 2001 for the purchase of all of
our available capacity not already under contract and the litigation has been
temporarily stayed. The CDWR is current in its payments under this contract, but
we are still owed $108 million for power provided in compliance with the
emergency dispatch orders for the six weeks prior to the agreement. Depending on
the outcome of the court proceedings initiated by the Cal ISO seeking to enjoin
us from ceasing power deliveries to the Cal ISO, we may be forced to continue
selling power without the guarantee of payment.
Additionally, we are seeking a prompt FERC determination that the Cal ISO
is not complying with the credit provisions of its tariff and a related order of
the FERC issued on February 14, 2001, requiring the Cal ISO not to make
purchases in the real time market unless a creditworthy purchaser is responsible
for such purchases.
For additional information regarding the situation in California, please
read "Business -- Wholesale Energy -- Power Generation Operations -- Southwest
Region" and "Business -- Regulation -- State and Local
Regulations -- California" in Item 1 of this Form 10-K, "-- Results of
Operations by Business Segment -- Wholesale Energy -- 2000 Compared to 1999," as
well as Notes 14(g) and 14(h) to our consolidated financial statements.
COMPETITIVE, REGULATORY AND OTHER FACTORS AFFECTING OUR EUROPEAN ENERGY
OPERATIONS
Competition. The European energy market is highly competitive. In
addition, over the next several years, we expect an increasing consolidation of
the participants in the European generating market.
Our European wholesale operations compete in the Netherlands, primarily
against the three other largest Dutch generating companies, various cogenerators
of electric power, various alternate sources of power and non-Dutch generators
of electric power, primarily from France and Germany. In 2000, UNA and the three
other largest Dutch generating companies supplied approximately 50% of the
electricity consumed in the Netherlands. Smaller Dutch producers supplied about
25% of the consumed electricity, and the remainder was imported. At present, the
Dutch electricity system has three operational interconnection points with
Germany and two interconnection points with Belgium. There are also a number of
projects that are at various stages of development and that may increase the
number of interconnections in the future (post 2005) including interconnections
with Norway and the United Kingdom. The Belgian interconnections are used to
import electricity from France, but a larger portion of Dutch electricity
imports comes from Germany.
Our European trading and marketing operations will also be subject to
increasing levels of competition. As of December 31, 2000, there were 32 trading
and marketing companies registered with the Amsterdam Power Exchange.
Competition among power generators for customers is intense, and we expect
competition to increase with the deregulation of the market. Please read
"-- Regulation." The primary elements of competition affecting both the
generation and trading and marketing operations of our European Energy business
segment are price, credit support, and supply and delivery reliability.
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Deregulation. The Dutch electricity market was opened to limited wholesale
and retail competition on January 1, 1999 as retail competition for large
industrial customers began. The Dutch wholesale electric market was completely
opened to competition on January 1, 2001. Consistent with our expectations at
the time we made the acquisition, we anticipate that our European Energy
business segment may experience a significant decline in gross margin in 2001
attributable to the deregulation of the market and termination of an agreement
with the other Dutch generators and the Dutch distributors. The next customer
segment, composed primarily of commercial customers, will be liberalized by
2002. The remainder of the market, mainly residential, will be open to
competition by 2003. The timing of these market openings is subject to change,
however, at the discretion of the Dutch Minister of Economic Affairs. In
addition, the results of our European Energy segment will be negatively impacted
beginning in 2002 due to the imposition of a standard Dutch corporate income tax
rate, which is currently 35%, on the income of UNA. In 2000 and prior years,
UNA's Dutch corporate income tax rate was zero percent.
Other. Another factor that could have a significant impact on the Dutch
energy industry, including the operations of our European Energy business
segment, is the ultimate resolution of stranded costs issues in the Netherlands.
Prior to 2001, UNA and the other Dutch generators sold their generating output
through the coordinating body for the Dutch electricity generating sector, B.V.
Nederlands Elektriciteit Administratiekantor (NEA). Over the years, NEA has
incurred "stranded" costs as a result of, among other things, a perceived need
to cover anticipated shortages in energy production supply. NEA stranded costs
consist primarily of investments in alternative energy sources and fuel and
power purchase contracts currently estimated to be uneconomical. Legislation has
been approved by the Dutch parliament which would transfer the liability for the
stranded costs from NEA to its four shareholders, one of which is UNA. For
information regarding this legislation, please read Note 14(i) to our
consolidated financial statements.
In connection with our acquisition of UNA, the selling shareholders of UNA
agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG
1.4 billion ($599 million based on an exchange rate of 2.34 NLG per U.S. dollar
as of December 31, 2000), which may be increased in some circumstances at our
option up to NLG 1.9 billion ($812 million). Of the total consideration we paid
for the shares of UNA, NLG 900 million ($385 million) has been placed by the
selling shareholders under the direction of the Dutch Minister of Economic
Affairs in an escrow account to secure the indemnity obligations by the former
shareholders of UNA. Although our management believes that the indemnity
provision will be sufficient to fully satisfy UNA's ultimate share of any
stranded costs obligation, this judgment is based on numerous assumptions
regarding the ultimate outcome and timing of the resolution of the stranded cost
issue, the former shareholders' timely performance of their obligations under
the indemnity arrangement, and the amount of stranded costs, which at present is
not determinable. Any shortfall in the indemnity provision could have a material
adverse effect on our results of operations.
Our European operations are subject to various risks incidental to
investing or operating in foreign countries. These risks include economic risks,
such as fluctuations in currency exchange rates, restrictions on the
repatriation of foreign earnings and/or restrictions on the conversion of local
currency earnings into U.S. dollars. For example, we estimate that the impact of
the devaluation of the Euro relative to the U.S. dollar during 2000 negatively
impacted U.S. dollar net income in the amount of approximately $8 million.
Impact of Currency Fluctuations on Company Earnings. For information about
our exposure through our investment in Europe to losses resulting from
fluctuations in currency rates, please read "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this Form 10-K.
COMPETITIVE AND OTHER FACTORS AFFECTING RERC OPERATIONS
Natural Gas Distribution. Our Natural Gas Distribution business segment
competes primarily with alternate energy sources such as electricity and other
fuel sources. In some areas, intrastate pipelines, other gas distributors and
marketers also compete directly with our Natural Gas Distribution business
segment for gas sales to end-users. In addition, as a result of federal
regulatory changes affecting interstate pipelines, natural gas marketers
operating on these pipelines may be able to bypass our Natural Gas Distribution
business
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segment's facilities and market, sell and/or transport natural gas directly to
commercial and industrial customers.
Generally, the regulations of the states in which our Natural Gas
Distribution business segment operates allow us to pass through changes in the
costs of natural gas to our customers through purchased gas adjustment
provisions in rates. There is, however, an inherent timing difference between
our purchases of natural gas and the ultimate recovery of these costs.
Consequently, we may incur additional "carrying" costs as a result of this
timing difference and the resulting, temporary under-recovery of our purchased
gas costs. To a large extent, these additional carrying costs are not recovered
from our customers.
Pipelines and Gathering. Our Pipelines and Gathering segment competes with
other interstate and intrastate pipelines in the transportation and storage of
natural gas. The principal elements of competition among pipelines are rates,
terms of service, and flexibility and reliability of service. Our Pipelines and
Gathering segment competes indirectly with other forms of energy available to
its customers, including electricity, coal and fuel oils. The primary
competitive factor is price. Changes in the availability of energy and pipeline
capacity, the level of business activity, conservation and governmental
regulations, the capability to convert to alternative fuels, and other factors,
including weather, affect the demand for natural gas in areas we serve and the
level of competition for transportation and storage services. Since FERC Order
No. 636, REGT's and MRT's commodity sales activity has been minimal. Commodity
transactions are usually related to system management activity which we have
been able to manage with little exposure. We have not been nor do we anticipate
to be, negatively impacted from the recent price levels and the tightening of
supply. In addition, competition for our gathering operations is impacted by
commodity pricing levels in its markets because these prices influence the level
of drilling activity in those markets.
Natural Gas Pipeline Company of America has proposed, and is soliciting
customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point
17 miles East of St. Louis Metro, with a proposed in-service date of June 2002.
MRT has renewed or is engaged in negotiations to renew service agreements under
multi-year terms, including service and potential expansion needs along MRT's
existing East Line in Illinois. Our Pipelines and Gathering business segment
derives approximately 14% of its revenues from its contract with Laclede, which
has been under an annual evergreen term provision since 1999. In the event we
are not able to renegotiate a long-term extension to the contract with Laclede,
and Laclede engages another pipeline for the transportation services it
currently obtains from us, the operating and financial results of our Pipelines
and Gathering business segment would be materially adversely affected.
FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS
For information regarding our exposure to risk as a result of fluctuations
in commodity prices and derivative instruments, please read "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K.
INDEXED DEBT SECURITIES (ZENS) AND OUR AOL TIME WARNER INVESTMENT
For information on our indexed debt securities and our investment in AOL
Time Warner common stock, please read "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of this Form 10-K and Note 8 to our consolidated
financial statements.
ENVIRONMENTAL EXPENDITURES
We are subject to numerous environmental laws and regulations, which
require us to incur substantial costs to operate existing facilities, construct
and operate new facilities, and mitigate or remove the effect of past operations
on the environment. For additional information regarding environmental
contingencies, please read Note 14(g) to our consolidated financial statements.
Clean Air Act Expenditures. We expect the majority of capital expenditures
associated with environmental matters to be incurred by our Electric Operations
and Wholesale Energy business segments in connection with emission limitations
for NOx under the Clean Air Act, or to enhance operational flexibility
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under Clean Air Act requirements. In 2000, emission reduction requirements for
NOx were finalized for our electric generating facilities in Texas and the
Mid-Atlantic region. We currently estimate that up to $534 million will be
required to comply with the requirements through the end of 2003, with an
estimated $215 million to be incurred in 2001. The Texas regulations require
additional reductions that must be completed by March 2007. Estimates for the
Texas units for the period 2004 through 2007 have not been defined, but could be
up to $230 million. We are currently litigating the economic and technical
viability of the Texas post-2004 reduction requirements, but cannot predict the
outcome of this litigation. In addition, the Legislation created a program
mandating air emissions reductions for some generating facilities of our
Electric Operations segment. The Legislation provides for stranded costs
recovery for costs associated with this obligation incurred before May 1, 2003.
For additional information regarding the Legislation, please read Note 4(a) to
our consolidated financial statements. Additional NOx emission controls for our
generating units located in California may result in expenditures of up to $30
million through 2002. For additional information regarding environmental
regulation of air emissions, please read "Business -- Environmental
Matters -- Air Emissions" in Item 1 of this Form 10-K.
Site Remediation Expenditures. From time to time we have received notices
from regulatory authorities or others regarding our status as a potentially
responsible party in connection with sites found to require remediation due to
the presence of environmental contaminants. Based on currently available
information, we believe that remediation costs will not materially affect our
financial position, results of operations or cash flows. There can be no
assurance, however, that future developments, including additional information
about existing sites or the identification of new sites, will not require
material revisions to our estimates. For information about specific sites that
are the subject of remediation claims, please read Note 14(g) to our
consolidated financial statements and Note 9(c) to RERC's consolidated financial
statements.
Water, Mercury and Other Expenditures. As discussed under
"Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K,
regulatory authorities are in the process of implementing regulations and
quality standards in connection with the discharge of pollutants into waterways.
Once these regulations and quality standards are enacted, we will be able to
determine if our operations are in compliance, or if we will have to incur costs
in order to comply with the quality standards and regulations. Until that time,
however, we are not able to predict the amount of these expenditures, if any. To
date, however, our expenditures associated with respect to permits,
registrations and authorizations for operation of facilities under the statutes
regulating the discharge of pollutants into surface water have not been
material. With regard to mercury remediation and other environmental matters,
such as the disposal of solid wastes, our expenditures have not been, and are
not expected to be material, based on our experiences and that of others in our
industries. Please read "Business -- Environmental Matters -- Mercury
Contamination" and "-- Other" in Item 1 of this Form 10-K.
OTHER CONTINGENCIES
For a description of other legal and regulatory proceedings affecting us,
please read Notes 4 and 14 to our consolidated financial statements and Note 9
to RERC's consolidated financial statements.
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LIQUIDITY AND CAPITAL RESOURCES
COMPANY CONSOLIDATED CAPITAL REQUIREMENTS
Our liquidity and capital requirements are affected primarily by capital
programs, working capital needs and debt service requirements. Our Wholesale
Energy segment expects to continue to participate as a bidder in future
acquisitions of independent power projects and privatizations of generation
facilities, which are excluded from the following table. Our capital
requirements are expected to be met with excess cash flows from operations and
the proceeds of project financings, equity offerings and borrowings. Additional
capital expenditures are dependent upon the nature and extent of future project
commitments, some of which may be substantial. The capital requirements for 2000
were, and as estimated for 2001 through 2005 as of March 19, 2001 are, as
follows (in millions):
2000 2001 2002 2003 2004 2005
------ ------ ------ ------ ------ ------
Electric Operations (with nuclear
fuel)(1)................................ $ 643 $ 947 $ 428 $ 450 $ 427 $ 379
Natural Gas Distribution.................. 195 176 175 180 169 172
Pipelines and Gathering................... 61 51 52 38 38 33
Wholesale Energy(1)(2).................... 1,966 591 532 186 146 129
European Energy........................... 995 5 26 -- 21 17
Other Operations.......................... 91 126 97 101 109 98
Payments of long-term debt, sinking fund
requirements and minimum capital lease
obligations............................. 679 630 789 1,238 48 332
Mid-Atlantic generating assets operating
lease payments.......................... 1 259 137 77 84 75
Major maintenance cash outlays for
non-rate regulated electric generating
assets.................................. 73 65 78 77 82 89
------ ------ ------ ------ ------ ------
Total........................... $4,704 $2,850 $2,314 $2,347 $1,124 $1,324
====== ====== ====== ====== ====== ======
- ---------------
(1) Beginning in 2002 capital requirements for current generation operations of
Reliant Energy HL&P are included in Wholesale Energy rather than in Electric
Operations.
(2) In August 2000, we sold to and leased back from owner-lessors, interests in
three Mid-Atlantic generating facilities. As consideration for the sale, we
received $1.0 billion in cash, which was used to repay indebtedness
outstanding under credit facilities. The expenditures for the acquisitions
of these Mid-Atlantic generating facilities have been excluded from the 2000
capital requirements.
The net cash provided by/used in operating, investing and financing
activities for 1998, 1999 and 2000 is as follows (in millions):
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
Cash provided by (used in):
Operating activities..................................... $1,427 $1,110 $1,346
Investing activities..................................... (1,238) (2,876) (3,288)
Financing activities..................................... (206) 1,823 2,032
Cash Provided by Operating Activities
Net cash provided by operations in 2000 increased $236 million compared to
1999. This increase primarily resulted from:
- proceeds from the sale of an investment in marketable debt securities by
UNA,
- improved operating results of our Wholesale Energy segment's California
generating facilities,
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- incremental cash flows provided by UNA, acquired in the fourth quarter of
1999,
- cash flows from the Mid-Atlantic generating facilities, acquired in the
second quarter of 2000,
- increased sales from our Electric Operations segment due to growth in
usage and number of customers, and
- partially offset by increased Electric Operations' under-recovered fuel
costs and Wholesale Energy's margin deposits on energy trading
activities.
Net cash provided by operations in 1999 decreased $317 million compared to
1998 primarily due to a $141 million federal tax refund received in 1998 and
other changes in working capital.
Cash Used in Investing Activities
Net cash used in investing activities increased $412 million during 2000
compared to 1999. This increase was primarily due to:
- the funding of the remaining purchase obligation for UNA of $982 million
on March 1, 2000,
- the purchase of the Mid-Atlantic generation facilities for $2.1 billion
on May 12, 2000, and
- increased capital expenditures.
Proceeds of $1.0 billion from the sale-leaseback of three of our
Mid-Atlantic generation facilities in 2000, the sale of a substantial portion of
our Latin American investments in 2000 and the purchase of $537 million of AOL
Time Warner securities in 1999 partially offset these increases.
Net cash used in investing activities increased $1.6 billion in 1999
compared to 1998. This increase was primarily due to:
- the cash payment of $833 million in 1999 related to the acquisition of
UNA,
- the cash payment of $188 million in 1999 for the acquisition of our
generating facility located in Florida,
- the purchase of $537 million of AOL Time Warner securities in 1999, and
- increased capital expenditures.
Cash Used in/Provided by Financing Activities
Cash flows provided by financing activities increased $209 million in 2000
compared to 1999, primarily due to cash received from short-term borrowings
partially offset by a decline in proceeds from long-term debt and the sale of
trust preferred securities.
Cash flows provided by financing activities increased $2.0 billion in 1999
compared to 1998, primarily due to cash received from short-term borrowings, the
net issuance of long-term debt and the issuance of trust preferred securities
aggregating $2.1 billion (please read Notes 10 and 11 to our consolidated
financial statements), partially offset by $91 million of purchases of our
common stock. The net borrowings incurred during 1999 were utilized to purchase
AOL Time Warner securities, to make the $833 million cash payment related to the
acquisition of UNA, to support increased capital expenditures and to fund our
working capital requirements.
FUTURE SOURCES AND USES OF CASH FLOWS
Credit Facilities. As of December 31, 2000, we had credit facilities in
effect, including facilities of various financing subsidiaries and operating
subsidiaries, that provided for an aggregate of $8.4 billion in committed
credit. As of December 31, 2000, $6.7 billion was outstanding under these
facilities including commercial paper of $3.7 billion and letters of credit of
$899 million. The remaining unused credit facilities
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totaled $1.7 billion. The credit facilities under which Reliant Energy borrows
or provides credit support contain various business and financial covenants
requiring us to, among other things, maintain leverage (as defined in the credit
facilities) below specified ratios. Certain credit facilities at the subsidiary
level also contain various financial covenants limiting leverage and requiring
the subsidiary to maintain its interest coverage ratio (as defined in the credit
facilities) above a specified ratio during stated periods. We are in compliance
with the covenants under all of these credit agreements. We do not expect any of
these covenants to materially limit our ability to borrow or obtain letters of
credit under these facilities. For additional discussion, please read Note 10(a)
to our consolidated financial statements.
Of the $8.4 billion of committed credit facilities described above, $5.0
billion will expire in 2001. To the extent that we continue to need access to
this amount of committed credit, we expect to extend or replace these facilities
on normal commercial terms on a timely basis.
Between December 2000 and March 2001, Reliant Resources entered into a
total of eleven bilateral credit facilities with financial institutions, which
provide for an aggregate of $1.6 billion in committed credit. The facilities
became effective subsequent to December 31, 2000 and expire on October 2, 2001.
Concurrent with the effectiveness of these facilities, $500 million of credit
facilities of a financing subsidiary were canceled. Interest rates on the
borrowings are based on the London inter-bank offered rate (LIBOR) plus a
margin, a base rate or a rate determined through a bidding process. These
facilities contain various business and financial covenants requiring Reliant
Resources to, among other things, maintain a ratio of net debt to the sum of net
debt, subordinated affiliate debt and shareholder's equity not to exceed 0.60 to
1.00. These covenants are not anticipated to materially restrict Reliant
Resources from borrowing funds or obtaining letters of credit under these
facilities. The credit facilities are subject to facility and usage fees that
are calculated based on the amount of the facility commitments and on the
amounts outstanding under the facilities, respectively.
Shelf Registrations. At December 31, 2000, Reliant Energy had shelf
registration statements providing for the issuance of $230 million aggregate
liquidation value of our preferred stock, $580 million aggregate principal
amount of our debt securities and $125 million of trust preferred securities and
related junior subordinated debt securities. In addition, Reliant Energy had a
shelf registration for 15 million shares of its common stock which, would have
been worth $650 million as of December 31, 2000 based on the closing price of
its common stock as of this date. In January 2001, RERC Corp. filed a shelf
registration statement for $600 million of unsecured unsubordinated debt
securities of which $550 million was issued in February 2001.
RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million
of unsecured notes that bear interest at 7.75% per year and mature in February
2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net
proceeds from the sale of the notes to pay a $400 million dividend to Reliant
Energy, and for general corporate purposes. Reliant Energy used the $400 million
proceeds from the dividend for general corporate purposes, including the
repayment of short-term borrowings.
Money Fund. We have a "money fund" through which Reliant Energy and some
of its participating subsidiaries can borrow or invest on a short-term basis.
Funding needs are aggregated and borrowing or investing is based on the net cash
position. The money fund's net funding requirements are generally met with
commercial paper.
Securitization. Reliant Energy HL&P filed an application with the Texas
Utility Commission requesting a financing order authorizing the issuance by a
special purpose entity organized by us, pursuant to the Legislation, of
transition bonds relating to Reliant Energy HL&P's generation related regulatory
assets. In May 2000, the Texas Utility Commission issued a financing order to
Reliant Energy authorizing the issuance of transition bonds in an amount not to
exceed $740 million plus actual up-front qualified costs. Payments on the
transition bonds will be made out of funds derived from non-bypassable
transition charges assessed to Reliant Energy HL&P's transmission and
distribution customers. The offering of the transition bonds will be registered
under the Securities Act of 1933 and is expected to be consummated during 2001.
The transition bonds will be offered and sold only by means of a prospectus.
This Form 10-K does not constitute an offer to sell or the solicitation of an
offer to buy nor will there be any sale of the transition bonds in any state in
which
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such offer, solicitation or sale would be unlawful prior to registration or
qualification under the securities laws of such state.
The expected timing of the transition bond offering assumes that the Texas
Supreme Court will have rejected a constitutional challenge to the statute
permitting the financing orders. That challenge was brought in a Texas state
district court by Power Choice, Inc. in connection with a different financing
order, issued by the Texas Utility Commission to another utility. The district
court affirmed the constitutionality of the statute. Power Choice took a direct
appeal to the Texas Supreme Court under a statute providing for expedited
judicial review. The Texas Supreme Court heard oral argument on November 29,
2000, and as of March 19, 2001, a decision has not been rendered at this time.
Reliant Energy Latin America Divestitures. We have received an aggregate
of $790 million in after-tax proceeds from the sale of some investments held by
the Latin America business segment. For additional information, please read
"Business -- Our Business -- Discontinued Operations" in Item 1 of the Form 10-K
and Note 19 to our consolidated financial statements.
Fuel Filing. As of December 31, 2000, Reliant Energy HL&P was
under-collected on fuel recovery by approximately $558 million. In two separate
filings, Reliant Energy HL&P received approval to implement fuel surcharges to
collect the under-recovery of fuel expenses, as well as to adjust the fuel
factor to compensate for significant increases in the price of natural gas.
On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and
address our undercollected fuel costs of $389 million, which is the accumulated
amount since September 2000 through February 2001 plus estimates for March and
April, 2001. Reliant Energy HL&P is requesting to revise its fixed fuel factor
to be implemented with the May 2001 billing cycle and has proposed to defer the
collection of the $389 million until the 2004 stranded costs true-up proceeding.
For additional information regarding the 2004 stranded costs true-up proceeding,
please read "-- Certain Factors Affecting Our Future Earnings -- Competitive,
Regulatory and Other Factors Affecting Our Electric Operations" and Note 4(a) to
our consolidated financial statements.
Initial Public Offering of Reliant Resources. On July 27, 2000, Reliant
Energy announced its intention to form Reliant Resources, which will own and
operate a substantial portion of Reliant Energy's unregulated operations, and to
offer no more than 20% of the common stock of Reliant Resources in an initial
public offering in 2001. Reliant Energy expects the Offering to be followed by a
distribution to Reliant Energy's or its successor's shareholders the remaining
common stock of Reliant Resources within 12 months of the Offering. For
additional information, please read "Business -- Our Business -- Restructuring,"
in Item 1 of this Form 10-K, "-- Certain Factors Affecting Our Future
Earnings -- Business Separation and Restructuring" and Note 4(b) to our
consolidated financial statements.
Acquisition of UNA. In the fourth quarter of 1999, we funded $833 million
of the UNA purchase obligation. On March 1, 2000, we funded the $982 million
remaining UNA purchase obligation. We obtained a portion of the funds for this
purchase from a Euro 600 million ($596 million) three-year term loan facility
established in February 2000.
Indemnification of UNA Stranded Costs. In connection with the acquisition
of UNA, the selling shareholders of UNA agreed to indemnify UNA for specified
stranded costs in an amount not to exceed NLG 1.4 billion ($599 million based on
a December 31, 2000 exchange rate of 2.34 NLG per U.S. dollar). This amount may
be increased in some circumstances at our option up to NLG 1.9 billion ($812
million). Of the total consideration we paid for the shares of UNA, NLG 900
million ($385 million) has been placed in an escrow account to secure these
indemnity obligations by the former shareholders of UNA under the direction of
the Dutch Ministry of Economic Affairs. We believe that the indemnity provision
will be sufficient to cover UNA's ultimate share of any stranded costs
obligation. We base this belief on numerous assumptions regarding the ultimate
outcome and timing of the resolution of the stranded costs issue, the former
shareholders' timely performance of their obligations under the indemnity
arrangement, and the amount of stranded costs, which at present is not
determinable. For further discussion of UNA stranded costs, please read Note
14(i) to our consolidated financial statements.
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Acquisition of Mid-Atlantic Assets. On May 12, 2000, we completed the
acquisition of our Mid-Atlantic assets from Sithe Energies, Inc. for an
aggregate purchase price of $2.1 billion. The acquisition was originally
financed through commercial paper borrowings at one of our financing
subsidiaries. In August 2000, we entered into separate sale/leaseback
transactions with each of the three owner-lessors for our respective 16.45%,
16.67% and 100% interests in the Conemaugh, Keystone and Shawville generating
stations, respectively, which we acquired as part of the Mid-Atlantic
acquisition. For additional discussion of these lease transactions, please read
Notes 3(a) and 14(c) to our consolidated financial statements. As consideration
for the sale of our interest in each of the facilities, we received a total of
$1.0 billion in cash that was used to repay commercial paper borrowings at one
of our financing subsidiaries. We will continue to make lease payments through
2029. The lease terms expire in 2034. Cash lease payments are scheduled as
follows (in millions):
2001....................................................... $ 259
2002....................................................... 137
2003....................................................... 77
2004....................................................... 84
2005....................................................... 75
2006 and beyond............................................ 1,188
------
Total............................................ $1,820
======
Channelview Project. Our 781 MW gas-fired, combined cycle, cogeneration
plant located in Channelview, Texas, which is currently under construction, is
expected to cost $463 million, including $129 million in commitments for the
purchase of combustion turbines. Of this amount, $280 million had been incurred
as of December 31, 2000. The project continues to be financed through funds
received under the terms of a committed equity bridge facility, which totals $92
million, a non-recourse debt facility aggregating $369 million and projected
construction revenues of $2 million.
Other Generating Projects. As of December 31, 2000, we had an additional
three non-rate regulated generating facilities under construction. Total
estimated costs of constructing these facilities are $867 million, including
$366 million in commitments for the purchase of combustion turbines. As of
December 31, 2000, we had incurred $614 million of the total projected costs of
these projects, which were funded primarily through short-term borrowings from
various financing subsidiaries of Reliant Energy. We believe that our level of
cash, our borrowing capability and proceeds from the initial public offering as
discussed above will be sufficient to fund these commitments. In addition, we
have options to purchase additional combustion turbines for a total estimated
cost of $544 million for future generation projects. We believe that our current
level of cash, our borrowing capability and proceeds from the initial public
offering will be sufficient to fund these options should we choose to exercise
them.
Naming Rights to Houston Sports Complex. In October 2000, we acquired the
naming rights for the new football stadium for the Houston Texans, the National
Football League's newest franchise. In addition, the naming rights cover the
entertainment and convention facilities included in the stadium complex. The
agreement extends for 32 years. In addition to naming rights, the agreement
provides us with significant sponsorship rights. The aggregate cost of the
naming rights will be approximately $300 million. During the fourth quarter of
2000, we incurred an obligation to pay $12 million in order to secure the
long-term commitment and for the initial advertising of which $10 million was
expensed. Starting in 2002, when the new stadium is operational, we will pay $10
million each year through 2032 for annual advertising under this agreement.
California Trade Receivables. During the summer and fall of 2000, prices
for wholesale electricity in California increased dramatically as a result of a
combination of factors, including higher natural gas prices and emissions
allowance costs, reduction in available hydroelectric generation resources,
increased demand, decreases in net electric imports, structural market flaws
including over-reliance on the spot market, and limitations on supply as a
result of maintenance and other outages. Although wholesale prices increased,
California's deregulation legislation kept retail rates frozen below 1996
levels. This caused two of California's
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public utilities, which are our customers based on our deliveries to the Cal PX
and the Cal ISO, to amass billions of dollars of uncollected wholesale power
costs and ultimately default in January and February 2001 on payments owed for
wholesale power purchased through the Cal PX and from the Cal ISO. As of
December 31, 2000, we were owed $101 million by the Cal PX and $181 million by
the Cal ISO. In the fourth quarter of 2000, we recorded a pre-tax provision of
$39 million against receivable balances related to energy sales in the
California market. From January 1, 2001 through February 28, 2001, we have
collected $105 million of these receivable balances. As of March 1, 2001, we
were owed $358 million by the Cal ISO, the Cal PX, the CDWR and California
Energy Resource Scheduling, for energy sales in the California wholesale market,
which includes power sales in the wholesale California market from the fourth
quarter of 2000 through February 28, 2001. For additional information regarding
uncertainties in the California wholesale market, please read "-- Certain
Factors Affecting Our Future Earnings -- Competitive, Regulatory and Other
Factors Affecting Our Wholesale Energy Operations -- California" as well as
Notes 14(g) and 14(h) to our consolidated financial statements.
Treasury Stock Purchases. As of December 31, 2000, we were authorized
under our common stock repurchase program to purchase an additional $271 million
of our common stock. Our purchases under our repurchase program depend on market
conditions, might not be announced in advance and may be made in open market or
privately negotiated transactions.
Environmental Issues. We anticipate investing up to $711 million in
capital and other special project expenditures between 2001 and 2005 for
environmental compliance. Of this amount, we anticipate expenditures to be
approximately $217 million and $259 million in 2001 and 2002, respectively.
Other Sources/Uses of Cash. Our liquidity and capital requirements are
affected primarily by capital expenditures, debt service requirements and
various working capital needs. We expect to continue to participate as a bidder
in future acquisitions of independent power projects and privatizations of
generation facilities. We expect any resulting capital requirements to be met
with excess cash flows from operations, as well as proceeds from debt and equity
offerings, project financings and other borrowings. Additional capital
expenditures depend upon the nature and extent of future project commitments,
some of which may be substantial. We believe that our current level of cash and
borrowing capability and proceeds from the Reliant Resources initial public
offering discussed above, along with future cash flows from operations, will be
sufficient to meet the existing operational needs of our businesses for the next
12 months.
NEW ACCOUNTING PRONOUNCEMENTS
Effective January 1, 2001, we were required to adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS
No. 133), which establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities. This statement requires that derivatives
be recognized at fair value in the balance sheet and that changes in fair value
be recognized either currently in earnings or deferred as a component of other
comprehensive income, depending on the intended use of the derivative, its
resulting designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board (FASB) issued an amendment that narrows the
applicability of the pronouncement to some purchase and sales contracts and
allows hedge accounting for some other specific hedging relationships. Adoption
of SFAS No. 133 resulted in a $62 million cumulative after-tax increase to net
income and a cumulative after-tax increase of accumulated other comprehensive
loss of $252 million in the first quarter of 2001. The adoption also increased
current assets, long-term assets, current liabilities, and long-term liabilities
by $703 million, $252 million, $805 million and $340 million, respectively, on
our consolidated balance sheet. We will also reclassify $788 million from
current portion of long-term debt to other current liabilities due to the
adoption.
The total impact of our adoption of SFAS No. 133 on earnings and
accumulated other comprehensive loss is dependent upon certain pending
interpretations, which are currently under consideration, including those
related to the "normal purchases and normal sales." The interpretations of this
issue, and others, are currently under consideration by the FASB. While the
ultimate conclusions reached on interpretations being considered by the FASB
could impact the effects of our adoption of SFAS No. 133, we do not believe that
such conclusions would have a material effect on our current estimate of the
impact of the adoption.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
IMPACT OF CHANGES IN INTEREST RATES, EQUITY MARKET VALUES, FOREIGN CURRENCY
EXCHANGE RATES AND ENERGY COMMODITY PRICES
We are exposed to various market risks. These risks are inherent in our
financial statements and arise from transactions entered into in the normal
course of business. We utilize derivative financial instruments to mitigate the
impact of changes in electricity and fuel prices on our operating results and
cash flows. We utilize cross-currency swaps and options to hedge our net
investments in foreign subsidiaries and other financial instruments to manage
various other market risks.
INTEREST RATE RISK
We have long-term debt, Company obligated mandatorily redeemable preferred
securities of subsidiary trusts holding solely our junior subordinated
debentures (Trust Preferred Securities), securities held in our nuclear
decommissioning trust, bank facilities, some lease obligations and our
obligations under the ZENS, which subject us to the risk of loss associated with
movements in market interest rates.
At December 31, 1999 and 2000, we had issued fixed-rate debt (excluding
indexed debt securities) and Trust Preferred Securities aggregating $5.7 billion
and $5.5 billion, respectively, in principal amount and having a fair value of
$5.5 billion each year. These instruments are fixed-rate and, therefore, do not
expose us to the risk of loss in earnings due to changes in market interest
rates (please read Notes 10 and 11 to our consolidated financial statements).
However, the fair value of these instruments would increase by approximately
$281 million if interest rates were to decline by 10% from their levels at
December 31, 2000. In general, such an increase in fair value would impact
earnings and cash flows only if we were to reacquire all or a portion of these
instruments in the open market prior to their maturity.
Our floating-rate obligations aggregated $3.1 billion and $5.8 billion at
December 31, 1999 and 2000, respectively, (please read Note 10 to our
consolidated financial statements), inclusive of (a) amounts borrowed under our
short-term and long-term credit facilities (including the issuance of commercial
paper supported by these facilities), (b) borrowings underlying a receivables
facility and (c) amounts subject to a master leasing agreement under which lease
payments vary depending on short-term interest rates. These floating-rate
obligations expose us 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, 2000 levels, our consolidated interest expense
and expense under operating leases would increase by a total of approximately $3
million each month in which such increase continued.
As discussed in Notes 14(l) to our consolidated financial statements, we
contribute $14.8 million per year to a trust established to fund our 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 $159 million
as of December 31, 2000, of which approximately 40% were fixed-rate debt
securities that subject us 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, 2000, the decrease in fair value of the fixed-rate debt
securities would not be material to us. In addition, the risk of an economic
loss is mitigated. Any unrealized gains or losses are accounted for in
accordance with SFAS No. 71 as a regulatory asset/liability because we believe
that our future contributions, which are currently recovered through the
rate-making process, will be adjusted for these gains and losses. For further
discussion regarding the recovery of decommissioning costs pursuant to the
Legislation, please read Note 4(a) to our consolidated financial statements.
As discussed in Note 10(b) to our consolidated financial statements, in
November 1998, RERC Corp. sold $500 million aggregate principal amount of its
6 3/8% Term Enhanced Remarketable Securities (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, 2000, we could terminate the option at a cost of $34 million. A
decrease of 10% in the December 31, 2000 level of interest rates would increase
the cost of termination of the option by approximately $13 million.
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As discussed in Note 8 to our consolidated financial statements, upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation will be
bifurcated into a debt component of $122 million and a derivative component of
$788 million. The debt component of $122 million is a fixed-rate obligation and,
therefore, does not expose us to the risk of loss in earnings due to changes in
market interest rates. However, the fair value of the debt component would
increase by approximately $17 million if interest rates were to decline by 10%
from levels at December 31, 2000. Changes in the fair value of the derivative
component will be recorded in our statements of consolidated operations and,
therefore, we are exposed to changes in the fair value of the derivative
component as a result of changes in the underlying risk-free interest rate. If
the risk-free interest rate were to increase by 10% from December 31, 2000
levels, the fair value of the derivative component would increase by
approximately $12 million, which would be recorded as a loss in our statements
of consolidated operations.
EQUITY MARKET RISK
As discussed in Note 8 to our consolidated financial statements, we own
approximately 26 million shares of AOL Time Warner Inc. common stock (AOL TW
Common), which are held by us to facilitate our ability to meet our obligations
under the ZENS. Please read Note 8 to our consolidated financial statements for
a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation
and our historical accounting treatment of our ZENS obligation. Subsequent to
adoption of SFAS No. 133, a decrease of 10% from the December 31, 2000 market
value of AOL TW Common would result in a loss of approximately $7 million, which
would be recorded as a loss in our statements of consolidated operations.
As discussed above under "-- Interest Rate Risk," we contribute to a trust
established to fund our share of the decommissioning costs for the South Texas
Project, which held debt and equity securities as of December 31, 2000. The
equity securities expose us 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, 2000, the resulting loss in fair value of these securities would
not be material to us. Currently, the risk of an economic loss is mitigated as
discussed above under "-- Interest Rate Risk."
FOREIGN CURRENCY EXCHANGE RATE RISK
Our European operations expose us to risk of loss in the fair value of our
European investments due to the fluctuation in foreign currencies relative to
our reporting currency, the U.S. dollar. We account for adjustments resulting
from translation of our investments that have functional currencies other than
the U.S. dollar as a charge or credit to a separate component of accumulated
other comprehensive income (loss) in stockholders' equity. As of December 31,
2000, we have entered into foreign currency swaps and have issued
Euro-denominated debt to hedge our net European investment. Changes in the value
of the swaps and debt are recorded as foreign currency translation adjustments
as a component of accumulated other comprehensive income (loss) in stockholders'
equity. As of December 31, 2000, we had recorded a $2 million loss in cumulative
net translation adjustments. The cumulative translation adjustments will be
realized in earnings and cash flows only upon the disposition of the related
investments.
We have substantially hedged our net investment in our European
subsidiaries through a combination of Euro-denominated borrowings and various
derivative instruments. During the normal course of business, we review our
currency hedging strategies and determine the hedging approach we deem
appropriate based upon the circumstances of each situation.
Our European Energy segment has entered into financial instruments to
purchase approximately $120 million to hedge future fuel purchases payable in
U.S. dollars. As of December 31, 2000, the fair value of these financial
instruments was a $6 million liability. An increase in the value of the Euro of
10% compared to the U.S. dollar from its December 31, 2000 level would result in
an additional loss in the fair value of these foreign currency financial
instruments of $12 million.
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COMMODITY PRICE RISK
Trading and marketing operations often involve market risks associated with
managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. We routinely enter into
futures, forward contracts, swaps and options to hedge purchase and sale
commitments, fuel requirements and inventories of natural gas, coal,
electricity, oil, emission allowances, weather derivatives and other commodities
and to minimize the risk of market fluctuations on our trading, marketing, power
origination and risk management operations. We assess the risk of our
non-trading derivatives (Energy Derivatives) using a sensitivity analysis
method, and we assess the risk of our trading derivatives (Trading Derivatives)
using the value-at-risk (VAR) method, in order to maintain our total exposure
within management-prescribed limits (both methods are described below).
The sensitivity analysis performed on our Energy Derivatives measures the
potential loss in earnings based on a hypothetical 10% movement in energy
prices. An increase of 10% in the market prices of energy commodities from their
December 31, 1999 and 2000 levels would have decreased the fair value of our
Energy Derivatives, from their levels on those respective dates, by $12 million
and $149 million, respectively.
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 our physical purchases and sales of natural gas and electric power
to which the hedges relate. Furthermore, the Energy Derivative portfolio is
managed to complement the physical transaction portfolio, reducing overall risks
within limits. Therefore, the adverse impact to the fair value 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:
- the Energy Derivatives are not closed out in advance of their expected
term,
- the Energy Derivatives continue to function effectively as hedges of the
underlying risk, and
- as applicable, anticipated underlying transactions settle as expected.
If any of the above-mentioned assumptions cease to be true, 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.
Trading Derivatives held by our trading and marketing operations consist of
physical forwards, swaps, options and exchange-traded futures and options in
natural gas, electricity, crude oil and refined products and weather
derivatives, and are exposed to losses in fair value due to changes in the price
and volatility of the underlying derivatives. We utilize the variance/covariance
model of VAR, which is a probabilistic model that measures the risk of loss to
earnings in market sensitive instruments. The variance/covariance model relies
on statistical relationships to describe how changes in different markets can
affect a portfolio of instruments with different characteristics and market
exposures. We use the delta-approximation method for reporting option positions.
VAR models are relatively sophisticated; however, the quantitative risk
information is limited by the parameters established in creating the model. The
instruments being evaluated could have features that may trigger a potential
loss in excess of calculated amounts if changes in commodity prices exceed the
confidence level of the model used. The VAR methodology employs a seasonally
adjusted volatility-based approach with the following critical parameters:
volatility estimates, appropriate market-oriented holding periods and seasonally
adjusted correlation estimates. The holding period (typically one day) is our
estimate of the length of time that will be needed to liquidate the positions.
The volatility and the correlation estimates measure the impact of adverse price
movements both at an individual position level as well as at the total portfolio
level. The confidence level established for our purposes is 95%. For example, if
VAR is calculated at $10 million, we may state with a 95% confidence level that
if prices move against our positions, our pre-tax loss in liquidating our
portfolio would not exceed $10 million based on the VAR assumptions over the
defined holding period. With respect to Trading Derivatives, our highest, lowest
and average monthly VAR during 2000 was
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$15 million, $1 million and $6 million, respectively. During 1999, our highest,
lowest and average monthly VAR was less than $8 million.
We cannot assure you that market volatility, failure of counterparties to
meet their contractual obligations, transactions entered into after the date of
this Form 10-K or a failure of risk controls will not lead to significant losses
from our marketing and risk management activities.
RISK OVERSIGHT
We control the scope of our trading, power origination, marketing and risk
management operations through a comprehensive set of policies and procedures
involving senior levels of our management. Our Board of Directors sets the risk
limit parameters, and the audit committee of the board has oversight for the
ongoing evaluation of the adequacy of the risk control organization and
policies. A risk oversight committee, comprised of corporate and business
segment officers, oversees all of our activities, which include commodity price,
credit, foreign currency, equity and interest rate risk, including our trading,
marketing, power origination and risk management operations. The committee also
proposes VAR limits to our Board of Directors. Our Board of Directors ultimately
sets our aggregate VAR limit. We have a corporate risk control organization,
headed by a chief risk control officer, which is assigned responsibility for
establishing and enforcing the policies, procedures and limits and evaluating
the risks inherent in proposed transactions. Key risk control activities include
credit review and approval, credit and performance risk measurement and
monitoring, validation of transactions, portfolio valuation and daily portfolio
reporting including mark-to-market valuation, VAR and other risk measurement
metrics.
To the extent an open position exists, fluctuating commodity prices can
impact financial results and financial position, either favorably or
unfavorably. As a result, we cannot predict with precision the impact that our
risk management decisions may have on our businesses, operating results or
financial position.
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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF THE COMPANY.
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1999 2000
----------- ----------- -----------
REVENUES.................................................... $11,229,519 $15,223,094 $29,339,384
EXPENSES:
Fuel and cost of gas sold................................. 4,815,752 6,699,792 15,071,801
Purchased power........................................... 2,215,049 4,137,414 8,627,853
Operation and maintenance................................. 1,583,122 1,781,030 2,356,207
Taxes other than income taxes............................. 469,429 441,242 498,061
Depreciation and amortization............................. 866,272 905,305 906,328
----------- ----------- -----------
Total.............................................. 9,949,624 13,964,783 27,460,250
----------- ----------- -----------
OPERATING INCOME............................................ 1,279,895 1,258,311 1,879,134
----------- ----------- -----------
OTHER INCOME (EXPENSE):
Gain (loss) on AOL Time Warner investment................. -- 2,452,406 (204,969)
(Loss) gain on indexed debt securities.................... (1,176,211) (629,523) 101,851
(Loss) income of equity investment of unconsolidated
subsidiaries............................................ (601) (793) 42,860
Other, net................................................ 67,619 59,766 83,765
----------- ----------- -----------
Total.............................................. (1,109,193) 1,881,856 23,507
----------- ----------- -----------
INTEREST AND OTHER CHARGES:
Interest.................................................. 502,432 498,451 700,083
Distribution on trust preferred securities................ 29,201 51,220 54,358
----------- ----------- -----------
Total.............................................. 531,633 549,671 754,441
----------- ----------- -----------
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES, EXTRAORDINARY ITEMS AND PREFERRED DIVIDENDS........ (360,931) 2,590,496 1,148,200
Income Tax (Benefit) Expense................................ (82,563) 915,973 377,064
----------- ----------- -----------
(LOSS) INCOME FROM CONTINUING OPERATIONS BEFORE
EXTRAORDINARY ITEMS AND PREFERRED DIVIDENDS............... (278,368) 1,674,523 771,136
Income (loss) from discontinued operations (net of tax of
$(52,131), $16,856 and $45,721)........................... 137,276 (8,792) (172,375)
Loss on disposal of discontinued operations, including
provision of $4,843 for operating loss during phase-out
period (less applicable tax of $12,846)................... -- -- (158,706)
Extraordinary (loss) gain, net of tax of $98,679 and $0..... -- (183,261) 7,445
----------- ----------- -----------
(LOSS) INCOME BEFORE PREFERRED DIVIDENDS.................... (141,092) 1,482,470 447,500
Preferred Dividends......................................... 390 389 389
----------- ----------- -----------
NET (LOSS) INCOME ATTRIBUTABLE TO COMMON STOCKHOLDERS....... $ (141,482) $ 1,482,081 $ 447,111
=========== =========== ===========
BASIC (LOSS) EARNINGS PER SHARE:
(Loss) Income from Continuing Operations Before
Extraordinary Items..................................... $ (0.98) $ 5.87 $ 2.71
Income (Loss) from Discontinued Operations, net of tax.... 0.48 (0.03) (0.61)
Loss on Disposal of Discontinued Operations, net of tax... -- -- (0.56)
Extraordinary (Loss) Gain, net of tax..................... -- (0.64) 0.03
----------- ----------- -----------
Net (Loss) Income Attributable to Common Stockholders..... $ (0.50) $ 5.20 $ 1.57
=========== =========== ===========
DILUTED (LOSS) EARNINGS PER SHARE:
(Loss) Income from Continuing Operations Before
Extraordinary Items..................................... $ (0.98) $ 5.85 $ 2.68
Income (Loss) from Discontinued Operations, net of tax.... 0.48 (0.03) (0.60)
Loss on Disposal of Discontinued Operations, net of tax... -- -- (0.55)
Extraordinary (Loss) Gain, net of tax..................... -- (0.64) 0.03
----------- ----------- -----------
Net (Loss) Income Attributable to Common Stockholders..... $ (0.50) $ 5.18 $ 1.56
=========== =========== ===========
See Notes to the Company's Consolidated Financial Statements
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1999 2000
--------- ---------- --------
Net (loss) income attributable to common stockholders.... $(141,482) $1,482,081 $447,111
Foreign currency translation adjustments from continuing
operations............................................. -- (587) (1,220)
Foreign currency translation adjustments from
discontinued
operations (net of tax of $17,656, $23,143 and
$16,371)............................................... (32,790) (42,392) (30,405)
Reclassification adjustment for foreign currency
translation losses realized in net income (net of tax
of $57,296)............................................ -- -- 106,408
Unrealized loss on available-for-sale securities (net of
tax of $5,877, $373 and $1,492)........................ (10,370) (1,224) (2,264)
Reclassification adjustment for impairment loss on
available-for-sale securities realized in net income
(net of tax of $9,276)................................. -- -- 17,228
Additional minimum non-qualified pension liability
adjustment (net of tax of $11,127)..................... -- -- (19,135)
--------- ---------- --------
Comprehensive (Loss) Income.............................. $(184,642) $1,437,878 $517,723
========= ========== ========
See Notes to the Company's Consolidated Financial Statements
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31,
-------------------------
1999 2000
----------- -----------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 80,767 $ 175,972
Investment in AOL Time Warner common stock................ 3,979,461 896,824
Accounts receivable, net.................................. 1,078,736 2,623,492
Accrued unbilled revenues................................. 172,629 592,618
Inventory................................................. 340,459 483,213
Price risk management assets.............................. 722,429 4,460,843
Margin deposits on energy trading activities.............. 33,721 521,004
Prepayments and other current assets...................... 128,194 253,335
----------- -----------
Total current assets............................... 6,536,396 10,007,301
----------- -----------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 13,133,559 15,260,155
----------- -----------
OTHER ASSETS:
Goodwill and other intangibles, net....................... 3,041,751 3,080,707
Regulatory assets......................................... 1,739,507 1,926,103
Price risk management assets.............................. 173,590 752,186
Equity investments in unconsolidated subsidiaries......... 78,041 108,727
Net assets of discontinued operations..................... 1,078,185 194,858
Other..................................................... 675,437 746,709
----------- -----------
Total other assets................................. 6,786,511 6,809,290
----------- -----------
TOTAL ASSETS....................................... $26,456,466 $32,076,746
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Short-term borrowings..................................... $ 2,876,311 $ 5,004,494
Current portion of long-term debt......................... 4,354,230 1,623,202
Accounts payable.......................................... 1,025,245 3,077,926
Taxes accrued............................................. 215,680 172,449
Interest accrued.......................................... 115,192 103,489
Dividends declared........................................ 110,811 110,893
Price risk management liabilities......................... 718,228 4,442,811
Margin deposits from customers on energy trading
activities.............................................. 3,800 284,603
Accumulated deferred income taxes......................... 415,591 309,008
Business purchase obligation.............................. 431,570 --
Other..................................................... 348,041 610,379
----------- -----------
Total current liabilities.......................... 10,614,699 15,739,254
----------- -----------
OTHER LIABILITIES:
Accumulated deferred income taxes......................... 2,541,109 2,548,891
Unamortized investment tax credit......................... 270,243 265,737
Price risk management liabilities......................... 142,305 737,540
Benefit obligations....................................... 394,550 491,964
Business purchase obligation.............................. 596,303 --
Other..................................................... 1,017,010 1,109,850
----------- -----------
Total other liabilities............................ 4,961,520 5,153,982
----------- -----------
LONG-TERM DEBT.............................................. 4,868,643 4,996,095
----------- -----------
COMMITMENTS AND CONTINGENCIES (NOTE 14)
COMPANY OBLIGATED MANDATORILY REDEEMABLE PREFERRED
SECURITIES OF SUBSIDIARY TRUSTS HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OF THE COMPANY.................... 705,272 705,355
----------- -----------
STOCKHOLDERS' EQUITY........................................ 5,306,332 5,482,060
----------- -----------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY......... $26,456,466 $32,076,746
=========== ===========
See Notes to the Company's Consolidated Financial Statements
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31,
---------------------------------------
1998 1999 2000
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net (loss) income attributable to common stockholders..... $ (141,482) $ 1,482,081 $ 447,111
Adjustments to reconcile net (loss) income to net cash
provided by operating activities:
Depreciation and amortization........................... 866,272 905,305 906,328
Deferred income taxes................................... (434,717) 625,211 (41,892)
Investment tax credit................................... (20,123) (58,706) (18,330)
(Gain) loss on AOL Time Warner investment............... -- (2,452,406) 204,969
Loss (gain) on indexed debt securities.................. 1,176,211 629,523 (101,851)
Extraordinary items..................................... -- 183,261 (7,445)
Undistributed losses (earnings) of unconsolidated
subsidiaries.......................................... 601 793 (24,931)
Proceeds from sale of debt securities................... -- -- 123,428
Impairment of marketable equity securities.............. -- -- 26,504
Net cash (used in) provided by discontinued
operations............................................ (184,567) (24,547) 437,620
Changes in other assets and liabilities:
Accounts receivable, net.............................. 129,943 (325,777) (1,933,033)
Inventory............................................. (138,237) 51,480 (74,603)
Federal tax refund.................................... 140,532 -- 86,155
Fuel cost over (under) recovery....................... 125,104 73,567 (515,278)
Margin deposits on energy trading activities, net..... 42,630 (59,467) (206,480)
Accounts payable...................................... (98,249) 206,409 2,040,724
Other assets.......................................... (131,050) (71,259) (302,588)
Other liabilities..................................... 61,774 (89,417) 229,138
Other, net.............................................. 32,426 33,487 70,078
----------- ----------- -----------
Net cash provided by operating activities.......... 1,427,068 1,109,538 1,345,624
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures...................................... (712,492) (1,165,639) (1,842,385)
Business acquisitions, net of cash acquired............... (292,398) (1,060,000) (2,121,481)
Proceeds from sale-leaseback transactions................. -- -- 1,000,000
Payment of a business purchase obligation................. -- -- (981,789)
Investment in AOL Time Warner securities.................. -- (537,055) --
Investments in unconsolidated subsidiaries................ (40,928) (36,582) (5,755)
Net cash (used in) provided by discontinued operations.... (189,656) (55,100) 641,768
Other, net................................................ (2,677) (21,543) 21,824
----------- ----------- -----------
Net cash used in investing activities.............. (1,238,151) (2,875,919) (3,287,818)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt, net......................... 1,267,107 2,060,680 1,092,373
Payments of long-term debt................................ (697,714) (935,908) (678,709)
Proceeds from sale of trust preferred securities, net..... -- 362,994 --
(Decrease) increase in short-term borrowings, net......... (314,717) 822,468 2,170,314
Proceeds from sale of common stock........................ 4,542 30,452 53,809
Payment of common stock dividends......................... (426,265) (427,255) (426,859)
Purchase of treasury stock................................ -- (90,708) (27,306)
Net cash (used in) provided by discontinued operations.... (10,555) 400 (120,173)
Other, net................................................ (28,090) (204) (31,138)
----------- ----------- -----------
Net cash (used in) provided by financing
activities....................................... (205,692) 1,822,919 2,032,311
----------- ----------- -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH..................... -- -- 5,088
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS........ (16,775) 56,538 95,205
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR.............. 41,004 24,229 80,767
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR.................... $ 24,229 $ 80,767 $ 175,972
=========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized)................... $ 502,889 $ 504,821 $ 786,660
Income taxes............................................ 472,609 401,703 496,603
See Notes to the Company's Consolidated Financial Statements
78
84
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY
(THOUSANDS OF DOLLARS AND SHARES)
1998 1999 2000
-------------------- -------------------- --------------------
SHARES AMOUNT SHARES AMOUNT SHARES AMOUNT
------- ---------- ------- ---------- ------- ----------
PREFERENCE STOCK, NONE OUTSTANDING.... -- $ -- -- $ -- -- $ --
------- ---------- ------- ---------- ------- ----------
CUMULATIVE PREFERRED STOCK
Balance, beginning of year.......... 97 9,740 97 9,740 97 9,740
------- ---------- ------- ---------- ------- ----------
Balance, end of year................ 97 9,740 97 9,740 97 9,740
------- ---------- ------- ---------- ------- ----------
COMMON STOCK, NO PAR; AUTHORIZED
700,000,000 SHARES
Balance, beginning of year.......... 295,357 3,112,098 296,271 3,136,826 297,612 3,182,751
Issuances related to benefit and
investment plans.................. 914 24,734 1,341 46,062 2,302 74,447
Other............................... -- (6) -- (137) -- (8)
------- ---------- ------- ---------- ------- ----------
Balance, end of year................ 296,271 3,136,826 297,612 3,182,751 299,914 3,257,190
------- ---------- ------- ---------- ------- ----------
TREASURY STOCK
Balance, beginning of year.......... (93) (2,066) (103) (2,384) (3,625) (93,296)
Shares acquired..................... -- -- (3,524) (90,708) (1,184) (27,306)
Other............................... (10) (318) 2 (204) (2) (254)
------- ---------- ------- ---------- ------- ----------
Balance, end of year................ (103) (2,384) (3,625) (93,296) (4,811) (120,856)
------- ---------- ------- ---------- ------- ----------
UNEARNED ESOP STOCK
Balance, beginning of year.......... (12,389) (229,827) (11,674) (217,780) (10,679) (199,226)
Issuances related to benefit plan... 715 12,047 995 18,554 2,040 38,068
------- ---------- ------- ---------- ------- ----------
Balance, end of year................ (11,674) (217,780) (10,679) (199,226) (8,639) (161,158)
------- ---------- ------- ---------- ------- ----------
RETAINED EARNINGS
Balance, beginning of year.......... 2,013,055 1,445,081 2,500,181
Net (loss) income................... (141,482) 1,482,081 447,111
Common stock dividends -- $1.50 per
share............................. (426,492) (426,981) (426,942)
---------- ---------- ----------
Balance, end of year................ 1,445,081 2,500,181 2,520,350
---------- ---------- ----------
ACCUMULATED OTHER COMPREHENSIVE LOSS
Balance, beginning of year.......... (6,455) (49,615) (93,818)
Foreign currency translation
adjustments from continuing
operations........................ -- (587) (1,220)
Foreign currency translation
adjustments from discontinued
operations........................ (32,790) (42,392) (30,405)
Reclassification adjustment for
foreign currency translation
losses realized in net income..... -- -- 106,408
Unrealized loss on
available-for-sale securities..... (10,370) (1,224) (2,264)
Reclassification adjustment for
impairment loss on
available-for-sale securities
realized in net income............ -- -- 17,228
Additional minimum non-qualified
pension liability adjustment...... -- -- (19,135)
---------- ---------- ----------
Balance, end of year................ (49,615) (93,818) (23,206)
---------- ---------- ----------
Total Stockholders' Equity........ $4,321,868 $5,306,332 $5,482,060
========== ========== ==========
See Notes to the Company's Consolidated Financial Statements
79
85
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
Reliant Energy, Incorporated (Reliant Energy), formerly Houston Industries
Incorporated, together with its subsidiaries (collectively, the Company), is a
diversified international energy services company that provides energy and
energy services in North America and Western Europe. Reliant Energy is both an
electric utility company and a utility holding company.
The Company's financial reporting segments include the following: Electric
Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy,
European Energy, and Other Operations. Electric Operations includes the
operations of Reliant Energy HL&P, an electric utility. Natural Gas Distribution
consists of intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers and some non-rate regulated
retail gas marketing operations. Pipelines and Gathering includes the interstate
natural gas pipeline operations and the natural gas gathering and pipelines
services businesses. Wholesale Energy is engaged in the acquisition, development
and operation of non-rate regulated power generation facilities as well as the
wholesale energy trading, marketing, power origination and risk management
services in North America. European Energy is engaged in the operation of power
generation facilities in the Netherlands as well as wholesale energy trading and
marketing operations in Western Europe. Other Operations includes unallocated
general corporate expenses, unregulated retail electric operations, a
communications business, an eBusiness group and non-operating investments.
Effective December 1, 2000, Reliant Energy's Board of Directors approved a
plan to dispose of the Latin America business segment through sales of its Latin
American assets. Accordingly, the Company is reporting the results of the
Company's Latin America business segment as discontinued operations for all
periods presented in the Consolidated Financial Statements in accordance with
Accounting Principles Board Opinion No. 30. For information regarding the
disposal of the Latin America business segment, see Note 19.
On July 27, 2000, Reliant Energy announced its intention to form a company,
Reliant Resources, Inc. (Reliant Resources), to own and operate a substantial
portion of the Company's unregulated operations and to offer no more than 20% of
the common stock of Reliant Resources in an initial public offering (Offering).
Reliant Energy expects the Offering to be followed by a distribution to Reliant
Energy's or its successor's shareholders of the remaining common stock of
Reliant Resources (Distribution) within twelve months of the Offering. For
additional information, see Note 4(b).
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Reclassifications and Use of Estimates.
Some amounts from the previous years have been reclassified to conform to
the 2000 presentation of financial statements. These reclassifications do not
affect earnings.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
(b) Market Risk and Uncertainties.
The Company is subject to the risk associated with price movements of
energy commodities and the credit risk associated with the Company's risk
management activities. For additional information regarding these risks, see
Note 5. The Company is also subject to risks relating to the supply and prices
of fuel and electricity, seasonal weather patterns, technological obsolescence
and the regulatory environment in the United States and Western Europe.
80
86
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(c) Principles of Consolidation.
The accounts of Reliant Energy and its wholly owned and majority owned
subsidiaries are included in the Consolidated Financial Statements. All
significant intercompany transactions and balances are eliminated in
consolidation. The Company accounts for investments in entities in which the
Company has an ownership interest between 20% and 50% and exercises significant
influence using the equity method of accounting. For additional information
regarding investments recorded using the equity method of accounting, see Note
7. Other investments, excluding marketable securities, are generally carried at
cost.
(d) Revenues.
The Company records revenue for electricity and natural gas sales and
services under the accrual method and these revenues are generally recognized
upon delivery. Pipelines and Gathering record revenues as transportation
services are provided. Energy sales and services not billed by month-end are
accrued based upon estimated energy and services delivered. Domestic non-rate
regulated electric power and other non-rate regulated energy services are sold
at market-based prices through existing power exchanges or through third-party
contracts. Energy revenues related to the Company's power generation facilities
in Europe were generated under a regulated pricing structure, which includes
compensation for the cost of fuel, capital and operation and maintenance
expenses. The electric generation market in the Netherlands opened to wholesale
competition on January 1, 2001. The Company's energy trading and marketing
operations are accounted for under mark-to-market accounting as discussed in
Note 5.
(e) Long-lived Assets and Intangibles.
The Company records property, plant and equipment at historical cost. The
Company recognizes repair and maintenance costs incurred in connection with
planned major maintenance, such as turbine and generator overhauls, control
system upgrades and air conditioner replacements, under the "accrual in advance"
method for its non-rate regulated power generation operations acquired or
developed prior to December 31, 1999. Planned major maintenance cycles primarily
range from two to ten years. Under the accrual in advance method, the Company
estimates the costs of planned major maintenance and accrues the related expense
over the maintenance cycle. As of December 31, 1999 and 2000, the Company's
maintenance reserve was $48 million and $27 million, respectively, of which $46
million and $20 million, respectively, were included in other long-term
liabilities and the remainder in other current liabilities. The Company expenses
all other repair and maintenance costs as incurred. Property, plant and
equipment includes the following:
DECEMBER 31,
ESTIMATED USEFUL -----------------
LIVES (YEARS) 1999 2000
---------------- ------- -------
(IN MILLIONS)
Electric................................................... 1-58 $16,598 $18,754
Natural gas distribution................................... 5-50 1,696 1,809
Pipelines and gathering.................................... 5-75 1,555 1,582
Other property............................................. 3-40 140 247
------- -------
Total............................................ 19,989 22,392
Accumulated depreciation................................... (6,855) (7,132)
------- -------
Property, plant and equipment, net............... $13,134 $15,260
======= =======
81
87
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Goodwill is amortized
on a straight-line basis over 10 to 40 years. See Note 3 and the following table
for additional information regarding goodwill and the related amortization
periods.
DECEMBER 31,
ESTIMATED USEFUL ---------------
LIVES (YEARS) 1999 2000
---------------- ------ ------
(IN MILLIONS)
Reliant Energy Resources Corp. (RERC Corp.)................. 40 $2,112 $2,086
Reliant Energy Mid-Atlantic Power Holdings, LLC............. 35 -- 7
N.V. UNA.................................................... 30 897 897
Other....................................................... 10-35 112 136
------ ------
Total............................................. 3,121 3,126
Accumulated amortization.................................... (136) (222)
Foreign currency exchange impact............................ (61) (107)
------ ------
Total Goodwill, net............................... $2,924 $2,797
====== ======
The Company recognizes specifically identifiable intangibles, including air
emissions regulatory allowances, water rights and permits, when specific rights
and contracts are acquired. As of December 31, 1999 and 2000, specific
intangibles were $118 million and $284 million, respectively. The Company
amortizes air emissions regulatory allowances primarily on a units-of-production
basis as utilized. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range between 20 and 35 years.
The Company periodically evaluates long-lived assets, including property,
plant and equipment, goodwill and specifically identifiable intangibles, when
events or changes in circumstances indicate that the carrying value of these
assets may not be recoverable. The determination of whether an impairment has
occurred is based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. To date, no impairment
has been indicated, except as discussed in Note 4(a).
(f) Regulatory Assets.
The Company applies the accounting policies established in Statement of
Financial Accounting Standards (SFAS) No. 71 (SFAS No. 71) to the accounts of
transmission and distribution operations of Reliant Energy HL&P and the utility
operations of Natural Gas Distribution and to some of the accounts of Pipelines
and Gathering. For information regarding Reliant Energy HL&P's electric
generation operations' discontinuance of the application of SFAS No. 71 in 1999
and the effect on its regulatory assets and the Texas Electric Choice Plan
(Legislation), see Note 4(a).
The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 1999 and 2000.
DECEMBER 31,
---------------
1999 2000
------ ------
(IN MILLIONS)
Recoverable impaired plant costs, net....................... $ 587 $ 281
Recoverable electric generation related regulatory assets,
net....................................................... 952 1,385
Regulatory tax liability, net............................... (45) (49)
Unamortized loss on reacquired debt......................... 69 66
Other long-term assets/liabilities.......................... (14) 6
------ ------
Total............................................. $1,549 $1,689
====== ======
82
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Included in the above table are $191 million and $237 million of regulatory
liabilities recorded as other long-term liabilities in the Company's
Consolidated Balance Sheets as of December 31, 1999 and 2000, respectively,
which primarily relate to the recovery of fuel costs as of December 31, 1999,
and gains on nuclear decommissioning trust funds, regulatory tax liabilities and
excess deferred income taxes as of December 31, 1999 and 2000.
Under a "deferred accounting" plan authorized by the Public Utility
Commission of Texas (Texas Utility Commission), Electric Operations was
permitted for regulatory purposes to accrue carrying costs in the form of
allowance for funds used during construction (AFUDC) on its investment in the
South Texas Project Electric Generating Station (South Texas Project) and to
defer and capitalize depreciation and other operating costs on its investment
after commercial operation until these costs were reflected in rates. In
addition, the Texas Utility Commission authorized Electric Operations to defer
allowable costs (including return) for future recovery. Pursuant to SFAS No. 92,
"Regulated Enterprises -- Accounting for Phase-in Plans," the Company deferred
these costs. These costs are included in recoverable electric generation related
regulatory assets. The amortization of all deferred plant costs (which totaled
$26 million for 1998) is included in the Company's Statements of Consolidated
Operations as depreciation and amortization expense. Pursuant to the
Legislation, see Note 4(a), the Company discontinued amortizing deferred plant
costs effective January 1, 1999.
In 1998, 1999 and 2000, the Company, as permitted by the 1995 rate case
settlement (Rate Case Settlement), also amortized $4 million, $22 million and
$11 million, respectively, of its investment in lignite reserves associated with
a canceled generating station. The investment in these reserves was fully
amortized during 2000.
For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets and the related amortization
during 1999 and 2000, see Notes 2(g) and 4(a).
If, as a result of changes in regulation or competition, the Company's
ability to recover these assets and liabilities would not be assured, then
pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the
Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
be Disposed Of" (SFAS No. 121), the Company would be required to write off or
write down these regulatory assets and liabilities. In addition, the Company
would be required to determine any impairment to the carrying costs of plant and
inventory assets.
(g) Depreciation and Amortization Expense.
Depreciation is computed using the straight-line method based on economic
lives or a regulatory mandated method. Depreciation for 1998, 1999 and 2000 was
$558 million, $547 million and $391 million, respectively. Amortization of
goodwill for the same periods was $55 million, $62 million and $86 million,
respectively. Other amortization expense, including amortization of regulatory
assets and air emissions regulatory allowances and other intangibles, was $253
million, $296 million and $429 million in 1998, 1999 and 2000, respectively.
For information regarding amortization of deferred plant costs, investments
in lignite reserves and amortization of recoverable impaired plant costs
included in regulatory assets in the Company's Consolidated Balance Sheets, see
Notes 2(f) and 4(a).
In June 1998, the Texas Utility Commission issued an order approving a
transition to competition plan (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 permitted 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 provided that all earnings above a
stated overall annual rate of return on invested capital be used to recover
Electric Operations'
83
89
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
investment in generation assets. Electric Operations implemented the Transition
Plan effective January 1, 1998 and pursuant to its terms, recorded an aggregate
of $104 million in additional depreciation and $99 million in redirected
depreciation for the first six months in 1999 and $194 million in additional
depreciation and $195 million in redirected depreciation in 1998. Due to the
discontinuance of SFAS No. 71 to Electric Operations' generation operations, the
provisions for additional and redirected depreciation of the Transition Plan are
no longer applied effective June 30, 1999. For additional information regarding
the discontinuance of SFAS No. 71 to the Electric Operations' generation
operations and the related legislation, see Note 4(a).
Pursuant to the Legislation, the Company is allowed to recover the
generation related regulatory assets recorded as of December 31, 1998.
Therefore, the Company discontinued amortizing some generation related
regulatory assets effective as of January 1, 1999.
In connection with the discontinuation of SFAS No. 71 in June 1999, the
Company reassessed the economic lives of Reliant Energy HL&P's generation plant
and equipment in the fourth quarter of 1999. Some prospective depreciation rates
were revised as a result of the Legislation. These changes in depreciation rates
reduced depreciation expense for Reliant Energy HL&P's generation plant and
equipment by $40 million in 2000. The effect on both basic and diluted earnings
per share for 2000 was $0.09.
(h) Capitalization of Interest.
Interest and AFUDC related to debt for subsidiaries that apply SFAS No. 71
are capitalized as a component of projects under construction and will be
amortized over the assets' estimated useful lives. During 1998, 1999 and 2000,
the Company capitalized interest and AFUDC related to debt of $6 million, $19
million and $45 million, respectively.
(i) Income Taxes.
The Company files a consolidated federal income tax return. The Company
follows a policy of comprehensive interperiod income tax allocation. The Company
uses the liability method of accounting for deferred income taxes and measures
deferred income taxes for all significant income tax temporary differences.
Investment tax credits were deferred and are being amortized over the estimated
lives of the related property. Unremitted earnings from the Company's foreign
operations are deemed to be permanently reinvested in foreign operations. For
additional information regarding income taxes, see Note 13.
(j) Allowance for Doubtful Accounts.
Accounts receivable, principally from customers, are net of an allowance
for doubtful accounts of $34 million and $105 million at December 31, 1999 and
2000, respectively. The provision for doubtful accounts in the Company's
Statements of Consolidated Operations for 1998, 1999 and 2000 was $21 million,
$16 million and $95 million, respectively. For information regarding the
provision against receivable balances related to energy sales in the California
market, see Note 14(h).
(k) Inventory.
Inventory consists principally of materials and supplies, coal and lignite,
natural gas and heating oil. Inventories used in the production of electricity
and in the retail natural gas distribution operations are valued at the lower of
average cost or market except for coal and lignite, which are valued under the
last-in, first-out
84
90
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
method. Heating oil and natural gas used in the trading and marketing operations
are accounted for under mark-to-market accounting as discussed in Note 5. Below
is a detail of inventory:
DECEMBER 31,
-------------
1999 2000
----- -----
(IN MILLIONS)
Materials and supplies...................................... $188 $270
Coal and lignite............................................ 46 59
Natural gas................................................. 93 107
Heating oil................................................. 13 47
---- ----
Total inventory................................... $340 $483
==== ====
(l) Investment in Other Debt and Equity Securities.
In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value in the Company's
Consolidated Balance Sheets and any unrealized gain or loss, net of tax, as a
separate component of stockholders' equity and accumulated other comprehensive
income (loss). In accordance with SFAS No. 115, the Company reports "trading"
securities at estimated fair value in the Company's Consolidated Balance Sheets,
and any unrealized holding gains and losses are recorded as other income
(expense) in the Company's Statements of Consolidated Operations.
As of December 31, 1999 and 2000, the Company held "available-for-sale"
debt and equity securities in its nuclear decommissioning trust, which is
reported at its fair value of $145 million and $159 million, respectively, in
the Company's Consolidated Balance Sheets in other long-term assets. Any
unrealized losses or gains are accounted for in accordance with SFAS No. 71 as a
regulatory asset/liability.
In addition, as of December 31, 1999 and 2000, the Company held marketable
equity securities of $9 million and $5 million, respectively, classified as
"available-for-sale." At December 31, 1999 and 2000, the accumulated unrealized
loss, net of tax, relating to these equity securities was $17 million and $2
million, respectively. During 2000, pursuant to SFAS No. 115, the Company
incurred a pre-tax impairment loss equal to the $27 million of cumulative
unrealized losses for these securities, which was recorded in other income
(expense) in the Company's Statement of Consolidated Operations. Management's
determination to recognize this impairment resulted from a combination of events
occurring in 2000 related to this investment. These events affecting the
investment included changes occurring in the investment's senior management,
announcement of significant restructuring charges and related downsizing for the
entity, reduced earnings estimates for this entity by brokerage analysts and the
bankruptcy of a competitor of the investment in the first quarter of 2000. These
events, coupled with the stock market value of the Company's investment in these
securities continuing to be below the Company's cost basis, caused management to
believe the decline in fair value of these "available-for-sale" securities to be
other than temporary.
As of December 31, 1999 and 2000, the Company held an investment in Time
Warner Inc. (now AOL Time Warner, Inc.) common stock, which was classified as a
"trading" security. For information regarding the Company's investment in AOL
Time Warner, Inc. common stock, see Note 8.
As of December 31, 1999, the Company held $129 million of debt securities
that were classified as "trading." This investment was recorded in other assets
in the Company's Consolidated Balance Sheets as of December 31, 1999. In
addition, as of December 31, 1999, the Company held $14 million of other equity
securities that were classified as "trading." The Company held no investments
classified as "trading" as of December 31, 2000, except as discussed above. For
these securities, the Company recorded unrealized holding gains in other income
in the Company's Statements of Consolidated Operations of $7 million and $6
million for 1999 and 2000, respectively. No unrealized gains or losses on
"trading" securities were recorded in 1998.
85
91
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(m) Project Development Costs.
Project development costs include costs for professional services, permits
and other items that are incurred incidental to a particular project. The
Company expenses these costs as incurred until the project is considered
probable. After a project is considered probable, capitalizable costs incurred
are capitalized to the project. When project operations begin, the Company
begins to amortize these costs on a straight-line basis over the life of the
facility. As of December 31, 1999 and 2000, the Company had recorded in the
Company's Consolidated Balance Sheets project development costs of $3 million
and $7 million, respectively.
(n) Environmental Costs.
The Company expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. The Company expenses
amounts that relate to an existing condition caused by past operations, and that
do not have future economic benefit. The Company records undiscounted
liabilities related to these future costs when environmental assessments and/or
remediation activities are probable and the costs can be reasonably estimated.
Subject to SFAS No. 71, a corresponding regulatory asset is recorded in
anticipation of recovery through the rate making process by subsidiaries that
apply SFAS No. 71 in some circumstances.
(o) Foreign Currency Adjustments.
Local currencies are the functional currency of the Company's foreign
continuing operations. Foreign subsidiaries' assets and liabilities have been
translated into U.S. dollars using the exchange rate at the balance sheet date.
Revenues, expenses, gains and losses have been translated using the weighted
average exchange rate for each month prevailing during the periods reported.
Cumulative adjustments resulting from translation have been recorded in
stockholders' equity in other comprehensive income (loss).
(p) Statements of Consolidated Cash Flows.
For purposes of reporting cash flows, the Company considers cash
equivalents to be short-term, highly liquid investments readily convertible to
cash.
(q) Changes in Accounting Principles.
In March 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." This statement
requires capitalization of some costs of internal-use software. The Company
adopted SOP 98-1 in the second quarter of 1998 without a material impact on the
Company's results of operations or financial position.
The AICPA's SOP 98-5, "Reporting on the Costs of Start-Up Activities," was
adopted by the Company in the fourth quarter of 1998. This statement requires
that certain costs of start-up activities and organizational costs be expensed
as incurred. The adoption of SOP 98-5 did not have a material impact on the
Company's results of operations or financial position.
The Company adopted Emerging Issues Task Force Issue (EITF) 98-10,
"Accounting for Contracts Involved in Energy Trading and Risk Management
Activities" (EITF 98-10), on January 1, 1999. The adoption of EITF 98-10 had no
material impact on the Company's results of operations or financial position.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the Securities and Exchange Commission (SEC) on December 3, 1999. SAB
No. 101 summarizes certain of the SEC staff's views in applying generally
accepted accounting principles to revenue recognition in financial
86
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
statements. During 2000, the Company implemented SAB No. 101 without a material
impact on the Company's results of operations or financial position.
(r) New Accounting Pronouncements.
Effective January 1, 2001, the Company was required to adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS
No. 133), which establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities. This statement requires that derivatives
be recognized at fair value in the balance sheet and that changes in fair value
be recognized either currently in earnings or deferred as a component of other
comprehensive income, depending on the intended use of the derivative, its
resulting designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board (FASB) issued an amendment that narrows the
applicability of the pronouncement to some purchase and sales contracts and
allows hedge accounting for some other specific hedging relationships. Adoption
of SFAS No. 133 resulted in an after-tax increase in net income of $62 million
and a cumulative after-tax increase in accumulated other comprehensive loss of
$252 million in the first quarter of 2001. The adoption also increased current
assets, long-term assets, current liabilities and long-term liabilities by $703
million, $252 million, $805 million and $340 million, respectively, in the
Company's Consolidated Balance Sheet. The Company will also reclassify $788
million from the current portion of long-term debt to other current liabilities
due to the adoption. For information regarding the effect of adoption of SFAS
No. 133 on the Company's indexed debt obligation, see Note 8(c).
The total impact of our adoption of SFAS No. 133 on earnings and
accumulated other comprehensive loss is dependent upon certain pending
interpretations, which are currently under consideration, including those
related to the "normal purchases and normal sales." The interpretations of this
issue, and others, are currently under consideration by the FASB. While the
ultimate conclusions reached on interpretations being considered by the FASB
could impact the effects of its adoption of SFAS No. 133, the Company does not
believe that such conclusions would have a material effect on its current
estimate of the impact of the adoption.
(3) BUSINESS ACQUISITIONS
(a) Reliant Energy Mid-Atlantic Power Holdings, LLC.
On May 12, 2000, a subsidiary of the Company purchased entities owning
electric power generating assets and development sites located in Pennsylvania,
New Jersey and Maryland having an aggregate net generating capacity of
approximately 4,262 megawatts (MW). With the exception of development entities
that were sold to another subsidiary of the Company in July 2000, the assets of
the entities acquired are held by Reliant Energy Mid-Atlantic Power Holdings,
LLC (REMA). The purchase price for the May 2000 transaction was $2.1 billion,
subject to post-closing adjustments which management does not believe will be
material. The Company accounted for the acquisition as a purchase with assets
and liabilities of REMA reflected at their estimated fair values. On a
preliminary basis, the Company's fair value adjustments related to the
acquisition primarily included adjustments in property, plant and equipment, air
emissions regulatory allowances, materials and supplies inventory, environmental
reserves and related deferred taxes. The air emissions regulatory allowances of
$153 million are being amortized on a units-of-production basis as utilized. The
excess of the purchase price over the fair value of net assets acquired of $7
million was recorded as goodwill and is being amortized over 35 years. The
Company expects to finalize these fair value adjustments no later than May 2001,
based on valuation reports of property, plant and equipment and intangible
assets, and does not anticipate additional material modifications to the
preliminary adjustments. Funds for the acquisition of REMA were made available
through commercial paper borrowings by a finance subsidiary, which borrowings
were supported by bank credit facilities.
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The net purchase price of REMA was allocated and the fair value adjustments
to the seller's book value are as follows (in millions):
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
Current assets.............................................. $ 75 $ (37)
Property, plant and equipment............................... 1,941 670
Goodwill.................................................... 7 (144)
Other intangibles........................................... 153 (10)
Other assets................................................ 4 (4)
Current liabilities......................................... (45) (8)
Other liabilities........................................... (38) (14)
------ -----
$2,097 $ 453
====== =====
Adjustments to property, plant and equipment, other intangibles, which
includes air emissions regulatory allowances, and environmental reserves
included in other liabilities are based primarily on valuation reports prepared
by independent appraisers and consultants.
In August 2000, the Company entered into separate sale/leaseback
transactions with each of three owner-lessors for the Company's 16.45%, 16.67%
and 100% interests in the Conemaugh, Keystone and Shawville generating stations,
respectively, acquired as part of the REMA acquisition. As lessee, the Company
leases an interest in each facility from each owner-lessor under a facility
lease agreement. As consideration for the sale of the Company's interest in the
facilities, the Company received $1.0 billion in cash. The Company used the $1.0
billion of sale proceeds to repay commercial paper referred to above.
The Company's results of operations include the results of REMA only for
the period beginning May 12, 2000. Prior to November 24, 1999, the acquired
entities' operations were fully integrated with, and their results of operations
were consolidated into, the regulated electric utility operations of a prior
owner of the facilities. In addition, prior to November 24, 1999, the electric
output of the facilities was sold based on rates set by regulatory authorities
and is not indicative of REMA's future results. The following table presents
selected actual financial information and unaudited pro forma information for
1999 and 2000, as if the acquisition had occurred on November 24, 1999 and
January 1, 2000, as applicable. Pro forma information prior to November 24, 1999
would not be meaningful since historical financial results of the business and
the revenue generating activities underlying that period as described above are
substantially different from the wholesale generation activities that REMA has
been engaged in after November 24, 1999. Pro forma amounts
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
also give effect to the sale and leaseback of interests in three of the REMA
generating plants, which were consummated in August 2000.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000
------------------- -------------------
UNAUDITED UNAUDITED
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues............................................. $15,223 $15,253 $29,339 $29,506
Income from continuing operations before
extraordinary items................................ 1,674 1,664 771 762
Net income attributable to common stockholders....... 1,482 1,472 447 438
Basic earnings per share from continuing operations
before extraordinary items......................... 5.87 5.84 2.71 2.68
Diluted earnings per share from continuing operations
before extraordinary items......................... 5.85 5.82 2.68 2.65
Basic earnings per share............................. 5.20 5.16 1.57 1.54
Diluted earnings per share........................... 5.18 5.15 1.56 1.53
These unaudited pro forma results, based on assumptions deemed appropriate
by the Company's management, have been prepared for informational purposes only
and are not necessarily indicative of the amounts that would have resulted if
the acquisition of the REMA entities had occurred on November 24, 1999 and
January 1, 2000, as applicable. Purchase-related adjustments to the results of
operations include the effects on depreciation and amortization, interest
expense and income taxes.
(b) N.V. UNA.
Effective October 7, 1999, the Company acquired N.V. UNA (UNA), a Dutch
electric generation company, for a total net purchase price, payable in Dutch
Guilders (NLG), of $1.9 billion based on an exchange rate on October 7, 1999 of
2.06 NLG per U.S. dollar. The aggregate purchase price paid in 1999 by the
Company consisted of $833 million in cash. On March 1, 2000, under the terms of
the acquisition agreement, the Company funded the remaining purchase obligation
for $982 million. The business purchase obligation was recorded in the Company's
Consolidated Balance Sheet as of December 31, 1999, based on the exchange rate
on December 31, 1999, of 2.19 NLG per U.S. dollar. A portion ($596 million) of
the business purchase obligation was classified as a non-current liability, as
this portion of the obligation was financed with a three-year term loan facility
obtained in the first quarter of 2000.
The Company recorded the UNA acquisition under the purchase method of
accounting, with assets and liabilities of UNA reflected at their estimated fair
values. As outlined in the table below, the Company's fair value adjustments
related to the acquisition of UNA primarily included increases in property,
plant and equipment, long-term debt, severance liabilities, post-employment
benefit liabilities and deferred foreign taxes. Additionally, a $19 million
receivable was recorded in connection with the acquisition as the selling
shareholders agreed to reimburse UNA for some obligations incurred prior to the
purchase of UNA. Adjustments to property, plant and equipment are based
primarily on valuation reports prepared by independent appraisers and
consultants. The excess of the purchase price over the fair value of net assets
acquired of $897 million was recorded as goodwill and will be amortized on a
straight-line basis over 30 years. The Company finalized these fair value
adjustments during September 2000. The Company finalized a severance plan (UNA
Plan) in connection with the UNA acquisition in September 2000 (commitment date)
and in accordance with EITF 95-3 "Recognition of Liabilities in Connection with
a Purchase Business Combination," recorded this liability of $19 million in the
third quarter of 2000. Payments under the UNA Plan will be primarily made in
mid-2001.
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
In connection with the acquisition of UNA, the Company developed a
comprehensive business process reengineering and employee severance plan
intended to make UNA competitive in the deregulated Dutch electricity market
that began January 1, 2001. The UNA Plan's initial conceptual formulation was
initiated prior to the acquisition of UNA in October 1999. The finalization of
the UNA Plan was approved and completed in September 2000. The Company
identified 195 employees who will be involuntarily terminated in UNA's following
functional areas: plant operations and maintenance, procurement, inventory,
general and administrative, legal, finance and support. The Company has notified
all employees identified under the severance component of the UNA Plan that they
are subject to involuntary termination and that the majority of terminations
will occur over a period not to exceed twelve months from the date of
finalization of the UNA Plan. The termination benefits under the UNA Plan are
governed by UNA's Social Plan, a collective bargaining agreement between UNA and
its various representative labor unions signed in 1998. The Social Plan provides
defined benefits for involuntarily severed employees, depending upon age, tenure
and other factors, and was agreed to by the management of UNA as a result of the
anticipated deregulation of the Dutch electricity market. The Social Plan is
still in force and binding on the current management of the Company and UNA. The
Company is currently executing the UNA Plan as of the date of these Consolidated
Financial Statements.
The net purchase price of UNA was allocated and the fair value adjustments
to the seller's book value are as follows (in millions):
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
Current assets.............................................. $ 229 $ 19
Property, plant and equipment............................... 1,899 719
Goodwill.................................................... 897 897
Current liabilities......................................... (336) --
Deferred taxes.............................................. (81) (81)
Long-term debt.............................................. (422) (87)
Other long-term liabilities................................. (244) (35)
------ ------
$1,942 $1,432
====== ======
The following table presents selected actual financial information for 1998
and 1999, and unaudited pro forma information for 1998 and 1999, as if the
acquisition of UNA had occurred on January 1, 1998 and 1999, respectively. The
unaudited pro forma results are based on assumptions deemed appropriate by the
Company's management, have been prepared for informational purposes only and are
not necessarily indicative of the consolidated results that would have resulted
if the acquisition of UNA had occurred on January 1, 1998 and 1999, as
applicable. Purchase related adjustments to results of operations include
amortization of goodwill,
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
interest expense and the effects on depreciation and amortization of the
assessed fair value of some of UNA's net assets and liabilities.
YEAR ENDED DECEMBER 31,
-----------------------------------------
1998 1999
------------------- -------------------
UNAUDITED UNAUDITED
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues............................................. $11,230 $12,062 $15,223 $15,704
Income from continuing operations before
extraordinary item................................. (278) (227) 1,674 1,648
Net (loss) income attributable to common
stockholders....................................... (141) (90) 1,482 1,455
Basic earnings per share from continuing operations
before extraordinary item.......................... (0.98) (0.80) 5.87 5.78
Diluted earnings per share from continuing operations
before extraordinary item.......................... (0.98) (0.80) 5.85 5.76
Basic earnings per share............................. (0.50) (0.32) 5.20 5.11
Diluted earnings per share........................... (0.50) (0.32) 5.18 5.09
(4) REGULATORY MATTERS
(a) Texas Electric Choice Plan and Discontinuance of SFAS No. 71 for Electric
Generation Operations.
In June 1999, the Texas legislature adopted the Legislation, which
substantially amended the regulatory structure governing electric utilities in
Texas in order to allow retail electric competition. Retail pilot projects for
up to 5% of each utility's load in all customer classes will begin in June 2001,
and retail electric competition for all other customers will begin on January 1,
2002. In preparation for that competition, the Company expects to make
significant changes in the electric utility operations it conducts through its
electric utility division, Reliant Energy HL&P. In addition, the Legislation
requires the Texas Utility Commission to issue a number of new rules and
determinations in implementing the Legislation.
The Legislation defines the process for competition and creates a
transition period during which most utility rates are frozen at rates not in
excess of their present levels. The Legislation provides for utilities to
recover their generation related stranded costs and regulatory assets (as
defined in the Legislation).
Retail Choice. Under the Legislation, on January 1, 2002, retail customers
of most investor owned electric utilities in Texas will be entitled to purchase
their electricity from any of a number of "retail electric providers," which
will have been certified by the Texas Utility Commission. Retail electric
providers will not own or operate generation assets and their sales rates will
not be subject to traditional cost-of-service rate regulation. Retail electric
providers that are affiliates of electric utilities may compete substantially
statewide for these sales, but rates they charge within the affiliated electric
utility's traditional service territory are subject to some limitations at the
outset of retail choice, as described below. The Texas Utility Commission will
prescribe regulations governing quality, reliability and other aspects of
service from retail electric providers. Transactions between the regulated
utility and its current and future competitive affiliates are subject to
regulatory scrutiny and must comply with a code of conduct established by the
Texas Utility Commission. The code of conduct governs interactions among
employees of regulated and current and future unregulated affiliates as well as
the exchange of information between these affiliates. The Company intends to
compete in the Texas retail market and, as a result, has certified two of its
subsidiaries as retail electric providers.
Unbundling. By January 1, 2002, electric utilities in Texas such as
Reliant Energy HL&P will restructure their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Legislation, the Company submitted a plan in January 2000
that
91
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
was later amended to accomplish the required separation (the Business Separation
Plan). For additional information regarding the Business Separation Plan, see
Note 4(b). The transmission and distribution business will continue to be
subject to cost-of-service rate regulation and will be responsible for the
delivery of electricity to retail customers.
Generation. Power generators will sell electric energy to wholesale
purchasers, including retail electric providers, at unregulated rates beginning
January 1, 2002. To facilitate a competitive market, each power generation
company affiliated with a transmission and distribution utility will be required
to sell at auction 15% of the output of its installed generating capacity. The
first auction will be held on or before September 1, 2001 for power delivered
after January 1, 2002. This obligation continues until January 1, 2007 unless
before that date the Texas Utility Commission determines at least 40% of the
quantity of electric power consumed in 2000 by residential and small commercial
load in the electric utility's service area is being served by retail electric
providers other than the affiliated retail electric provider. See Note 4(b) for
information regarding the capacity auctions and the effect of the Business
Separation Plan on the Company. The Legislation also creates a program mandating
air emissions reductions for non-permitted generating facilities. The Company
anticipates that any stranded costs associated with this obligation incurred
before May 1, 2003 will be recoverable through the stranded costs recovery
mechanisms contained in the Legislation.
Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 will
be frozen until January 1, 2002. Pursuant to Texas Utility Commission
regulations, effective January 1, 2002, retail rates charged to residential and
small commercial customers by the utility's affiliated retail electric provider
will be reduced by 6% from the average rates (on a bundled basis) in effect on
January 1, 1999 (adjusted for fuel charges). That reduced rate will be known as
the "price to beat" and will be charged by the affiliated retail electric
provider to residential and small commercial customers in the utility's service
area who have not elected service from another retail electric provider. The
affiliated retail electric provider may not offer different rates to residential
or small commercial customer classes in the utility's service area until the
earlier of the date the Texas Utility Commission determines that 40% of power
consumed by that class in the affiliated transmission and distribution utility's
service area is being served by non-affiliated retail electric providers or
January 1, 2005. In addition, the affiliated retail electric provider must make
the price to beat available to eligible consumers until January 1, 2007.
Stranded Costs. Reliant Energy HL&P will be entitled to recover its
stranded costs (i.e., the excess of net book value of generation assets (as
defined by the Legislation) over the market value of those assets) and its
regulatory assets related to generation. The Legislation prescribes specific
methods for determining the amount of stranded costs and the details for their
recovery. However, during the base rate freeze period from 1999 through 2001,
earnings above the utility's authorized return formula will be applied in a
manner to accelerate depreciation of generation related plant assets for
regulatory purposes. In addition, depreciation expense for transmission and
distribution related assets may be redirected to generation assets for
regulatory purposes during that period.
The Texas Utility Commission has recently stated on record that it would
consider requiring electric utilities to reverse the amount of redirected
depreciation and accelerated depreciation previously taken if in its estimation
the utility has overmitigated its stranded costs. The reversal could occur
through a lower rate for the transmission and distribution utility and/or
through credits contained in the transmission and distribution utility's rate.
Any order requiring the reversal of these amounts would likely be included in
the Texas Utility Commission proceeding establishing the initial rate of the
transmission and distribution utility. The Company does not expect the final
Reliant Energy HL&P transmission and distribution rate to be established until
August 2001. For information regarding redirected depreciation, see "Accounting"
in this Note 4(a).
The Legislation provides for Reliant Energy HL&P, or a special purpose
entity, to issue securitization bonds for the recovery of generation related
regulatory assets and a portion of stranded costs. These bonds will be sold to
third parties and will be amortized through non-bypassable charges to
transmission and distribution customers. Any stranded costs not recovered
through the securitization bonds will be recovered through a non-
92
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
bypassable charge to transmission and distribution customers. Costs associated
with nuclear decommissioning that have not been recovered as of January 1, 2002,
will continue to be subject to cost-of-service rate regulation and will be
included in a non-bypassable charge to transmission and distribution customers.
For further discussion of the effect of the Business Separation Plan on funding
of the nuclear decommissioning trust fund, see Note 4(b).
In May 2000, the Texas Utility Commission issued a financing order to the
Company authorizing the issuance of transition bonds in an amount not to exceed
$740 million plus actual up-front qualified costs. Payments on the transition
bonds will be made out of funds derived from non-bypassable transition charges
to Reliant Energy HL&P's transmission and distribution customers. The offering
of the transition bonds will be registered under the Securities Act of 1933 and
is expected to be consummated during 2001.
Capacity Auction True-up. In accordance with the Legislation, beginning on
January 1, 2002, and ending when the true-up proceeding is completed, any
difference between market power prices received in the generation capacity
auction and the Texas Utility Commission's earlier estimates of those market
prices will be included in the 2004 stranded costs true-up, as further discussed
below. This component of the true-up is intended to ensure that neither the
customers nor the Company are disadvantaged economically as a result of the
two-year transition period by providing this pricing structure. For information
regarding the effect of the Business Separation Plan on the generation capacity
auctions, see Note 4(b).
Accounting. Historically, Reliant Energy HL&P has applied the accounting
policies established in SFAS No. 71. In general, SFAS No. 71 permits a company
with cost-based rates to defer some costs that would otherwise be expensed to
the extent that it meets the following requirements: (a) its rates are regulated
by a third-party; (b) its rates are cost-based; and (c) there exists a
reasonable assumption that all costs will be recoverable from customers through
rates. When a company determines that it no longer meets the requirements of
SFAS No. 71, pursuant to SFAS No. 101 and SFAS No. 121, it is required to write
off regulatory assets and liabilities unless some form of recovery continues
through rates established and collected from remaining regulated operations. In
addition, such company is required to determine any impairment to the carrying
costs of deregulated plant and inventory assets in accordance with SFAS No. 121.
In July 1997, the EITF reached a consensus on Issue No. 97-4, "Deregulation
of the Pricing of Electricity -- Issues Related to the Application of FASB
Statements No. 71, Accounting for the Effects of Certain Types of Regulation,
and No. 101, Regulated Enterprises Accounting for the Discontinuation of
Application of FASB Statement No. 71" (EITF No. 97-4). EITF No. 97-4 concluded
that a company should no longer apply SFAS No. 71 to a segment which is subject
to a deregulation plan at the time the deregulation legislation or enabling rate
order contains sufficient detail for the utility to reasonably determine how the
plan will affect the segment to be deregulated. In addition, EITF No. 97-4
requires that regulatory assets and liabilities be allocated to the applicable
portion of the electric utility from which the source of the regulated cash
flows will be derived.
The Company believes that the Legislation provides sufficient detail
regarding the deregulation of the Company's electric generation operations to
require it to discontinue the use of SFAS No. 71 for those operations. Effective
June 30, 1999, the Company applied SFAS No. 101 to Reliant Energy HL&P's
electric generation operations. Reliant Energy HL&P's transmission and
distribution operations continue to meet the criteria of SFAS No. 71.
In 1999, the Company evaluated the effects that the Legislation would have
on the recovery of its generation related regulatory assets and liabilities. The
Company determined that a pre-tax accounting loss of $282 million existed
because it believes only the economic value of its generation related regulatory
assets (as defined by the Legislation) will be recovered. Therefore, the Company
recorded a $183 million after-tax extraordinary loss in the fourth quarter of
1999. If events were to occur that made the recovery of some of the remaining
generation related regulatory assets no longer probable, the Company would write
off the remaining
93
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
balance of such assets as a non-cash charge against earnings. Pursuant to EITF
No. 97-4, the remaining recoverable regulatory assets will not be written off
and will become associated with the transmission and distribution portion of the
Company's electric utility business. For details regarding Reliant Energy HL&P's
regulatory assets, see Note 2(f).
At June 30, 1999, the Company performed an impairment test of its
previously regulated electric generation assets pursuant to SFAS No. 121 on a
plant specific basis. Under SFAS No. 121, an asset is considered impaired, and
should be written down to fair value, if the future undiscounted net cash flows
expected to be generated by the use of the asset are insufficient to recover the
carrying amount of the asset. For assets that are impaired pursuant to SFAS No.
121, the Company determined the fair value for each generating plant by
estimating the net present value of future cash inflows and outflows over the
estimated life of each plant. The difference between fair value and net book
value was recorded as a reduction in the current book value. The Company
determined that $797 million of electric generation assets were impaired as of
June 30, 1999. Of these amounts, $745 million related to the South Texas Project
and $52 million related to two gas-fired generation plants. The Legislation
provides for recovery of this impairment through regulated cash flows during the
transition period and through non-bypassable charges to transmission and
distribution customers. As such, a regulatory asset has been recorded for an
amount equal to the impairment loss and is included on the Company's
Consolidated Balance Sheets as a regulatory asset. The Company recorded
amortization expense related to the recoverable impaired plant costs and other
assets created from discontinuing SFAS No. 71 of $221 million in the third and
fourth quarters of 1999 and $329 million in 2000. The Company expects to fully
amortize this regulatory asset as it is recovered from regulated cash flows in
2001.
The impairment analysis requires estimates of possible future market
prices, load growth, competition and many other factors over the lives of the
plants. The resulting impairment loss is highly dependent on these underlying
assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must
finalize and reconcile stranded costs (as defined by the Legislation) in a
filing with the Texas Utility Commission. Any positive difference between the
regulatory net book value and the fair market value of the generation assets (as
defined by the Legislation) will be collected through future non-bypassable
charges. Any over-mitigation of stranded costs may be refunded through future
non-bypassable charges. This final reconciliation allows alternative methods of
third party valuation of the fair market value of these assets, including
outright sale, stock valuations and asset exchanges. Because generally accepted
accounting principles require the Company to estimate fair market values on a
plant-by-plant basis in advance of the final reconciliation, the financial
impacts of the Legislation with respect to the final determination of stranded
costs in 2004 are subject to material changes. Factors affecting such change may
include estimation risk, uncertainty of future energy and commodity prices and
the economic lives of the plants. If events occur that make the recovery of all
or a portion of the regulatory assets associated with the generation plant
impairment loss and other assets created from discontinuance of SFAS No. 71
pursuant to the Legislation no longer probable, the Company will write off the
corresponding balance of these assets as a non-cash charge against earnings. One
of the results of discontinuing the application of SFAS No. 71 for the
generation operations is the elimination of the regulatory accounting effects of
excess deferred income taxes and investment tax credits related to these
operations. The Company believes it is probable that some parties will seek to
return these amounts to ratepayers and accordingly, the Company has recorded an
offsetting liability.
In order to reduce potential exposure to stranded costs related to
generation assets, Reliant Energy HL&P redirected $195 million and $99 million
of depreciation in 1998 and for the six months ended June 30, 1999,
respectively, from transmission and distribution related plant assets to
generation assets for regulatory and financial reporting purposes. This
redirection was in accordance with the Company's Transition Plan. See Note 4(c)
for additional information regarding the Transition Plan. The Legislation
provides that depreciation expense for transmission and distribution related
assets may be redirected to generation assets during the base rate freeze period
from 1999 through 2001. For regulatory purposes, the Company has
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
continued to redirect transmission and distribution depreciation to generation
assets. Beginning June 30, 1999, redirected depreciation expense cannot be
recorded by the electric generation operations portion of Reliant Energy HL&P
for financial reporting purposes as this portion of electric operations is no
longer accounted for under SFAS No. 71. During the six months ended December 31,
1999 and during 2000, $99 million and $218 million in depreciation expense,
respectively, has been redirected from transmission and distribution for
regulatory purposes and has been established as an embedded regulatory asset
included in transmission and distribution related plant and equipment balances.
As of December 31, 1999 and 2000, the cumulative amount of redirected
depreciation for regulatory purposes is $393 million and $611 million,
respectively.
The Company has reviewed its long-term purchase power contracts and fuel
contracts for potential loss in accordance with SFAS No. 5, "Accounting for
Contingencies" and Accounting Research Bulletin No. 43, Chapter 4, "Inventory
Pricing." Based on projections of future market prices for wholesale
electricity, the analysis indicated no loss recognition is appropriate at this
time.
Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71,
the accounting policies discussed below related to Electric Operations'
generation operations have been changed effective July 1, 1999. Allowance for
funds used during construction will no longer be accrued on generation related
construction projects. Instead, interest will be capitalized on these projects
in accordance with SFAS No. 34, "Capitalization of Interest Cost."
Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred
the premiums and expenses that arose when long-term debt was redeemed and
amortized these costs over the life of the new debt. If no new debt was issued,
these costs were amortized over the remaining original life of the retired debt.
Effective July 1, 1999, costs resulting from the retirement of debt attributable
to the generation operations of Reliant Energy HL&P will be recorded in
accordance with SFAS No. 4, "Reporting Gains and Losses from Extinguishment of
Debt," unless these costs will be recovered through regulated cash flows. In
that case, these costs will be deferred and recorded as a regulatory asset by
the entity through which the source of the regulated cash flows will be derived.
(b) Business Separation Plan.
General. As required by the Legislation, Reliant Energy submitted the
Business Separation Plan in 2000 to the Texas Utility Commission. The Business
Separation Plan was later amended to provide for the restructuring of the
Company's businesses into two separate and publicly traded companies in order to
separate its unregulated businesses from its regulated businesses. In December
2000, the plan was approved by the Texas Utility Commission. Reliant Resources
holds Reliant Energy's unregulated businesses, including the Wholesale Energy
segment, European Energy segment, communications business, eBusiness group, new
ventures group and retail electric business. As further described below, Reliant
Energy will undergo a restructuring of the Company's corporate organization to
achieve a holding company structure. This holding company will hold primarily
what are currently Reliant Energy's rate-regulated businesses. Reliant Resources
expects to conduct the Offering in 2001. After the Offering, Reliant Energy will
own approximately 80% of Reliant Resources common stock. Reliant Energy expects
the Offering to be followed by a distribution to Reliant Energy's or its
successor's shareholders of the remaining common stock of Reliant Resources
within 12 months of the Offering (the Distribution Date).
The Offering and the Distribution are subject to further corporate
approvals, market and other conditions, and government actions, including
receipt of a favorable Internal Revenue Service ruling that the Distribution
would be tax-free to Reliant Energy or its successor and its shareholders for
U.S. federal income tax purposes, as applicable. There can be no assurance that
the Offering and the Distribution will be completed as described or within the
time periods outlined above.
95
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Restructuring of Regulated Entities. Under the Business Separation Plan,
Reliant Energy will restructure its regulated operations into a holding company
structure in which a new corporate entity (Regulated Holding Company) will be
formed as the parent with the Company's regulated businesses as subsidiaries.
This Regulated Holding Company is expected to own (a) the Company's electric
transmission and distribution operations, (b) its natural gas distribution
businesses, (c) initially, its regulated electric generating assets in Texas,
(d) its interstate pipelines, gas gathering and pipeline services operations,
and (e) its interests in energy companies in Latin America until disposition of
these investments (see Note 19). In these Notes, references to Reliant Energy in
connection with events occurring or the performance of agreements after the
restructuring generally refer to the Regulated Holding Company.
In connection with the formation of the new holding company for regulated
businesses, Reliant Energy expects to transfer the stock of all of its
subsidiaries to the new holding company and will transfer its regulated electric
generating assets in Texas to an indirect wholly owned partnership (Texas Genco)
until the stranded costs associated with those assets are valued in 2004. At
that time, Reliant Resources will have the right to exercise an option to
acquire those assets, as further discussed below. As a result of the stock and
asset transfers described above, Reliant Energy will become solely a
transmission and distribution company, with its other businesses becoming
subsidiaries of the new holding company. Reliant Energy expects that the
regulated holding company will be required to assume all of Reliant Energy's
debt other than its first mortgage bonds, which would remain with Reliant
Energy. The indebtedness of some wholly owned financing subsidiaries is expected
to be refinanced by the regulated holding company by the end of 2002.
Reliant Energy has made and will continue to make internal asset and stock
transfers intended to allocate the assets and liabilities of Reliant Energy in
accordance with regulatory requirements and as contemplated by the Business
Separation Plan. Forms of each of the intercompany agreements described below
have been prepared and will be entered into by Reliant Energy and Reliant
Resources prior to the Offering.
Aspects of the restructuring of Reliant Energy's regulated businesses are
subject to the approval of Reliant Energy's shareholders and lenders and
approvals from the SEC under the Public Utility Holding Company Act and from the
United States Nuclear Regulatory Commission (NRC). There can be no assurance
that the restructuring of the Company's regulated businesses will be completed
as described above.
Agreements Related to Texas Generating Assets. Pursuant to the Business
Separation Plan, Reliant Energy expects to cause Texas Genco to either issue and
sell in an initial public offering or to distribute to its shareholders no more
than 20% of the common stock of Texas Genco by June 30, 2002. In connection with
the separation of its unregulated businesses from its regulated businesses,
Reliant Energy will grant Reliant Resources an option to purchase all of the
shares of capital stock of Texas Genco that will be owned by Reliant Energy
after the initial public offering or distribution. The Texas Genco option may be
exercised between January 10, 2004 and January 24, 2004. The per share exercise
price under the option will be the average daily closing price on the national
exchange for publicly held shares of common stock of Texas Genco for the 30
consecutive trading days with the highest average closing price during the 120
trading days immediately preceding January 10, 2004, plus a control premium, up
to a maximum of 10%, to the extent a control premium is included in the
valuation determination made by the Texas Utility Commission relating to the
market value of Texas Genco's common stock equity. The exercise price is also
subject to adjustment based on the difference between the per share dividends
paid during the period there is a public ownership interest in Texas Genco and
Texas Genco's per share earnings during that period. If the disposition to the
public of common stock of Texas Genco is by means of a primary or secondary
public offering, the public offering may be of as little as 17% (rather than
19%) of Texas Genco's outstanding common stock, in which case Reliant Energy
will have the right to subsequently reduce its interest to a level not less than
80%. Reliant Resources will agree that if it exercises the Texas Genco Option
and purchases the shares of Texas Genco common stock, Reliant Resources will
also purchase all notes and other receivables from Texas Genco then held by
Reliant Energy, at their principal amount plus accrued interest. Similarly, if
Texas Genco holds notes
96
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
or receivables from the Company, Reliant Resources will assume those obligations
in exchange for a payment to Reliant Resources by the Company of an amount equal
to the principal plus accrued interest.
Exercise of the Texas Genco option by Reliant Resources will be subject to
various regulatory approvals, including Hart-Scott-Rodino antitrust clearance
and Nuclear Regulatory Commission license transfer approval. The option will be
exercisable only if Reliant Energy or its successor distributes all of the
shares of Reliant Resources common stock it owns to its shareholders.
The Texas Genco option agreement will require Reliant Energy to take
commercially reasonable action as may be appropriate to cause Texas Genco to
have a capital structure appropriate, in the judgment of Reliant Energy's Board
of Directors, for the satisfactory marketing of Texas Genco common stock in an
initial public offering or to establish a satisfactory trading market for Texas
Genco common stock following a distribution of shares to Reliant Energy's
shareholders. It also will contain covenants relating to the operation of the
Texas Genco assets prior to the exercise or expiration of the option and require
that Reliant Energy maintain ownership of all equity of Texas Genco until
exercise or expiration of the Texas Genco option, subject to the initial public
offering or distribution obligation.
Reliant Resources will provide engineering and technical support services
and environmental, safety and industrial health services to support the
operations and maintenance of Texas Genco's facilities. Reliant Resources will
also provide systems, technical, programming and consulting support services and
hardware maintenance (but excluding plant-specific hardware) necessary to
provide dispatch planning, dispatch and settlement and communication with the
independent system operator. The fees charged for these services will be
designed to allow Reliant Resources to recover its fully allocated direct and
indirect costs and reimbursement of out-of-pocket expenses. Expenses associated
with capital investment in systems and software that benefit both the operation
of Texas Genco's facilities and Reliant Resources' facilities in other regions
will be allocated on an installed megawatt basis. The term of the technical
services agreement will begin at the Distribution Date. The term of this
agreement will end on the first to occur of (a) the closing date of the Reliant
Resources' Texas Genco option, (b) Reliant Energy's sale of Texas Genco, or all
or substantially all of the assets of Texas Genco, if Reliant Resources does not
exercise the Texas Genco option, or (c) December 31, 2004, provided the Texas
Genco option is not exercised. Texas Genco may extend the term of this agreement
until December 31, 2005.
Pursuant to the Legislation, Texas Genco will be required to sell at
auction 15% of the output of its installed generating capacity beginning January
1, 2002. The first auction will be held on or before September 1, 2001 for power
delivered after January 1, 2002. This obligation continues until January 1,
2007, unless before that date the Texas Utility Commission determines that at
least 40% of the quantity of electric power consumed in 2000 by residential and
small commercial customers in the Reliant Energy HL&P traditional service area
is being served by retail electric providers other than subsidiaries of Reliant
Resources. Texas Genco plans to auction all of its remaining output during the
time period prior to Reliant Resources' exercise of the Texas Genco option.
Pursuant to the Business Separation Plan, Reliant Resources is entitled to
purchase, at prices established in these auctions, up to 50% of the remaining
capacity, energy and ancillary services auctioned by Texas Genco.
When Texas Genco is organized, it will become the beneficiary of the
decommissioning trust that has been established to provide funding for
decontamination and decommissioning of a nuclear electric generation station in
which Reliant Energy owns a 30.8% interest (see Note 6). The master separation
agreement will provide that Reliant Energy will collect through rates or other
authorized charges to its electric utility customers amounts designated for
funding the decommissioning trust, and will pay the amounts to Texas Genco.
Texas Genco will in turn be required to deposit these amounts received from
Reliant Energy into the decommissioning trust. Upon decommissioning of the
facility, in the event funds from the trust are inadequate, Reliant Energy will
be required to collect through rates or other authorized charges to customers as
contemplated by the Texas Utilities Code all additional amounts required to fund
Texas Genco's
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
obligations relating to the decommissioning of the facility. Following the
completion of the decommissioning, if surplus funds remain in the
decommissioning trust, the excess will be refunded to Reliant Energy's
ratepayers.
Retail Agreement between Reliant Energy and Reliant Resources. Under a
retail agreement, Reliant Resources will provide customer service call center
operations, credit and collections and revenue reporting services for Reliant
Energy's electric utility division and receiving and processing payments for the
accounts of Reliant Energy's electric utility division and two of Reliant
Energy's natural gas distribution divisions. Reliant Energy will provide the
office space and equipment for Reliant Resources to perform these services.
These services will terminate on January 1, 2002. The charges Reliant Energy
will pay Reliant Resources for these services are generally intended to allow
Reliant Resources to recover its fully allocated costs of providing the
services, plus out-of-pocket costs and expenses.
Service Agreements between Reliant Energy and Reliant Resources. Reliant
Resources plans to enter into agreements with Reliant Energy under which Reliant
Energy will provide Reliant Resources, on an interim basis, with various
corporate support services (including accounting, finance, investor relations,
planning, legal, communications, governmental and regulatory affairs and human
resources), information technology services and other previously shared services
such as corporate security, facilities management, accounts receivable, accounts
payable and payroll, office support services and purchasing and logistics.
These arrangements will continue after the Offering under a transition
services agreement providing for their continuation until December 31, 2004, or,
in the case of some corporate support services, until the Distribution Date. The
charges Reliant Resources will pay Reliant Energy for these services are
generally intended to allow Reliant Energy to recover its fully allocated costs
of providing the services, plus out-of-pocket costs and expenses. In each case,
Reliant Resources will have the right to terminate categories of services at an
earlier date.
Pursuant to a lease agreement, Reliant Energy will lease Reliant Resources
office space in its headquarters building in Houston, Texas for an interim
period.
Other Agreements. In connection with the separation of Reliant Resources'
businesses from those of Reliant Energy, Reliant Resources will also enter into
other agreements providing, among other things, for mutual indemnities and
releases with respect to Reliant Resources' respective businesses and
operations, matters relating to corporate governance, matters relating to
responsibility for employee compensation and benefits, and allocation of tax
liabilities. In addition, Reliant Resources and Reliant Energy will enter into
various agreements relating to ongoing commercial arrangements, including among
other things the leasing of optical fiber and related maintenance activities,
rights to build fiber networks along existing rights of way, and the provision
of local exchange telecommunications and data services in the greater Houston
metropolitan area and long distance telecommunications services.
Reliant Energy will agree that $1.9 billion of intercompany indebtedness
owed by Reliant Resources and its subsidiaries prior to the closing of the
Offering will be converted into equity as a capital contribution to Reliant
Resources.
(c) Transition Plan.
In June 1998, the Texas Utility Commission issued an order in Docket No.
18465 approving the Company's Transition Plan filed by Reliant Energy HL&P in
December 1997. The Transition Plan included base rate credits to residential
customers of 4% in 1998 and an additional 2% in 1999. Commercial customers whose
monthly billing is 1,000 kva or less were entitled to receive base rate credits
of 2% in each of 1998 and 1999. The Company implemented the Transition Plan
effective January 1, 1998.
98
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(d) Reliant Energy HL&P Filings.
As of December 31, 2000, Reliant Energy HL&P had recorded as a regulatory
asset under-recovered fuel cost of $558 million. In two separate filings in
2000, Reliant Energy HL&P filed and received approval to implement a fuel
surcharge to collect the under recovery of fuel expenses, as well as to adjust
the fuel factor to compensate for significant increases in the price of natural
gas.
On March 15, 2001, Reliant Energy HL&P filed to revise its fuel factor and
address the Company's undercollected fuel costs of $389 million, which is the
accumulated amount since September 2000 through February 2001 plus estimates for
March and April, 2001. Reliant Energy HL&P is requesting to revise its fixed
fuel factor to be implemented with the May 2001 billing cycle and has proposed
to defer the collection of the $389 million until the 2004 stranded costs
true-up proceeding, discussed in Note 4(a) above.
(5) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
The Company offers energy price risk management services primarily related
to natural gas, electric power and other energy related commodities. The Company
provides these services by utilizing a variety of derivative financial
instruments, including (a) fixed and variable-priced physical forward contracts,
(b) fixed and variable-priced swap agreements, (c) options traded in the
over-the-counter financial markets and (d) exchange-traded energy futures and
option contracts (Trading Derivatives). Fixed-price swap agreements require
payments to, or receipts of payments from, counterparties based on the
differential between a fixed and variable price for the commodity.
Variable-price swap agreements require payments to, or receipts of payments
from, counterparties based on the differential between industry pricing
publications or exchange quotations.
The Company applies mark-to-market accounting for all of its energy
trading, marketing and price risk management operations. Accordingly, these
Trading Derivatives are recorded at fair value with realized and unrealized
gains (losses) recorded as a component of revenues. The recognized, unrealized
balances are included in price risk management assets/liabilities.
The notional quantities, maximum terms and the estimated fair value of
Trading Derivatives at December 31, 1999 and 2000 are presented below (volumes
in billions of British thermal units equivalent (Bbtue) and dollars in
millions):
VOLUME-FIXED VOLUME-FIXED MAXIMUM
PRICE PAYOR PRICE RECEIVER TERM (YEARS)
------------ -------------- ------------
1999
Natural gas.................................... 1,278,953 1,251,319 9
Electricity.................................... 242,868 239,452 10
Oil and other.................................. 285,251 286,521 3
2000
Natural gas.................................... 1,876,358 1,868,597 17
Electricity.................................... 526,556 523,942 6
Oil and other.................................. 52,820 42,380 2
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FAIR VALUE AVERAGE FAIR VALUE(1)
--------------------- ---------------------
ASSETS LIABILITIES ASSETS LIABILITIES
------ ----------- ------ -----------
1999
Natural gas.................................. $ 581 $ 564 $ 550 $ 534
Electricity.................................. 122 91 96 74
Oil and other................................ 193 206 183 187
------ ------ ------ ------
$ 896 $ 861 $ 829 $ 795
====== ====== ====== ======
2000
Natural gas.................................. $4,059 $4,054 $2,058 $2,038
Electricity.................................. 1,115 1,087 601 561
Oil and other................................ 39 39 63 70
------ ------ ------ ------
$5,213 $5,180 $2,722 $2,669
====== ====== ====== ======
- ---------------
(1) Computed using the ending balance of each quarter.
In addition to the fixed-price notional volumes above, the Company also has
variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue and
3,004,336 Bbtue as of December 31, 1999 and 2000, respectively. Notional amounts
reflect the commodity volumes underlying the transactions but do not represent
the amounts exchanged by the parties to the financial instruments. Accordingly,
notional amounts do not accurately measure the Company's exposure to market or
credit risks.
All of the fair values shown in the table above at December 31, 1999 and
2000, have been recognized in income. The Company estimated the fair value as of
December 31, 1999 and 2000, using quoted prices where available and other
valuation techniques when market data was not available, for example in illiquid
markets. For financial instruments for which quoted prices are not available,
the Company utilizes alternative pricing methodologies, including, but not
limited to, extrapolation of forward pricing curves using historically reported
data from illiquid pricing points. These same pricing techniques are used to
evaluate a contract prior to taking the position. The prices and fair values are
subject to significant changes based on changing market conditions.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein are not
indicative of likely future cash flows, as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and the Company's risk management portfolio needs
and strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual
100
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
obligations by a counterparty. The following table shows the composition of the
total price risk management assets of the Company as of December 31, 1999 and
2000.
DECEMBER 31, 1999 DECEMBER 31, 2000
------------------ -------------------
INVESTMENT INVESTMENT
GRADE(1) TOTAL GRADE(1) TOTAL
---------- ----- ---------- ------
(IN MILLIONS)
Energy marketers................................ $202 $230 $2,507 $2,709
Financial institutions.......................... 90 159 1,159 1,296
Gas and electric utilities...................... 220 221 511 586
Oil and gas producers........................... 31 31 500 599
Industrials..................................... 3 4 78 89
Others.......................................... 174 263 -- --
---- ---- ------ ------
Total................................. $720 908 $4,755 5,279
==== ======
Credit and other reserves....................... (12) (66)
---- ------
Energy price risk management assets(2).......... $896 $5,213
==== ======
- ---------------
(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.
(2) As of December 31, 2000, the Company had credit risk exposure to three
investment-grade counterparties that each represented greater than 5% of
price risk management assets. This information excludes some offsetting
contracts that either require or permit net settlement with non-trading
transactions not included in price risk management assets. The Company's
resulting net credit risk exposure to these three counterparties is below 5%
of price risk management assets.
(b) Non-Trading Activities.
To reduce the risk from market fluctuations in the revenues derived from
the sale of electric power and natural gas and related transportation, the
Company enters into futures transactions, forward contracts, swaps and options
(Energy Derivatives) in order to hedge some expected purchases of electric power
and natural gas and sales of electric power and natural gas (a portion of which
are firm commitments at the inception of the hedge). Energy Derivatives are also
utilized to fix the price of compressor fuel or other future operational gas
requirements and to protect natural gas distribution earnings against
unseasonably warm weather during peak gas heating months, although usage to date
for this purpose has not been material. The Company applies hedge accounting for
its derivative financial instruments utilized in non-trading activities.
Unrealized changes in the market value of Energy Derivatives utilized as hedges
are not generally recognized in the Company's Statements of Consolidated
Operations until the underlying hedged transaction occurs. Once it becomes
probable that an anticipated transaction will not occur, the Company recognizes
deferred gains and losses. In general, the financial impact of transactions
involving these Energy Derivatives is included in the Company's Statements of
Consolidated Operations under the captions (a) fuel expenses, in the case of
natural gas transactions, (b) purchased power, in the case of electric power
purchase transactions, and (c) revenues, in the case of electric power sales
transactions. Cash flows resulting from these transactions in Energy Derivatives
are included in the Company's Statements of Consolidated Cash Flows in the same
category as the item being hedged.
In connection with the Company's acquisition of UNA in 1999, the Company
entered into call option agreements with several banks to hedge the impact of
foreign exchange movements on the Dutch guilder. These call options provided the
right, but not the obligation, to purchase NLG 695 million from specific banks
at specific strike prices. The total premium paid, classified as other expense
on the Company's Statement of
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Consolidated Operations, for all of the options that were to expire on October
26, 1999, was $8 million. On October 12, 1999, the Company sold the remaining
value in the call options for $0.6 million. The proceeds were reflected in the
Company's results of operations as a reduction of other expense.
As of December 31, 1999 and 2000, the Company had outstanding foreign
currency swaps for 258 million and Euros 671 million, respectively
(approximately $228 million and $632 million), terminating in September 2000 and
January 2001, respectively. The Company also issued Euro-denominated debt,
maturing in March and June 2001. The foreign currency swaps and Euro-denominated
debt hedge the Company's net investment in UNA. In January 2001, the Company
entered into foreign currency swaps for Euros 671 million (approximately $633
million) to replace the foreign currency swaps that expired in January 2001.
These foreign currency swaps terminate in January 2002. In January and March
2001, the Company entered into foreign currency forward contracts for Euros 159
million (approximately $150 million) to adjust the hedge of its net investment
in UNA. These forward contracts expire in January 2002. The Company records
changes in the value of the hedging instruments and debt as foreign currency
translation adjustments as a component of stockholders' equity and accumulated
other comprehensive loss. The effectiveness of the hedging instruments can be
measured by the net change in foreign currency translation adjustments
attributed to the net investment in UNA. These amounts generally offset amounts
recorded in stockholders' equity as adjustments resulting from translation of
the hedged investment into U.S. dollars. As of December 31, 1999 and 2000, the
net carrying value of the currency swaps was a $6 million receivable and $62
million obligation, respectively, and was recorded in other current assets and
other current liabilities in the Company's Consolidated Balance Sheets.
During 2000, European Energy entered into financial instruments to purchase
approximately $120 million to hedge future fuel purchases payable in U.S.
dollars. As of December 31, 2000, the fair value of these financial instruments
was a $6 million liability. Unrealized changes in the market value of these
financial instruments are not recognized in the Company's Statements of
Consolidated Operations until the underlying hedged transaction occurs.
For transactions involving either Energy Derivatives or foreign currency
derivatives, hedge accounting is applied only if the derivative reduces the risk
of the underlying hedged item and is designated as a hedge at its inception.
Additionally, the derivatives must be expected to result in financial impacts
that are inversely correlated to those of the item(s) to be hedged. This
correlation, a measure of hedge effectiveness, is measured both at the inception
of the hedge and on an ongoing basis, with an acceptable level of correlation of
at least 80% for hedge designation. If and when correlation ceases to exist at
an acceptable level, hedge accounting ceases and mark-to-market accounting is
applied.
At December 31, 1999, the Company was a fixed-price payor and a fixed-price
receiver in Energy Derivatives covering 33,108 Bbtu and 5,481 Bbtu of natural
gas, respectively. At December 31, 2000, the Company was a fixed-price payor and
a fixed-price receiver in Energy Derivatives covering 198,001 Bbtu and 22,874
Bbtu of natural gas, respectively, and 486 Bbtu and zero Bbtu of oil,
respectively. In addition to the fixed-price notional volumes above, the Company
also has variable-priced agreements totaling 44,958 Bbtu and 174,900 Bbtu of
natural gas at December 31, 1999 and 2000, respectively. The weighted average
maturity of these instruments is less than two years.
The notional amount is intended to be indicative of the Company's level of
activity in these derivatives. However, the amounts at risk are significantly
smaller because, in view of the price movement correlation required for hedge
accounting, changes in the market value of these derivatives generally are
offset by changes in the value associated with the underlying physical
transactions or in other derivatives. When Energy Derivatives are closed out in
advance of the underlying commitment or anticipated transaction, however, the
market value changes may not offset due to the fact that price movement
correlation ceases to exist when the positions are closed, as further discussed
above. Under these circumstances, gains (losses) are deferred and recognized as
a component of income when the underlying hedged item is recognized in income.
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The average maturity discussed above and the fair value discussed in Note
15 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions in the trading portfolio at any time in
response to changing market conditions, market liquidity and the Company's risk
management portfolio needs and strategies. Terms regarding cash settlements of
these contracts vary with respect to the actual timing of cash receipts and
payments.
(c) Trading and Non-trading -- General Policy.
In addition to the risk associated with price movements, credit risk is
also inherent in the Company's risk management activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. The Company has off-balance sheet risk to the extent that the
counterparties to these transactions may fail to perform as required by the
terms of each contract. In order to minimize this risk, the Company enters into
these contracts primarily with counterparties having a minimum investment grade
index rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3,
respectively. For long-term arrangements, the Company periodically reviews the
financial condition of these firms in addition to monitoring the effectiveness
of these financial contracts in achieving the Company's objectives. If the
counterparties to these arrangements fail to perform, the Company would seek to
compel performance at law or otherwise obtain compensatory damages. The Company
might be forced to acquire alternative hedging arrangements or be required to
replace the underlying commitment at then-current market prices. In this event,
the Company might incur additional losses to the extent of amounts, if any,
already paid to the counterparties. For information regarding credit risk
related to the California wholesale electricity market, see Note 14(h).
The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.
The Company has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading, marketing, power
origination and risk management activities. The committee's duties are to
establish the Company's commodity risk policies, allocate risk capital within
limits established by the Company's Board of Directors, approve trading of new
products and commodities, monitor risk positions and ensure compliance with the
Company's risk management policies and procedures and trading limits established
by the Company's Board of Directors.
(6) JOINTLY OWNED ELECTRIC UTILITY PLANT
The Company has a 30.8% interest in the South Texas Project, which consists
of two 1,250 MW nuclear generating units and bears a corresponding 30.8% share
of capital and operating costs associated with the project. The South Texas
Project is owned as a tenancy in common among its four co-owners, with each
owner retaining its undivided ownership interest in the two nuclear-fueled
generating units and the electrical output from those units. The four co-owners
have delegated management and operating responsibility for the South Texas
Project to the South Texas Project Nuclear Operating Company (STPNOC). STPNOC is
managed by a board of directors comprised of one director from each of the four
owners, along with the chief executive officer of STPNOC. As of December 31,
2000, the Company's investment in the South Texas Project was $363 million (net
of $2.1 billion accumulated depreciation which includes an impairment loss
recorded in 1999 of $745 million). For additional information regarding the
impairment loss, see Note 4(a). The Company's investment in nuclear fuel was $39
million (net of $269 million amortization) as of December 31, 2000.
103
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(7) EQUITY INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
In April 1998, the Company formed a limited liability company to construct
and operate a 490 MW electric generation plant in Boulder City, Nevada in which
the Company has a 50% interest. The plant became operational in May 2000. In
October 1998, the Company entered into a partnership to construct and operate a
100 MW cogeneration plant in Orange, Texas in which its ownership interest is
50%. The plant began commercial operations in December 1999. As of December 31,
1999 and 2000, the Company's net investment in these projects was $78 million
and $109 million, respectively. The Company's equity income from these
investments was $43 million in 2000. The Company's equity loss from these
investments was $0.6 million and $0.8 million in 1998 and 1999, respectively.
During 1998 and 1999, there were no distributions from these investments. During
2000, $18 million was distributed from these investments.
(8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES
(a) Original Investment in Time Warner Securities.
On July 6, 1999, the Company converted its 11 million shares of Time Warner
Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of
Time Warner common stock (TW Common). Prior to the conversion, the Company's
investment in the TW Preferred was accounted for under the cost method at a
value of $990 million in the Company's Consolidated Balance Sheets. The TW
Preferred was redeemable after July 6, 2000, had an aggregate liquidation
preference of $100 per share (plus accrued and unpaid dividends), was entitled
to annual dividends of $3.75 per share until July 6, 1999 and was convertible by
the Company. The Company recorded pre-tax dividend income with respect to the TW
Preferred of $21 million in 1999 prior to the conversion and $41 million in
1998. Effective on the conversion date, the shares of TW Common were classified
as trading securities under SFAS No. 115 and an unrealized gain was recorded in
the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative
appreciation in the fair value of the Company's investment in Time Warner
securities.
(b) ACES.
In July 1997, in order to monetize a portion of the cash value of its
investment in TW Preferred, the Company issued 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES) having an original principal amount
of $1.052 billion and maturing July 1, 2000. The market value of ACES was
indexed to the market value of TW Common. On the July 1, 2000 maturity date, the
Company tendered 37.9 million shares of TW Common to fully settle its
obligations in connection with its unsecured 7% ACES having a value of $2.9
billion.
(c) ZENS.
On September 21, 1999, the Company issued approximately 17.2 million of its
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an
original principal amount of $1.0 billion. The original principal amount per
ZENS will increase each quarter to the extent that the sum of the quarterly cash
dividends and the interest paid during a quarter on the reference shares
attributable to one ZENS is less than $.045, so that the annual yield to
investors from the date the Company issued the ZENS to the date of computation
of the contingent principal amount is not less than 2.309%. At maturity the
holders of the ZENS will receive in cash the higher of the original principal
amount of the ZENS (subject to adjustment as discussed above) or an amount based
on the then-current market value of TW Common, or other securities distributed
with respect to TW Common (one share of TW Common and such other securities, if
any, are referred to as reference shares). Each ZENS has an original principal
amount of $58.25 (the closing market price of the TW Common on September 15,
1999) and is exchangeable at any time at the option of the holder for cash equal
to 95% (100% in some cases) of the market value of the reference shares
attributable to one
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the
amount of any quarterly cash dividends paid in respect of the quarterly interest
period on the reference shares attributable to each ZENS. Subject to some
conditions, the Company has the right to defer interest payments from time to
time on the ZENS for up to 20 consecutive quarterly periods. As of December 31,
2000, no interest payments on the ZENS had been deferred.
On January 11, 2001, TW and America Online, Inc. combined to form AOL Time
Warner Inc. (AOL TW). As a result of the combination each share of TW Common was
converted into 1.5 shares of AOL TW Common Stock (AOL TW Common) and the Company
now holds 25.8 million shares of AOL TW Common. As a result of the combination,
the reference shares attributable to one ZENS is 1.5 shares of AOL TW Common.
The Company used $537 million of the net proceeds from the offering of the
ZENS to purchase 9.2 million shares of TW Common, which are classified as
trading securities under SFAS No. 115. Unrealized gains and losses resulting
from changes in the market value of the TW Common are recorded in the Company's
Statements of Consolidated Operations.
Prior to January 1, 2001, an increase above $58.25 (subject to some
adjustments) in the market value per share of TW Common resulted in an increase
in the Company's liability for the ZENS. However, as the market value per share
of TW Common declined below $58.25 (subject to some adjustments), the liability
for the ZENS did not decline below the original principal amount. As of December
31, 1999 and 2000, the market value of TW Common was $72.31 and $52.24,
respectively. Therefore, during 2000, the Company recorded a pre-tax net
unrealized loss on its investment in TW Common and its obligation on its indexed
debt securities of $103 million.
Prior to the purchase of additional shares of TW Common on September 21,
1999, the Company owned approximately 8 million shares of TW Common that were in
excess of the 38 million shares needed to economically hedge its ACES
obligation. For the period from July 6, 1999 to the ZENS issuance date, losses
(due to the decline in the market value of the TW Common during such period) on
these 8 million shares were $122 million ($79 million after-tax). The 8 million
shares of TW Common combined with the additional 9.2 million shares purchased
are expected to be held to facilitate the Company's ability to meet its
obligation under the ZENS.
The following table sets forth summarized financial information regarding
the Company's investment in TW securities and the Company's ACES and ZENS
obligations.
TW INVESTMENT ACES ZENS
------------- ------- ------
(IN MILLIONS)
Balance at December 31, 1997......................... $ 990 $ 1,174
Loss on indexed debt securities...................... -- 1,176
------- -------
Balance at December 31, 1998......................... 990 2,350
Issuance of indexed debt securities.................. -- -- $1,000
Purchase of TW Common................................ 537 -- --
Loss on indexed debt securities...................... -- 388 241
Gain on TW Common.................................... 2,452 -- --
------- ------- ------
Balance at December 31, 1999......................... 3,979 2,738 1,241
------- ------- ------
Loss (Gain) on indexed debt securities............... -- 139 (241)
Loss on TW Common.................................... (205) -- --
Settlement of ACES................................... (2,877) (2,877) --
------- ------- ------
Balance at December 31, 2000......................... $ 897 $ -- $1,000
======= ======= ======
105
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS
obligation is bifurcated into a debt component and a derivative component (the
holder's option to receive the appreciated value of AOL TW Common at maturity).
The derivative component is valued at fair value and determines the initial
carrying value assigned to the debt component ($121 million) as the difference
between the original principal amount of the ZENS ($1.0 billion) and the fair
value of the derivative component at issuance ($879 million). Effective January
1, 2001 the debt component is recorded at its accreted amount of $122 million
and the derivative component is recorded at its current fair value of $788
million, as a current liability, resulting in a transition adjustment pre-tax
gain of $90 million. The transition adjustment gain will be reported in the
first quarter of 2001 as the effect of a change in accounting principle.
Subsequently, the debt component will accrete through interest charges at 17.5%
up to the minimum amount payable upon maturity of the ZENS in 2029,
approximately $1.1 billion, and changes in the fair value of the derivative
component will be recorded in the Company's Statements of Consolidated
Operations. Changes in the fair value of the AOL TW Common held by the Company
should substantially offset changes in the fair values of the derivative
component of the ZENS.
(9) PREFERRED STOCK AND PREFERENCE STOCK
(a) Preferred Stock.
At December 31, 1999 and 2000, Reliant Energy had 10,000,000 authorized
shares of cumulative preferred stock, of which 97,397 shares were outstanding.
As of these dates, Reliant Energy's only outstanding series of preferred stock
was its $4.00 Preferred Stock. The $4.00 Preferred Stock pays an annual dividend
of $4.00 per share, is redeemable at $105 per share and has a liquidation price
of $100 per share to third-parties.
(b) Preference Stock.
At December 31, 1999 and 2000, Reliant Energy had 10,000,000 authorized
shares of preference stock, none of which was outstanding for financial
reporting purposes.
Reliant Energy has a Shareholder Rights Plan, which states that each share
of Reliant Energy's common stock includes one associated preference stock
purchase right (Right) which entitles the registered holder to purchase from
Reliant Energy a unit consisting of one-thousandth of a share of Series A
Preference Stock. The Rights, which expire on July 11, 2010, are exercisable
upon some events involving the acquisition of 20% or more of Reliant Energy's
outstanding common stock. Upon the occurrence of such an event, each Right
entitles the holder to receive common stock with a current market price equal to
two times the exercise price of the Right. At anytime prior to becoming
exercisable, Reliant Energy may repurchase the Rights at a price of $0.005 per
Right. There are 700,000 shares of Series A Preference Stock reserved for
issuance upon exercise of the Rights.
106
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(10) LONG-TERM DEBT AND SHORT-TERM BORROWINGS
DECEMBER 31, 1999 DECEMBER 31, 2000
---------------------- ----------------------
LONG-TERM CURRENT(1) LONG-TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Short-term borrowings:
Commercial paper................................. $1,793 $3,675
Lines of credit(2)............................... 563 853
Receivables facilities........................... 350 350
Other(2)......................................... 170 126
------ ------
Total short-term borrowings........................ 2,876 5,004
------ ------
Long-term debt:
Reliant Energy
ACES(3).......................................... $ -- 2,738 $ -- --
ZENS(3).......................................... -- 1,241 -- 1,000
Debentures 7.88% to 9.38% due 2001 to 2002....... 350 -- 100 250
First mortgage bonds 4.90% to 9.15% due 2002 to
2027.......................................... 1,261 150 1,261 --
Pollution control bonds 4.70% to 5.95% due 2011
to 2030....................................... 1,046 -- 1,046 --
Other............................................ 13 2 12 1
Financing Subsidiaries (directly or indirectly held
by Reliant Energy)
Notes payable 7.12% to 7.40% due 2001 to 2002.... 525 -- 300 225
Reliant Energy Power Generation, Inc.
Notes payable various market rates due 2002...... 70 -- 260 --
N.V. UNA (2)
Debentures 6.00% to 8.93% due 2001 to 2010....... 391 -- 66 1
Reliant Energy Capital Europe (2)
Notes Payable due 2003........................... -- -- 565 --
RERC Corp.
Convertible debentures 6.0% due 2012............. 93 -- 93 --
Debentures 6.38% to 8.90% due 2003 to 2008....... 962 -- 1,285 --
Notes payable 8.77% to 9.23% due 2001............ 150 223 -- 146
Unamortized discount and premium(4)................ 8 -- 8 --
------ ------ ------ ------
Total long-term debt..................... 4,869 4,354 4,996 1,623
------ ------ ------ ------
Total borrowings......................... $4,869 $7,230 $4,996 $6,627
====== ====== ====== ======
- ---------------
(1) Includes amounts due or exchangeable within one year of the date noted.
(2) Includes borrowings at December 31, 1999 and 2000 which are denominated in
Dutch Guilders (NLG) and Euros. As of December 31, 1999 and 2000, the
assumed exchange rate was 2.19 NLG and 2.34 NLG per U.S. dollar,
respectively, and 0.9938 Euro and 1.0616 Euros per U.S. dollar,
respectively.
(3) For additional information regarding ACES and ZENS, see Note 8(b) and (c).
As ZENS are exchangeable for cash at any time at the option of the holders,
these notes are classified as a current portion of long-term debt.
107
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(4) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in unamortized premium and discount is
unamortized premium related to fair value adjustments of long-term debt of
$33 million and $12 million at December 31, 1999 and 2000, respectively, and
is being amortized over the respective remaining term of the related
long-term debt.
(a) Short-term Borrowings.
As of December 31, 2000, the Company had credit facilities in effect, which
included facilities of various financing subsidiaries and operating
subsidiaries, with financial institutions which provide for an aggregate of $8.4
billion in committed credit. The facilities expire as follows: $5.0 billion in
2001, $2.1 billion in 2002 and $1.3 billion in 2003. Interest rates on
borrowings are based on the London interbank offered rate (LIBOR) plus a margin,
Euro interbank deposits plus a margin, a base rate or a rate determined through
a bidding process. As of December 31, 2000, unused credit facilities totaled
$1.7 billion. As of December 31, 2000, letters of credit outstanding under these
facilities aggregated $899 million. As of December 31, 2000, borrowings of $825
million were outstanding under these facilities that were classified as
long-term debt, based on availability of committed credit facilities with
expiration dates exceeding one year and management's intention to borrow these
amounts in excess of one year. Credit facilities aggregating $2.0 billion are
unsecured.
Of the $8.4 billion of committed credit facilities described above, $5.0
billion will expire in 2001. To the extent that the Company continues to need
access to this amount of committed credit, the Company expects to extend or
replace these facilities on normal commercial terms on a timely basis.
The credit facilities under which Reliant Energy borrows or provides credit
support contain various business and financial covenants requiring the Company
to, among other things, maintain leverage (as defined in the credit facilities)
below specified ratios. Certain credit facilities at the subsidiary level also
contain various financial covenants limiting leverage and requiring the
subsidiary to maintain its interest coverage ratio (as defined in the credit
facilities) above a specified ratio during stated periods. The Company is in
compliance with the covenants under all of these credit agreements. The Company
does not expect any of these covenants to materially limit the Company's ability
to borrow or obtain letters of credit under these facilities.
The Company sells commercial paper to provide financing for general
corporate purposes. As of December 31, 2000, $3.7 billion of commercial paper
was outstanding. The commercial paper borrowings are supported by various credit
facilities discussed above including credit facilities aggregating $3.0 billion
expiring in 2001, a $1.6 billion credit facility expiring in 2002 and a $350
million revolving credit facility expiring in 2003.
The weighted average interest rate on short-term borrowings as of December
31, 1998, 1999 and 2000 was 5.77%, 5.84% and 7.43%, respectively.
(b) Long-term Debt.
Maturities of long-term debt and sinking fund requirements for the Company
are $630 million in 2001, $789 million in 2002, $1.2 billion in 2003, $48
million in 2004 and $332 million in 2005.
Substantially all physical assets used in the conduct of the business and
operations of Electric Operations are subject to liens securing the First
Mortgage Bonds. Sinking fund requirements on the First Mortgage Bonds may be
satisfied by certification of property additions at 100% of the requirements as
defined by the Mortgage and Deed of Trust. Sinking or improvement/replacement
fund requirements for 1998, 1999 and 2000 have been satisfied by certification
of property additions. The replacement fund requirement to be satisfied in 2001
is $340 million.
108
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1999 and 2000, RERC Corp. had issued and outstanding $98
million aggregate principal amount ($93 million carrying amount) of its 6%
Convertible Subordinated Debentures due 2012 (Subordinated Debentures). The
holders of the Subordinated Debentures receive interest quarterly and have the
right at any time on or before the maturity date thereof to convert each
Subordinated Debenture into 0.65 shares of Reliant Energy common stock and
$14.24 in cash. During 1999, RERC Corp. purchased $12 million aggregate
principal amount of its Subordinated Debentures.
In November 1998, RERC Corp. issued $500 million aggregate principal amount
of its 6 3/8% Term Enhanced ReMarketable Securities (TERM Notes). The TERM Notes
provide to the investment bank a call option, which gives it the right to have
the TERM Notes redeemed from the investors on November 1, 2003 and then
remarketed if it chooses to exercise the option. The TERM Notes are unsecured
obligations of RERC Corp. which bear interest at an annual rate of 6 3/8%
through November 1, 2003. On November 1, 2003, the holders of the TERM Notes are
required to tender their notes at 100% of their principal amount. The portion of
the proceeds attributable to the call option premium will be amortized over the
stated term of the securities. If the option is not exercised by the investment
bank, RERC Corp. will repurchase the TERM Notes at 100% of their principal
amount on November 1, 2003. If the option is exercised, the TERM Notes will be
remarketed on a date, selected by RERC Corp., within the 52-week period
beginning November 1, 2003. During this period and prior to remarketing, the
TERM Notes will bear interest at rates, adjusted weekly, based on an index
selected by RERC Corp. If the TERM Notes are remarketed, the final maturity date
of the TERM Notes will be November 1, 2013, subject to adjustment, and the
effective interest rate on the remarketed TERM Notes will be 5.66% plus RERC
Corp.'s applicable credit spread at the time of such remarketing.
During the second quarter of 2000, UNA negotiated the repurchase of $272
million aggregate principal amount of its long-term debt for a total cost of
$286 million, including $14 million in expenses. The book value of the debt
repurchased was $293 million, resulting in an extraordinary gain on the early
extinguishment of long-term debt of $7 million. Borrowings under a short-term
banking facility and proceeds from the sale of trading securities by UNA were
used to finance the debt repurchase.
During 1998 and 1999, the Company's regulated operations recorded losses
from the extinguishment of debt of $20 million and $22 million, respectively.
There were no losses recorded from the early extinguishment of debt in 2000. As
these costs will be recovered through regulated cash flows, these costs have
been deferred and a regulatory asset has been recorded. For further discussion
regarding the accounting, see Note 4(a).
(11) TRUST PREFERRED SECURITIES
In February 1999, a Delaware statutory business trust created by Reliant
Energy (REI Trust I) issued $375 million aggregate amount of preferred
securities to the public. In February 1997, two Delaware statutory business
trusts created by Reliant Energy (HL&P Capital Trust I and HL&P Capital Trust
II) publicly issued (a) $250 million aggregate amount of preferred securities
and (b) $100 million aggregate amount of capital securities, respectively.
Reliant Energy accounts for REI Trust I, HL&P Capital Trust I and HL&P Capital
Trust II as wholly-owned consolidated subsidiaries. Each of the trusts used the
proceeds of the offerings to purchase junior subordinated debentures issued by
Reliant Energy having interest rates and maturity dates that correspond to the
distribution rates and the mandatory redemption dates for each series of
preferred securities or capital securities.
The junior subordinated debentures are the trusts' sole assets and their
entire operations. Reliant Energy considers its obligations under the Amended
and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where
applicable, Agreement as to Expenses and Liabilities, relating to each series of
preferred securities or capital securities, taken together, to constitute a full
and unconditional guaranty by Reliant Energy of each trust's obligations with
respect to the respective series of preferred securities or capital securities.
109
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The preferred securities and capital securities are mandatorily redeemable
upon the repayment of the related series of junior subordinated debentures at
their stated maturity or earlier redemption. Subject to some limitations,
Reliant Energy has the option of deferring payments of interest on the junior
subordinated debentures. During any deferral or event of default, Reliant Energy
may not pay dividends on its capital stock. As of December 31, 2000, no interest
payments on the junior subordinated debentures had been deferred.
In June 1996, a Delaware statutory business trust created by RERC Corp.
(Resources Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. RERC Corp. accounts for Resources Trust as a wholly
owned consolidated subsidiary. Resources Trust used the proceeds of the offering
to purchase convertible junior subordinated debentures issued by RERC Corp.
having an interest rate and maturity date that correspond to the distribution
rate and mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent Resources Trust's sole
assets and its entire operations. RERC Corp. considers its obligation under the
Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement
relating to the convertible preferred securities, taken together, to constitute
a full and unconditional guaranty by RERC Corp. of RERC Trust's obligations with
respect to the convertible preferred securities.
The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Reliant Energy common stock. During 1998, 1999 and 2000, convertible preferred
securities aggregating $16 million, $0.2 million and $0.3 million, respectively,
were converted, leaving $0.7 million and $0.4 million liquidation amount of
convertible preferred securities outstanding at December 31, 1999 and 2000,
respectively. Subject to some limitations, RERC Corp. has the option of
deferring payments of interest on the convertible junior subordinated
debentures. During any deferral or event of default, RERC Corp. may not pay
dividends on its common stock to Reliant Energy. As of December 31, 2000, no
interest payments on the subordinated debentures had been deferred.
The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of each series of the preferred securities,
convertible preferred securities or capital securities of the trusts and the
identity and similar terms of each related series of junior subordinated
debentures are as follows:
AGGREGATE
LIQUIDATION
AMOUNTS AS OF DISTRIBUTION MANDATORY
DECEMBER 31, RATE/INTEREST REDEMPTION
TRUST 1999 AND 2000 RATE DATE/MATURITY DATE JUNIOR SUBORDINATED DEBENTURES
- ----- ------------- ------------- ------------------ ------------------------------
(IN MILLIONS)
REI Trust I............... $375 7.20 % March 2048 7.20% Junior Subordinated
Debentures due 2048
HL&P Capital Trust I...... $250 8.125 % March 2048 8.125% Junior Subordinated
Deferrable Interest
Debentures Series A
HL&P Capital Trust II..... $100 8.257 % February 2037 8.257% Junior Subordinated
Deferrable Interest
Debentures Series B
Resources Trust........... $ 1 6.25 % June 2026 6.25% Convertible Junior
Subordinated Debentures due
2026
110
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(12) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS
(a) Incentive Compensation Plans.
The Company has a long-term incentive compensation plan (LICP) and other
incentive compensation plans that provide for the issuance of stock-based
incentives, including performance-based stock compensation, restricted shares,
stock options and stock appreciation rights, to key employees of the Company,
including officers. No stock appreciation rights have ever been issued under the
LICP. As of December 31, 2000, 604 current and 39 former employees of the
Company participate in the plans. A maximum of approximately 24 million shares
of Reliant Energy common stock may be issued under these plans.
Performance-based shares and restricted shares are granted to employees
without cost to the participants. The performance shares vest three years after
the grant date based upon the performance of the Company over a three-year
cycle, except as discussed below. The restricted shares vest to the participants
at various times ranging from immediate vesting to vesting at the end of a
three-year period. Upon vesting, the shares are released to the plans'
participants. During 1998, 1999 and 2000, the Company recorded compensation
expense of $17 million, $8 million and $22 million, respectively, related to
performance-based shares and restricted share grants. The following table
summarizes performance-based shares and restricted share grant activity for the
years 1998 through 2000:
NUMBER OF NUMBER OF
PERFORMANCE-BASED RESTRICTED
SHARES SHARES
----------------- ----------
Outstanding at December 31, 1997............................ 555,847 150,000
Granted................................................... 537,448 11,685
Canceled.................................................. (40,223) (300)
Released to participants.................................. (148,075) --
---------- -------
Outstanding at December 31, 1998............................ 904,997 161,385
Granted................................................... 431,643 113,837
Canceled.................................................. (228,215) (646)
Released to participants.................................. (179,958) (3,953)
---------- -------
Outstanding at December 31, 1999............................ 928,467 270,623
Granted................................................... 394,942 206,395
Canceled.................................................. (81,541) (13,060)
Released to participants.................................. (174,001) (5,346)
---------- -------
Outstanding at December 31, 2000............................ 1,067,867 458,612
---------- -------
Weighted average fair value of performance shares and
restricted shares granted for 1998........................ $ 23.75 $ 26.69
========== =======
Weighted average fair value of performance shares and
restricted shares granted for 1999........................ $ 29.23 $ 26.88
========== =======
Weighted average fair value of performance shares and
restricted shares granted for 2000........................ $ 25.19 $ 28.03
========== =======
Outstanding performance shares under the LICP will vest for the performance
cycle ending December 31, 2000 according to the terms and conditions of the
plan. Assuming the Distribution occurs during the calendar year 2001, Reliant
Energy's compensation committee will determine as of the Distribution Date the
level at which the performance objectives are expected to have been achieved
through the end of the performance cycle ending December 31, 2001 and will vest
the outstanding performance shares as of the Distribution Date as though the
performance objectives were achieved at that level. In addition, as of the
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Distribution Date, Reliant Energy's compensation committee will convert
outstanding performance shares for the performance cycle ending December 31,
2002 to a number of time-based restricted shares of Reliant Energy's common
stock equal to the number of performance shares that would have vested if the
performance objectives for the performance cycle were achieved at the maximum
level. These time-based restricted shares will vest if the participant holding
the shares remains employed with the Company or with Reliant Resources and its
subsidiaries through December 31, 2002. On the Distribution Date, holders of
these time-based restricted shares will receive shares of Reliant Resources
common stock in the same manner as other holders of Reliant Energy common stock,
but these shares of common stock will be subject to the same time-based vesting
schedule, as well as to the terms and conditions of the plan under which the
original performance shares were granted. Thus, following the Distribution,
employees who held performance shares under the LICP for the performance cycle
ending December 31, 2002 will hold time-based restricted shares of Reliant
Energy common stock and time-based restricted shares of Reliant Resources common
stock, which will vest following continuous employment through December 31,
2002.
Stock options generally become exercisable in one-third increments on each
of the first through third anniversaries of the grant date. The exercise price
is the average of the high and low sales price of Reliant Energy common stock on
the New York Stock Exchange on the grant date. The Company applies Accounting
Principles Board Opinion No. 25, "Accounting for Stock Issued to Employees" (APB
No. 25), and related interpretations in accounting for its stock option plans.
Accordingly, no compensation expense has been recognized for these fixed stock
options. The following table summarizes stock option activity for the years 1998
through 2000:
NUMBER WEIGHTED AVERAGE
OF SHARES EXERCISE PRICE
---------- ----------------
Outstanding at December 31, 1997......................... 1,074,567 $19.07
Options granted........................................ 2,243,535 26.31
Options exercised...................................... (294,445) 15.66
Options canceled....................................... (78,003)
----------
Outstanding at December 31, 1998......................... 2,945,654 24.87
==========
Options granted........................................ 3,806,051 26.74
Options exercised...................................... (83,610) 19.38
Options canceled....................................... (205,124)
----------
Outstanding at December 31, 1999......................... 6,462,971 25.99
==========
Options granted........................................ 5,936,510 22.14
Options exercised...................................... (1,061,169) 25.01
Options canceled....................................... (1,295,877)
----------
Outstanding at December 31, 2000......................... 10,042,435 24.13
==========
Options exercisable at December 31, 1998................. 531,855 20.31
Options exercisable at December 31, 1999................. 1,350,374 23.87
Options exercisable at December 31, 2000................. 2,258,397 25.76
112
118
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Exercise prices for Reliant Energy stock options outstanding ranged from
$7.00 to $47.22. The following table provides information with respect to stock
options outstanding at December 31, 2000:
AVERAGE REMAINING AVERAGE
OPTIONS EXERCISE CONTRACTUAL LIFE
OUTSTANDING PRICE (YEARS)
----------- -------- -----------------
Ranges of Exercise Prices Exercisable at:
$7.00-$21.00.................................. 4,790,791 $20.42 9.0
$21.01-$26.00................................. 1,700,730 25.31 7.0
$26.01-$47.22................................. 3,550,914 28.57 8.4
----------
Total................................. 10,042,435 24.13 8.5
==========
The following table provides information with respect to Reliant Energy
stock options exercisable at December 31, 2000:
OPTIONS AVERAGE
EXERCISABLE EXERCISE PRICE
----------- --------------
Ranges of Exercise Prices Exercisable at:
$7.00-$21.00.............................................. 150,310 $17.89
$21.01-$26.00............................................. 1,107,248 25.18
$26.01-$33.56............................................. 1,000,839 27.57
---------
Total............................................. 2,258,397 25.76
=========
In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation,"
the Company applies the guidance contained in APB No. 25 and discloses the
required pro forma effect on net income of the fair value based method of
accounting for stock compensation. The weighted average fair values at date of
grant for options granted during 1998, 1999 and 2000 were $4.27, $3.13 and
$5.07, respectively, and were estimated using the Black-Scholes option valuation
model with the following weighted-average assumptions:
1998 1999 2000
------ ------ ------
Expected life in years..................................... 10 5 5
Interest rate.............................................. 5.65% 5.10% 6.57%
Volatility................................................. 24.01% 21.23% 24.00%
Expected common stock dividend............................. $ 1.50 $ 1.50 $ 1.50
Pro forma information for 1998, 1999 and 2000 is provided below, to take
into account the amortization of stock-based compensation to expense on a
straight-line basis over the vesting period. Had compensation costs been
determined as prescribed by SFAS No. 123, the Company's net loss would have been
increased by $6 million in 1998. The Company's net income would have been
reduced by $5 million and $10 million in 1999 and 2000, respectively. Loss per
share would have been increased by $0.02 per share in 1998. Earnings per share
would have been reduced by $0.02 per share and $0.03 per share in 1999 and 2000,
respectively.
In connection with the Distribution, Reliant Energy expects to convert all
outstanding Reliant Energy stock options granted in 2000 and in prior years to a
combination of adjusted Reliant Energy stock options and new Reliant Resources
stock options. For the converted Reliant Energy stock options, the sum of the
intrinsic value of Reliant Energy stock options immediately prior to the
Distribution will equal the sum of the intrinsic values of the adjusted Reliant
Energy stock options and new Reliant Resources stock options granted immediately
after the Distribution. Following the Distribution Date, Reliant Resources
employees who no longer work for the Company due to the Distribution will hold
Reliant Energy stock options.
113
119
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) Pension.
The Company has noncontributory pension plans, that cover the employees of
the Company, except for the employees of its foreign subsidiaries. Effective
January 1, 1999, Reliant Energy amended and restated its plan and converted the
present value of the accrued benefits under the existing pension plan into a
cash balance pension plan. In connection with this conversion, Reliant Energy
grandfathered the existing benefit formulas for all employees participating in
the plan on December 31, 1998 for a period of ten years so that eligible
individuals will receive the greater of the prior pension plan benefit or the
new cash balance benefit upon retirement. Under the cash balance formula, each
participant has an account, for recordkeeping purposes only, to which credits
are allocated annually based on a percentage of the participant's pay. The
applicable percentage for 1999 and 2000 was 4% in each period.
Reliant Energy's funding policy is to review amounts annually in accordance
with applicable regulations in order to achieve adequate funding of projected
benefit obligations. The assets of the pension plans consist principally of
common stocks and high-quality, interest-bearing obligations.
UNA is a foreign subsidiary of the Company and participates along with
other companies in the Netherlands in making payments to pension funds which are
not administered by the Company. The Company treats these as a defined
contribution pension plan which provides retirement benefits for most of its
employees. The contributions are principally based on a percentage of the
employee's base compensation and charged against income as incurred. This
expense was $2 million and $6 million for the three months ended December 31,
1999 and during 2000, respectively.
Net pension cost for the Company (excluding UNA) includes the following
components:
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
(IN MILLIONS)
Service cost -- benefits earned during the period........... $ 33 $ 34 $ 33
Interest cost on projected benefit obligation............... 85 88 88
Expected return on plans assets............................. (121) (141) (146)
Net amortization............................................ -- (5) (12)
----- ----- -----
Net pension benefit....................................... $ (3) $ (24) $ (37)
===== ===== =====
Following are reconciliations of the Company's beginning and ending
balances of its retirement plan benefit obligation, plans assets and funded
status for 1999 and 2000 (excluding UNA):
YEAR ENDED
DECEMBER 31,
-----------------
1999 2000
------- -------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year....................... $ 1,390 $ 1,232
Service cost................................................ 34 33
Interest cost............................................... 88 88
Benefits paid............................................... (98) (85)
Plan amendments............................................. -- 3
Acquisitions................................................ -- 1
Transfer of obligation to non-qualified pension plan........ -- (11)
Actuarial (gain) loss....................................... (182) 58
------- -------
Benefit obligation, end of year............................. $ 1,232 $ 1,319
======= =======
114
120
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED
DECEMBER 31,
-----------------
1999 2000
------- -------
(IN MILLIONS)
CHANGE IN PLANS ASSETS
Plans assets, beginning of year............................. $ 1,430 $ 1,513
Benefits paid............................................... (98) (85)
Actual investment return.................................... 181 (11)
Acquisitions................................................ -- 1
------- -------
Plans assets, end of year................................... $ 1,513 $ 1,418
======= =======
RECONCILIATION OF FUNDED STATUS
Funded status............................................... $ 281 $ 99
Unrecognized transition asset............................... (5) (4)
Unrecognized prior service cost............................. (138) (125)
Unrecognized actuarial loss................................. 11 227
------- -------
Net amount recognized at end of year........................ $ 149 $ 197
======= =======
ACTUARIAL ASSUMPTIONS
Discount rate............................................... 7.5% 7.5%
Rate of increase in compensation levels..................... 3.5-5.5% 3.5-5.5%
Expected long-term rate of return on assets................. 10.0% 10.0%
The transitional asset at January 1, 1986, is being recognized over 17
years, and the prior service cost is being recognized over 15 years. The
actuarial gains and losses are due to changes in actuarial assumptions.
Effective March 1, 2001, the Company will no longer accrue benefits under a
noncontributory pension plan for its domestic non-union employees of Reliant
Resources and Reliant Energy Tegco, Inc. (Resources Participants). Effective
March 1, 2001, each non-union Resources Participant's unvested pension account
balance will be fully vested and a one-time benefit enhancement will be provided
to some qualifying participants. At the Distribution Date, each Resources
Participant will be able to elect to have his pension account balance (a) left
in the Reliant Energy pension plan, (b) rolled over to a new Reliant Resources
savings plan or an individual IRA account, or (c) paid in a lump sum or annuity
distribution. During the first quarter of 2001, the Company incurred a charge to
earnings of $85 million (pre-tax) for the one-time benefit enhancement discussed
above and a gain of $23 million (pre-tax) related to the curtailment of Reliant
Energy's pension plan.
In addition to the noncontributory pension plans discussed above, Reliant
Energy maintains non-qualified pension plans which allow participants to retain
the benefits to which they would have been entitled under Reliant Energy's
noncontributory pension plan except for the federally mandated limits on these
benefits or on the level of salary on which these benefits may be calculated.
The expense associated with these non-qualified plans was $5 million in 1998 and
1999, respectively, and $25 million in 2000. The related accrued benefit
liability at December 31, 1999 and 2000, was $28 million and $92 million,
respectively. During 2000, the Company recognized an additional minimum benefit
liability related to these non-qualified plans as a component of accumulated
other comprehensive loss of $30 million. Effective March 1, 2001, the Company
will not provide non-qualified pension benefits to Reliant Resources and its
participating subsidiaries' employees, or Reliant Energy Tegco, Inc.'s
employees.
(c) Savings Plan.
The Company has employee savings plans that qualify as cash or deferred
arrangements under Section 401(k) of the Internal Revenue Code of 1986, as
amended (the Code). Under the plans, participating
115
121
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
employees may contribute a portion of their compensation, pre-tax or after-tax,
generally up to a maximum of 16% of compensation. The Company matches a portion
of each employee's compensation contributed, with most matching contributions
subject to a vesting schedule. A substantial portion of Reliant Energy's match
is invested in Reliant Energy common stock.
Reliant Energy's savings plan has a leveraged Employee Stock Ownership Plan
(ESOP) component. Reliant Energy may use ESOP shares to satisfy its obligation
to make matching contributions under Reliant Energy's savings plan. Debt service
on the ESOP loan is paid using all dividends on shares in the ESOP, interest
earnings on funds held in the ESOP and cash contributions by Reliant Energy.
Shares of Reliant Energy common stock are released from the encumbrance of the
ESOP loan based on the proportion of debt service paid during the period.
The Company recognizes benefit expense for the ESOP equal to the fair value
of the ESOP shares committed to be released. The Company credits to unearned
ESOP shares the original purchase price of ESOP shares committed to be released
to plan participants with the difference between the fair value of the shares
and the original purchase price recorded to common stock. Dividends on allocated
ESOP shares are recorded as a reduction to retained earnings. Dividends on
unallocated ESOP shares are recorded as a reduction of principal or accrued
interest on the ESOP loan.
The ESOP share balances at December 31, 1999 and 2000 were as follows:
DECEMBER 31,
---------------------------
1999 2000
------------ ------------
Allocated shares transferred/distributed from the savings
plan................................................... 2,115,536 2,397,523
Allocated shares......................................... 5,967,159 7,725,772
Unearned shares.......................................... 10,679,489 8,638,889
------------ ------------
Total original ESOP shares..................... 18,762,184 18,762,184
============ ============
Fair value of unearned ESOP shares....................... $244,293,311 $374,171,880
The Company's savings plan benefit expense was $25 million, $35 million and
$53 million in 1998, 1999 and 2000, respectively.
(d) Postretirement Benefits.
The Company provides some postretirement benefits (primarily medical care
and life insurance benefits) for its retired employees, substantially all of
whom may become eligible for these benefits when they retire. Effective January
1, 1999, Reliant Energy amended its retiree medical plan to create an account
balance for each participant based on credited service at December 31, 1998.
Under the new plan, each participant has an account, for recordkeeping purposes
only, to which a $750 credit is allocated annually. Employees become eligible
for this postretirement benefit after completing five years of service after age
50. At retirement the account balance is converted into one of several annuity
options, the proceeds of which can be used solely to offset the cost of
purchasing medical benefits under Reliant Energy's medical plans. The accounts
may not be taken as a cash distribution.
Under SFAS No. 106, "Employer's Accounting for Postretirement Benefits
Other Than Pensions" (SFAS No. 106), postretirement benefits are accounted for
on an accrual basis using a specified actuarial method based on benefits and
years of service. The Company is amortizing $213 million over a 20-year period
to cover the "transition cost" of adopting SFAS No. 106.
Reliant Energy HL&P is required to fund during each year in an irrevocable
external trust $22 million of postretirement benefit costs, which are included
in its rates. Reliant Energy Minnegasco is required to fund postretirement
benefit costs for the amount included in its rates. The Company, excluding
Reliant Energy
116
122
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
HL&P and Reliant Energy Minnegasco, will continue funding its postretirement
benefits on a pay-as-you-go basis.
Net postretirement benefit cost for the Company includes the following
components:
YEAR ENDED
DECEMBER 31,
------------------
1998 1999 2000
---- ---- ----
(IN MILLIONS)
Service cost -- benefits earned during the period........... $ 8 $ 5 $ 6
Interest cost on projected benefit obligation............... 17 26 29
Expected return on plan assets.............................. (6) (9) (11)
Net amortization............................................ 4 15 12
--- --- ----
Net postretirement benefit cost........................... $23 $37 $ 36
=== === ====
Following are reconciliations of the Company's beginning and ending
balances of its postretirement benefit plans benefit obligation, plan assets and
funded status for 1999 and 2000:
YEAR ENDED
DECEMBER 31,
-----------------
1999 2000
------- -------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year....................... $ 410 $ 395
Service cost................................................ 5 6
Interest cost............................................... 26 29
Benefits paid............................................... (22) (27)
Participant contributions................................... 4 3
Acquisitions................................................ 12 12
Plan amendments............................................. -- 3
Foreign exchange impact..................................... -- (1)
Actuarial (gain) loss....................................... (40) 35
------- -------
Benefit obligation, end of year............................. $ 395 $ 455
======= =======
CHANGE IN PLAN ASSETS
Plan assets, beginning of year.............................. $ 84 $ 105
Benefits paid............................................... (22) (27)
Employer contributions...................................... 33 37
Participant contributions................................... 4 3
Actual investment return.................................... 6 4
------- -------
Plan assets, end of year.................................... $ 105 $ 122
======= =======
RECONCILIATION OF FUNDED STATUS
Funded status............................................... $ (290) $ (333)
Unrecognized transition obligation.......................... 135 126
Unrecognized prior service cost............................. 92 88
Unrecognized actuarial gain................................. (98) (52)
------- -------
Net amount recognized at end of year........................ $ (161) $ (171)
======= =======
117
123
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED
DECEMBER 31,
-----------------
1999 2000
------- -------
(IN MILLIONS)
ACTUARIAL ASSUMPTIONS
Discount rate............................................... 6.6-7.5% 6.6-7.5%
Expected long-term rate of return on assets................. 10.0% 10.0%
Health care cost trend rates -- Under 65.................... 5.8% 8.0%
Health care cost trend rates -- 65 and over................. 6.2% 9.0%
The assumed health care rates gradually decline to 5.5% for both medical
categories by 2010. The actuarial gains and losses are due to changes in
actuarial assumptions.
If the health care cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2000 would
increase by approximately 3.82%. The annual effect of the 1% increase on the
total of the service and interest costs would be an increase of approximately
3.13%. If the health care cost trend rate assumptions were decreased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2000 would
decrease by approximately 3.76%. The annual effect of the 1% decrease on the
total of the service and interest costs would be a decrease of 3.08%.
Effective March 1, 2001, the Company discontinued providing subsidized
postretirement benefits to its domestic non-union employees of Reliant Resources
and its participating subsidiaries and Reliant Energy Tegco, Inc. The Company
incurred a pre-tax loss of $40 million during the first quarter of 2001 related
to the curtailment of the Company's postretirement obligation.
(e) Postemployment Benefits.
Net postemployment benefit costs for former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily health care and life insurance benefits for participants in the
long-term disability plan) were not material in 1998 and were $11 million in
1999 and $2 million in 2000.
(f) Other Non-qualified Plans.
Since 1985, Reliant Energy has had in effect deferred compensation plans
which permit eligible participants to elect each year to defer a percentage of
that year's salary (prior to December 1993, up to 25% or 40%, depending on age,
and beginning in December 1993, up to 100%) and up to 100% of that year's annual
bonus. In general, employees who attain the age of 60 during employment and
participate in Reliant Energy's deferred compensation plans may elect to have
their deferred compensation amounts repaid in (a) fifteen equal annual
installments commencing at the later of age 65 or termination of employment or
(b) a lump-sum distribution following termination of employment. Interest
generally accrues on deferrals made in 1989 and subsequent years at a rate equal
to the average Moody's Long-Term Corporate Bond Index plus 2%, determined
annually until termination when the rate is fixed at the greater of the rate in
effect at age 64 or at age 65. Fixed rates of 19% to 24% were established for
deferrals made in 1985 through 1988. During 1998, 1999 and 2000, the Company
recorded interest expense related to its deferred compensation obligation of $32
million, $22 million and $14 million, respectively. The discounted deferred
compensation obligation recorded by the Company was $151 million and $159
million as of December 31, 1999 and 2000, respectively.
118
124
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(g) Other Employee Matters.
As of December 31, 2000, approximately 38% of the Company's employees are
subject to collective bargaining arrangements, of which contracts covering 8% of
the Company's employees will expire prior to December 31, 2001.
(13) INCOME TAXES
The components of (loss) income from continuing operations before taxes are
as follows:
YEAR ENDED DECEMBER 31,
-----------------------
1998 1999 2000
----- ------ ------
(IN MILLIONS)
United States............................................... $(361) $2,568 $1,137
Foreign..................................................... -- 22 11
----- ------ ------
(Loss) income from continuing operations before
income taxes.................................... $(361) $2,590 $1,148
===== ====== ======
The Company's current and deferred components of income tax (benefit)
expense were as follows:
YEAR ENDED DECEMBER 31,
-------------------------
1998 1999 2000
------- ------ ------
(IN MILLIONS)
Current:
Federal................................................... $ 341 $287 $391
State..................................................... 11 4 25
Foreign................................................... -- -- 3
----- ---- ----
Total current..................................... 352 291 419
----- ---- ----
Deferred:
Federal................................................... (448) 591 (47)
State..................................................... 13 34 1
Foreign................................................... -- -- 4
----- ---- ----
Total deferred.................................... (435) 625 (42)
----- ---- ----
Income tax (benefit) expense................................ $ (83) $916 $377
===== ==== ====
119
125
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
-----------------------
1998 1999 2000
----- ------ ------
(IN MILLIONS)
(Loss) income from continuing operations before income
taxes..................................................... $(361) $2,590 $1,148
Federal statutory rate...................................... 35% 35% 35%
----- ------ ------
Income taxes at statutory rate.............................. (126) 907 402
----- ------ ------
Net addition (reduction) in taxes resulting from:
State income taxes, net of valuation allowances and
federal income tax benefit............................. 16 25 17
Amortization of investment tax credit..................... (20) (21) (18)
Excess deferred taxes..................................... (4) (5) (4)
Difference between book and tax depreciation for which
deferred taxes have not been normalized................ 37 -- --
UNA tax holiday........................................... -- (5) (44)
Federal and foreign valuation allowance................... -- 1 13
Goodwill amortization..................................... 18 18 19
Other, net................................................ (4) (4) (8)
----- ------ ------
Total............................................. 43 9 (25)
----- ------ ------
Income tax (benefit) expense................................ $ (83) $ 916 $ 377
===== ====== ======
Effective rate.............................................. 22.9% 35.4% 32.8%
Following were the Company's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the financial statements and
their respective tax bases:
DECEMBER 31,
---------------
1999 2000
------ ------
(IN MILLIONS)
Deferred tax assets:
Current:
Unrealized loss on indexed debt securities............. $ 675 $ 555
------ ------
Non-current:
Alternative minimum tax and other credit
carryforwards......................................... 35 25
Employee benefits...................................... 95 143
Disallowed plant cost, net............................. 58 56
Operating loss carryforwards........................... 39 84
Contingent liabilities associated with discontinuance
of SFAS No. 71........................................ 74 74
Environmental reserves................................. 10 25
Allowance for doubtful accounts........................ 5 34
Foreign exchange gains................................. -- 26
Other.................................................. 103 88
Valuation allowance.................................... (19) (68)
------ ------
Total non-current deferred tax assets............. 400 487
------ ------
Total deferred tax assets, net.................... $1,075 $1,042
------ ------
120
126
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
DECEMBER 31,
---------------
1999 2000
------ ------
(IN MILLIONS)
Deferred tax liabilities:
Current:
Unrealized gain on AOL Time Warner investment.......... $1,091 $ 864
------ ------
Non-current:
Depreciation........................................... 2,367 2,290
Regulatory assets, net................................. 380 380
Deferred state income taxes............................ 69 69
Deferred gas costs..................................... 32 201
Other.................................................. 93 96
------ ------
Total non-current deferred tax liabilities........ 2,941 3,036
------ ------
Total deferred tax liabilities.................... 4,032 3,900
------ ------
Accumulated deferred income taxes, net............ $2,957 $2,858
====== ======
Tax Attribute Carryforwards. At December 31, 2000, the Company had $20
million, $523 million and $27 million of federal, state and foreign net
operating loss carryforwards, respectively. The losses are available to offset
future respective federal and state taxable income through the year 2020. The
foreign losses available to offset future foreign taxable income will not expire
under current foreign jurisdiction tax law.
At December 31, 2000, the Company had $9 million of federal alternative
minimum tax credits which are available to reduce future federal income taxes
payable over an indefinite period and $1 million of state alternative minimum
tax credits that are available to reduce future state income taxes payable
through the year 2002.
The valuation allowance reflects a net increase of $11 million and $49
million in 1999 and 2000, respectively. This net increase resulted from a
reassessment of the Company's future ability to use federal, state and foreign
tax net operating loss carryforwards, offset by changes in valuation allowances
provided for expiring state net operating loss carryforwards.
UNA Tax Holiday. Under 1998 Dutch tax law relating to the Dutch
electricity industry, UNA qualifies for a zero percent tax rate through December
31, 2001. The tax holiday applies only to the Dutch income earned by UNA.
Beginning January 1, 2002, UNA will be subject to Dutch corporate income tax at
standard statutory rates, which is currently 35%.
Undistributed Earnings of Foreign Subsidiaries. The undistributed earnings
of foreign subsidiaries aggregated $120 million as of December 31, 2000, which,
under existing tax law, will not be subject to U.S. income tax until
distributed. Provisions for U.S. taxes have not been accrued on these
undistributed earnings, as these earnings have been, or are intended to be,
permanently reinvested. In the event of a distribution of these earnings in the
form of dividends, the Company will be subject to U.S. income taxes net of
allowable foreign tax credits.
Tax Refunds. In February 1998, the Company received a refund from the
Internal Revenue Service (IRS) of $141 million in taxes and interest following
an audit of the Company's 1983 and 1984 federal income tax returns. The income
statement effect of this refund was recorded in 1997 earnings.
In 2000, the Company received refunds from the IRS totaling $126 million in
taxes and interest following audits of tax returns and refund claims for Reliant
Energy's 1985, 1986 and 1990 through 1995 tax years, and RERC Corp.'s 1979
through 1993 tax years. The pre-tax income statement effect of $40 million ($26
million after-tax) was recorded in 2000 in other income in the Company's
Consolidated Statement of Operations. Of
121
127
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the refunds, $26 million was recorded as a reduction in goodwill. Reliant
Energy's consolidated federal income tax returns have been audited and settled
through the 1996 tax year. All of RERC Corp.'s consolidated federal income tax
returns have been audited and settled.
(14) COMMITMENTS AND CONTINGENCIES
(a) Capital and Environmental Commitments.
The Company has various commitments for capital and environmental
expenditures. The Wholesale Energy segment has entered into commitments
associated with various non-rate regulated electric generating projects,
including commitments for the purchase of combustion turbines aggregating $436
million. In addition, the Wholesale Energy segment has options to purchase
additional generating equipment for a total estimated cost of $544 million for
future generating projects.
The Company anticipates investing up to $711 million in capital and other
special project expenditures between 2001 and 2005 for environmental compliance.
The Company anticipates expenditures to be as follows (in millions):
2001........................................................ $217
2002........................................................ 259
2003........................................................ 80
2004........................................................ 76
2005........................................................ 79
----
Total............................................. $711
====
(b) Fuel and Purchased Power.
Reliant Energy HL&P is a party to several long-term coal, lignite and
natural gas contracts, which have various quantity requirements and durations.
Minimum payment obligations for coal and transportation agreements that extend
through 2011 are approximately $280 million in 2001, $281 million in 2002 and
$274 million in 2003. Purchase commitments related to lignite mining and lease
agreements, natural gas purchases and storage contracts, and purchased power are
not material to the operations of the Company. Currently, Reliant Energy HL&P is
allowed recovery of these costs through base rates for electric service. As of
December 31, 2000, some of these contracts are above market. The Company
anticipates that stranded costs associated with these obligations will be
recoverable through the stranded costs recovery mechanisms contained in the
Legislation. For information regarding the Legislation, see Note 4(a).
REMA is a party to several long-term fuel supply contracts which have
various quantity requirements and durations. Minimum payment obligations under
these agreements that extend through 2004 are as follows as of December 31, 2000
(in millions):
2001........................................................ $ 85
2002........................................................ 66
2003........................................................ 29
2004........................................................ 14
----
Total............................................. $194
====
The Company's other long-term fuel supply commitments which have various
quantity requirements and durations are not considered material either
individually or in the aggregate to the Company's results of operations or cash
flows.
122
128
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(c) Lease Commitments.
In August 2000, the Company entered into separate sale/leaseback
transactions with each of three owner-lessors for the Company's respective
16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and Shawville
generating stations, respectively, acquired in the REMA acquisition. As lessee,
the Company leases an interest in each facility from each owner-lessor under a
facility lease agreement. The equity interests in all the subsidiaries of REMA
are pledged as collateral for REMA's lease obligations. In addition, the
subsidiaries have guaranteed the lease obligations. The lease documents contain
some restrictive covenants that restrict REMA's ability to, among other things,
make dividend distributions unless REMA satisfies various conditions. The
covenant restricting dividends would be suspended if the direct or indirect
parent of REMA, meeting specified criteria, guarantees the lease obligations.
The Company will make lease payments through 2029. The lease terms expire in
2034.
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2000, which primarily relate to the REMA leases mentioned above. Other
non-cancelable long-term operating leases principally consist of rental
agreements for building space, data processing equipment and vehicles, including
major work equipment.
REMA
SALE-LEASE
OBLIGATION OTHER TOTAL
---------- ----- ------
(IN MILLIONS)
2001....................................................... $ 259 $ 16 $ 275
2002....................................................... 137 10 147
2003....................................................... 77 8 85
2004....................................................... 84 6 90
2005....................................................... 75 6 81
2006 and beyond............................................ 1,188 36 1,224
------ ---- ------
Total............................................ $1,820 $ 82 $1,902
====== ==== ======
Total lease expense for all operating leases was $10 million, $13 million
and $46 million during 1998, 1999 and 2000, respectively.
(d) Cross Border Leases.
During the period from 1994 through 1997, under cross border lease
transactions, UNA leased several of its power plants and related equipment and
turbines to non-Netherlands based investors (the head leases) and concurrently
leased the facilities back under sublease arrangements with remaining terms as
of December 31, 2000, of 1 to 24 years. UNA utilized proceeds from the head
lease transactions to prepay its sublease obligations and to provide a source
for payment of end of term purchase options and other financial undertakings.
The initial sublease obligations totaled $2.4 billion of which $1.7 billion
remained outstanding as of December 31, 2000. These transactions involve UNA
providing to a foreign investor an ownership right in (but not necessarily title
to) an asset, with a leaseback of that asset. The net proceeds to UNA of the
transactions were recorded as a deferred gain and are currently being amortized
to income over the lease terms. At December 31, 1999 and 2000, the unamortized
deferred gain on these transactions totaled $87 million and $77 million,
respectively. The power plants, related equipment and turbines remain on the
financial statements of UNA and continue to be depreciated.
UNA is required to maintain minimum insurance coverages, perform minimum
annual maintenance and, in specified situations, post letters of credit. UNA's
shareholder is subject to some restrictions with respect to the liquidation of
UNA's shares. In the case of early termination of these contracts, UNA would be
contingently liable for some payments to the sublessors, which at December 31,
2000, are estimated to be
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$274 million. Starting in March 2000, UNA was required by some of the lease
agreements to obtain standby letters of credit in favor of the sublessors in the
event of early termination. The amount of the required letters of credit was
$274 million as of December 31, 2000. Commitments for these letters of credit
have been obtained as of December 31, 2000.
(e) Naming Rights to Houston Sports Complex.
In October 2000, the Company acquired the naming rights for the new
football stadium for the Houston Texans, the National Football League's newest
franchise. In addition, the naming rights cover the entertainment and convention
facilities included in the stadium complex. The agreement extends for 32 years.
In addition to naming rights, the agreement provides the Company with
significant sponsorship rights. The aggregate cost of the naming rights will be
approximately $300 million. During the fourth quarter of 2000, the Company
incurred an obligation to pay $12 million in order to secure the long-term
commitment and for the initial advertising of which $10 million was expensed in
the Company's Statement of Consolidated Operations in 2000. Starting in 2002,
when the new stadium is operational, the Company will pay $10 million each year
through 2032 for annual advertising under this agreement.
(f) Transportation Agreement.
A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR
Pipeline Company (ANR) that contemplated that this subsidiary would transfer to
ANR an interest in some of RERC Corp.'s pipeline and related assets. As of
December 31, 1999 and 2000, the Company had recorded $41 million in other
long-term liabilities in the Company's Consolidated Balance Sheets to reflect
the Company's obligation to ANR for the use of 130 Mmcf/day of capacity in some
of the Company's transportation facilities. The level of transportation will
decline to 100 Mmcf/day in the year 2003 with a refund of $5 million to ANR. The
ANR Agreement will terminate in 2005 with a refund of $36 million.
(g) Legal, Environmental and Other Regulatory Matters.
LEGAL MATTERS.
Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996,
the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a
proposed class of all similarly situated cities in Reliant Energy HL&P's service
area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a
wholly owned subsidiary of Reliant Energy) alleging underpayment of municipal
franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of
any kind for business conducted within these cities over the previous four
decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P
expressly impose fees only on its own receipts and only from sales of
electricity for consumption within a city, the Company regards all of
plaintiffs' allegations as spurious and is vigorously contesting the case. The
plaintiffs' pleadings asserted that their damages exceeded $250 million. The
269th Judicial District Court for Harris County granted partial summary judgment
in favor of Reliant Energy dismissing all claims for franchise fees based on
sales tax collections. Other motions for partial summary judgment were denied. A
six-week jury trial of the original claimant cities (but not the class of
cities) ended on April 4, 2000 (three cities case). Although the jury found for
Reliant Energy on many issues, they found in favor of the original claimant
cities on three issues, and assessed a total of $4 million in actual and $30
million in punitive damages. However, the jury also found in favor of Reliant
Energy on the affirmative defense of laches, a defense similar to a statute of
limitations defense, due to the original claimant cities having unreasonably
delayed bringing their claims during the 43 years since the alleged wrongs
began.
The trial court in the three cities case granted most of Reliant Energy's
motions to disregard the jury's findings. The trial court's rulings reduced the
judgment to $1.7 million, including interest, plus an award of $13.7 million in
legal fees. In addition, the trial court granted Reliant Energy's motion to
decertify the class
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
and vacated its prior orders certifying a class. Following this ruling, 45
cities filed individual suits against Reliant Energy in the District Court of
Harris County.
The extent to which issues in the three cities case may affect the claims
of the other cities served by Reliant Energy HL&P cannot be assessed until
judgments are final and no longer subject to appeal. However, the trial court's
rulings disregarding most of the jury's findings are consistent with Texas
Supreme Court opinions over the past decade. The Company estimates the range of
possible outcomes for the plaintiffs to be between zero and $17 million
inclusive of interest and attorneys' fees.
The three cities case has been appealed. The Company believes that the $1.7
million damage award resulted from serious errors of law and that it will be set
aside by the Texas appellate courts. In addition, the Company believes that
because of an agreement between the parties limiting fees to a percentage of the
damages, reversal of the award of $13.7 million in attorneys' fees in the three
cities case is probable.
California Wholesale Market. Reliant Energy and Reliant Energy Services,
Inc. have been named as defendants in class action lawsuits and other lawsuits
filed against a number of companies that own generation plants in California and
other sellers of electricity in California markets. RERC Corp. has also been
named as a defendant on one of the lawsuits. Pursuant to the terms of the master
separation agreement between Reliant Energy and Reliant Resources (see Note
4(b)), Reliant Resources will agree to indemnify RERC Corp. for any damages
arising under this lawsuit, and will agree to indemnify Reliant Energy for
damages arising under any of these lawsuits, and may elect to defend these
lawsuits at Reliant Resources' own expense. Three of these lawsuits were filed
in the Superior Court of the State of California, San Diego County; two were
filed in the Superior Court in San Francisco County. While the plaintiffs allege
various violations by the defendants of state antitrust laws and state laws
against unfair and unlawful business practices, each of the lawsuits is grounded
on the central allegation that defendants conspired to drive up the wholesale
price of electricity. In addition to injunctive relief, the plaintiffs in these
lawsuits seek treble the amount of damages alleged, restitution of alleged
overpayments, disgorgement of alleged unlawful profits for sales of electricity
during all or portions of 2000, costs of suit and attorneys' fees. In one of the
cases the plaintiffs allege aggregate damages of over $4 billion. Defendants
have filed petitions to remove the cases to federal court. Furthermore,
defendants have filed a motion with the Panel on Multidistrict Litigation
seeking transfer and consolidation of all the cases. These lawsuits have only
recently been filed. Therefore, the ultimate outcome of the lawsuits cannot be
predicted with any degree of certainty at this time. However, the Company does
not believe, based on its analysis to date of the claims asserted in these
lawsuits and the underlying facts, that resolution of these lawsuits will have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.
ENVIRONMENTAL MATTERS.
Manufactured Gas Plant Sites. RERC Corp. and its subsidiaries (RERC) and
its predecessors operated a manufactured gas plant (MGP) adjacent to the
Mississippi River in Minnesota, formerly known as Minneapolis Gas Works (MGW)
until 1960. RERC has substantially completed remediation of the main site other
than ongoing water monitoring and treatment. The manufactured gas was stored in
separate holders. RERC is negotiating clean-up of one such holder. There are six
other former MGP sites in the Minnesota service territory. Remediation has been
completed on one site. Of the remaining five sites, RERC believes that two were
neither owned nor operated by RERC. RERC believes it has no liability with
respect to the sites it neither owned nor operated.
At December 31, 1999 and 2000, RERC had accrued $19 million and $17
million, respectively, for remediation of the Minnesota sites. At December 31,
2000, the estimated range of possible remediation costs was $8 million to $36
million. The cost estimates of the MGW site are based on studies of that site.
The remediation costs for the other sites are based on industry average costs
for remediation of sites of similar size.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The actual remediation costs will be dependent upon the number of sites
remediated, the participation of other potentially responsible parties, if any,
and the remediation methods used.
Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded
accruals of $1 million and $2 million, respectively (with a maximum estimated
exposure of approximately $13 million and $17 million at December 31, 1999 and
2000, respectively), for other environmental matters in Minnesota for which
remediation may be required.
Issues relating to the identification and remediation of MGPs are common in
the natural gas distribution industry. The Company has received notices from the
United States Environmental Protection Agency and others regarding its status as
a potentially responsible party (PRP) for other sites. Based on current
information, the Company has not been able to quantify a range of environmental
expenditures for potential remediation expenditures with respect to other MGP
sites.
Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at sites found to be contaminated.
Although the Company is not aware of additional specific sites, it is possible
that other contaminated sites may exist and that remediation costs may be
incurred for these sites. Although the total amount of these costs cannot be
known at this time, based on experience by the Company and that of others in the
natural gas industry to date and on the current regulations regarding
remediation of these sites, the Company believes that the costs of any
remediation of these sites will not be material to the Company's financial
position, results of operations or cash flows.
REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see Note 3(a)), the Company became responsible for
liabilities associated with ash disposal site closures and site contamination at
the acquired facilities in Pennsylvania and New Jersey prior to a plant closing,
except for the first $6 million of remediation costs at the Seward Generating
Station. A prior owner retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. As of
December 31, 2000, REMA has liabilities associated with six ash disposal site
closures and six site investigations and environmental remediations. The Company
has recorded its estimate of these environmental liabilities in the amount of
$36 million as of December 31, 2000. The Company expects approximately $13
million will be paid over the next five years.
UNA Asbestos Abatement and Soil Remediation. Prior to the Company's
acquisition of UNA (see Note 3(b)), UNA had a $25 million obligation primarily
related to asbestos abatement, as required by Dutch law, and soil remediation at
six sites. During 2000, the Company initiated a review of potential
environmental matters associated with UNA's properties. UNA began remediation in
2000 of the properties identified to have exposed asbestos and soil
contamination, as required by Dutch law and the terms of some leasehold
agreements with municipalities in which the contaminated properties are located.
All remediation efforts are to be fully completed by 2005. As of December 31,
2000, the estimated undiscounted liability for this asbestos abatement and soil
remediation was $24 million.
Other. From time to time the Company has received notices from regulatory
authorities or others regarding its status as a PRP in connection with sites
found to require remediation due to the presence of environmental contaminants.
In addition, the Company has been named as a defendant in litigation related to
such sites and in recent years has been named, along with numerous others, as a
defendant in several lawsuits filed by a large number of individuals who claim
injury due to exposure to asbestos while working at sites along the Texas Gulf
Coast. Most of these claimants have been workers who participated in
construction of various industrial facilities, including power plants, and some
of the claimants have worked at locations owned by the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Company. The Company anticipates that additional claims like those received may
be asserted in the future and intends to continue vigorously contesting claims
which it does not consider to have merit. Although their ultimate outcome cannot
be predicted at this time, the Company does not believe, based on its experience
to date, that these matters, either individually or in the aggregate, will have
a material adverse effect on the Company's financial position, results of
operations or cash flows.
OTHER MATTERS. The Company is involved in other legal, environmental, tax
and regulatory proceedings before various courts, regulatory commissions and
governmental agencies regarding matters arising in the ordinary course of
business. Some of these proceedings involve substantial amounts. The Company's
management regularly analyzes current information and, as necessary, provides
accruals for probable liabilities on the eventual disposition of these matters.
The Company's management believes that the disposition of these matters will not
have a material adverse effect on the Company's financial condition, results of
operations or cash flows.
(h) California Wholesale Market Uncertainty.
During the summer and fall of 2000, prices for wholesale electricity in
California increased dramatically as a result of a combination of factors,
including higher natural gas prices and emission allowance costs, reduction in
available hydroelectric generation resources, increased demand, decreases in net
electric imports, structural market flaws including over-reliance on the
electric spot market, and limitations on supply as a result of maintenance and
other outages. Although wholesale prices increased, California's deregulation
legislation kept retail rates frozen below 1996 levels. This caused two of
California's public utilities, which are the Company's customers based on its
deliveries to the Cal PX and the Cal ISO, to amass billions of dollars of
uncollected wholesale power costs and to ultimately default in January and
February 2001 on payments owed for wholesale power purchased through the Cal PX
and from the Cal ISO.
As of December 31, 2000, the Company was owed $101 million by the Cal PX
and $181 million by the Cal ISO. In the fourth quarter of 2000, the Company
recorded a pre-tax provision of $39 million against receivable balances related
to energy sales in the California market. From January 1, 2001 through February
28, 2001, the Company has collected $105 million of these receivable balances.
As of March 1, 2001, the Company was owed a total of $358 million by the Cal
ISO, the Cal PX, the California Department of Water Resources (CDWR) and
California Energy Resource Scheduling, for energy sales in the California
wholesale market from the fourth quarter of 2000 through February 28, 2001.
Management will continue to assess the collectibility of these receivables based
on further developments affecting the California electricity market and the
market participants described herein. Additional provisions to the allowance may
be warranted in the future.
In response to the filing of a number of complaints challenging the level
of wholesale prices, the FERC initiated a staff investigation and issued an
order on December 15, 2000 implementing a series of wholesale market reforms,
including an interim price review procedure for prices above a $150/MWh
"breakpoint" on sales to the Cal ISO and through the Cal PX. The order does not
prohibit sales above the "breakpoint," but the seller is subject to weekly
reporting and monitoring requirements. For each reported transaction, potential
refund liability extends for a period of 60 days following the date any such
transaction is reported to the FERC. On March 9, 2001, the FERC issued a further
order establishing a proxy market clearing price of $273/MWh for January 2001,
and on March 16, 2001 the FERC issued a further order adjusting the proxy market
clearing price to $430/MWh for February 2001. New market monitoring and
mitigation measures to replace the $150/MWh breakpoint and reporting obligation
are being developed by the FERC to take effect on May 1, 2001.
In the FERC's March 9 and March 16 orders, the FERC outlined criteria for
determining amounts subject to possible refund based on the proxy market
clearing price for January and February 2001 and indicated that approximately
$12 million of the $125 million charged by the Company in January 2001 in
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
California to the Cal ISO and the Cal PX and approximately $7 million of the $47
million charged by the Company in February 2001 in California to the Cal ISO and
the Cal PX were subject to possible refunds. In the March 9 and March 16 orders,
the FERC set forth procedures for challenging possible refund obligations.
Because the Company believes that there is cost or other justification for
prices charged above the proxy market clearing prices established in the March 9
and March 16 orders, the Company intends to pursue such a challenge with respect
to the Company's potential refund amounts identified in such orders. Any refunds
the Company may ultimately be obligated to pay are to be credited against unpaid
amounts owed to the Company for its sales in the Cal PX or to the Cal ISO. The
December 15 order established that a refund condition would be in place for the
period beginning October 2, 2000 through December 31, 2002. The December 15
order also eliminated the requirement that California's public utilities sell
all of their generation into and purchase all of their power from the Cal PX and
directed that the Cal PX wholesale tariffs be terminated effective April 2001.
The Cal PX has since suspended its day-ahead and day-of markets and filed for
bankruptcy protection on March 9, 2001. Motions for rehearing have been filed on
a number of issues related to the December 15 order and such motions are still
pending before the FERC.
In addition to the FERC investigation discussed above, several state and
other federal regulatory investigations and complaints have commenced in
connection with the wholesale electricity prices in California and other
neighboring Western states to determine the causes of the high prices and
potentially to recommend remedial action. In California, the California Public
Utilities Commission, the California Electricity Oversight Board, the California
Bureau of State Audits and the California Office of the Attorney General all
have separate ongoing investigations into the high prices and their causes. None
of these investigations have been completed and no findings have been made in
connection with any of them.
Despite the market restructuring ordered under the December 15 order, the
California public utilities have continued to accrue unrecovered wholesale
costs. As a result, the credit ratings of two of these public utilities were
severely downgraded to below investment grade in January 2001. As their credit
lines became unavailable, the two utilities defaulted on payments due to the Cal
PX and the Cal ISO, which operate financially as pass-through entities,
coordinating payments from buyers and sellers of electricity. As a result, the
Cal PX and Cal ISO were not able to pay final invoices to market participants
totaling over $1 billion.
The default of two of California's public utilities on amounts owed the Cal
PX and the Cal ISO for purchased power has further exacerbated the current
crisis in the California wholesale markets and resulted in substantial
uncollected receivables owed to the Company by the Cal ISO and the Cal PX. The
Cal PX's efforts to recover the available collateral of the utilities, in the
form of block forward contracts, have been frustrated by the emergency acts of
California's Governor, who seized control of the contracts upon the expiration
of temporary restraining orders prohibiting such action. Although obligated to
pay reasonable value for the contracts, the state of California has not yet made
any payment for the contracts. Various actions have been filed challenging the
Governor's ability to seize these contracts.
Upon the default of the two utilities of amounts due to the Cal PX, the Cal
PX issued "charge-backs" allocating the utilities' defaults to the other market
participants. Proceedings were brought both in federal court and at the FERC
seeking a suspension of the charge-backs and challenging the reasonableness of
the Cal PX's actions. The Cal PX has since agreed to a preliminary injunction
suspending any of its charge-back activities in order to allow the FERC to
address the charge-back issues. Amounts owed to the Company were debited in
invoices by the Cal PX for charge-backs in the amount of $29 million and, on
February 14, 2001, the Company filed its own lawsuit against the Cal PX in the
United States District Court for the Central District of California, seeking a
recovery of those amounts and a stay of any further charge-backs by the Cal PX.
The filing of bankruptcy by the Cal PX will automatically stay for some period
the various court and administrative cases against the Cal PX.
The two defaulting utilities have both filed lawsuits challenging the
refusal of state regulators to allow wholesale power costs to be passed through
to retail customers under the "filed rate doctrine". The filed rate
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doctrine provides that wholesale power costs approved by the FERC are entitled
to be recovered through rates. Additionally, to address the failing financial
condition of the two defaulting utilities and the utilities' potential
bankruptcy, the California Legislature passed emergency legislation, effective
January 18, 2001 and February 2, 2001, appropriating funds to be used by the
CDWR for the purchase of wholesale electricity on behalf of the utilities and
authorizing the sale of bonds to fund future purchases under long-term power
contracts with wholesale generators. The CDWR began the process of soliciting
bids from generators for long-term contracts and continued the purchasing of
short-term power contracts. No bonds have yet been issued by the CDWR to support
long-term power purchases or to provide credit support for short-term purchases.
As noted above two of California's public utilities have defaulted in their
payment obligations to the Cal PX and the Cal ISO as a result of the refusal of
state regulators to allow them to recover their wholesale power costs. This
refusal by state regulators has also caused the utilities to default on numerous
other financial obligations, which could result in either the voluntary or
involuntary bankruptcy of the utilities. While a bankruptcy filing would result
in further post-petition purchases of wholesale electricity being considered
administrative expenses of the debtor, a substantial delay could be experienced
in the payment of pre-petition receivables pending the confirmation of a
reorganization plan. The California Legislature is currently considering
legislation under which a state entity would be formed to purchase and operate a
substantial share of the transmission lines in California in an effort to
provide cash to the utilities and thereby avoid potential bankruptcy filings by
the utilities. A number of the creditors for the two California public utilities
have indicated, however, that unless California moves quickly with such a plan,
an involuntary bankruptcy filing may be made by one or more of such creditors.
Because California's power reserves remain at low levels, in part as a
result of the lack of creditworthy buyers of power given the defaults of the
California utilities, the Cal ISO has relied on emergency dispatch orders
requiring generators to provide at the Cal ISO's direction all power not already
under contract. The power supplied to the Cal ISO has been used to meet the
needs of the customers of the utilities, even though two of those utilities do
not have the credit required to receive such power and may be unable to pay for
it. The Company has contested the obligation to provide power under these
circumstances. The Cal ISO sought a temporary restraining order compelling the
Company to continue to comply with the emergency dispatch orders despite the
utilities' defaults. Although the payment issue is still disputed, on February
21, 2001, the Company and the CDWR entered into a contract expiring March 23,
2001 for the purchase of all of the Company's available capacity not already
under contract and the litigation has been temporarily stayed. The CDWR is
current in its payments under this contract, but the Company is still owed $108
million for power provided in compliance with the emergency dispatch orders for
the six weeks prior to the agreement. Depending on the outcome of the court
proceedings initiated by the Cal ISO seeking to enjoin us from ceasing power
deliveries to the Cal ISO, the Company may be forced to continue selling power
without the guarantee of payment.
Additionally, the Company is seeking a prompt FERC determination that the
Cal ISO is not complying with the credit provisions of its tariff and a related
order of the FERC issued on February 14, 2001, requiring the Cal ISO not to make
purchases in the real time market unless a creditworthy purchaser is responsible
for such purchases.
(i) Indemnification of Stranded Costs.
The stranded costs in the Dutch electricity market are considered to be the
liabilities, uneconomical contractual commitments, and other costs associated
with obligations entered into by the coordinating body for the Dutch electricity
generating sector, N.V. Samenwerkende elecktriciteits-produktiebedrijven (SEP),
plus some district heating contracts with some municipalities in Holland. As of
December 29, 2000, SEP changed its name to BV Nederlands Elektriciteit
Administratiekantoor.
SEP was incorporated as the coordinating body for four of the large-scale
Dutch electricity generation companies, including UNA, which currently has an
equity interest in SEP of 25%. Among other things, SEP
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prior to 2001 owned and managed the dispatch for the national transmission grid,
coordinated the fuel supply, managed the import and the export of electricity,
and settled production costs for the electricity generation companies.
Under the Cooperation Agreement (OvS Agreement), UNA and the other Dutch
generators agreed to sell their generating output through SEP. Over the years,
SEP incurred stranded costs as a result of a perceived need to cover anticipated
shortages in energy production supply. SEP stranded costs consist primarily of
investments in alternative energy sources and fuel and power purchase contracts
currently estimated to be uneconomical.
In December 2000, the Dutch parliament adopted legislation, The Electricity
Production Sector Transitional Arrangements Act (Transition Act), allocating to
the Dutch generation sector, including UNA, financial responsibility for various
stranded costs contracts and other liabilities of SEP. The Transition Act also
authorizes the government to purchase from SEP at least a majority of the shares
in the Dutch national transmission grid company. The legislation became
effective in all material respects on January 1, 2001.
The Transition Act allocates financial responsibility to the individual
Dutch generators based on their average share in the costs and revenues under
the OvS Agreement during the past ten years. UNA's allocated share of these
costs has been set at 22.5%. In particular, the Transition Act allocates to the
four Dutch generation companies, including UNA, financial responsibility for
SEP's obligations to purchase electricity and gas under an import gas supply
contract and three electricity import contracts. The gas import contract expires
in 2015 and provides for gas imports aggregating 2.283 billion cubic meters per
year. The three electricity contracts have the following capacities and terms:
(a) 300 MW through 2005, (b) 600 MW through 2005 and (c) 600 MW through 2002 and
750 MW through 2009. The generators have the option of assuming their pro rata
interests in the contracts or, subject to the assignment terms of the contracts,
selling their interests to third parties.
The Transition Act provides that, subject to the approval of the European
Commission, the Dutch government will make financial compensations to the Dutch
generation sector for the out of market costs associated with two stranded cost
items: an experimental coal facility and district heating contracts.
The four Dutch generation companies and SEP are in discussions with the
Dutch Ministry of Economic Affairs regarding the implementation of the
Transition Act. The parties have reached an agreement in principle with the
Dutch Ministry of Economic Affairs regarding the compensation to be paid to SEP
for the national transmission grid company. The proposed compensation amount is
NLG 2.55 billion (approximately $1.1 billion based on an exchange rate of 2.34
NLG per U.S. dollar as of December 31, 2000). Although the Transition Act
clarifies many issues regarding the anticipated resolution of the stranded costs
debate in the Netherlands, there remain considerable uncertainties regarding the
exact manner in which the Transition Act will be implemented and the potential
for third parties to challenge the Transition Act on legal and constitutional
grounds.
In connection with the acquisition of UNA, the selling shareholders of UNA
agreed to indemnify UNA for some stranded costs in an amount not to exceed NLG
1.4 billion (approximately $599 million based on an exchange rate of 2.34 NLG
per U.S. dollar as of December 31, 2000), which may be increased in some
circumstances at the option of the Company up to NLG 1.9 billion (approximately
$812 million). Of the total consideration paid by the Company for the shares of
UNA, NLG 900 million (approximately $385 million) has been placed by the selling
shareholders in an escrow account under the direction of the Dutch Ministry of
Economic Affairs to secure the indemnity obligations. Although the Company's
management believes that the indemnity provision will be sufficient to fully
satisfy UNA's ultimate share of any stranded costs obligation, this judgment is
based on numerous assumptions regarding the ultimate outcome and timing of the
resolution of the stranded cost issue, the former shareholders' timely
performance of their obligations under the indemnity arrangement, and the amount
of stranded costs which at present is not determinable.
130
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(j) Operations Agreement with City of San Antonio.
As part of the 1996 settlement of certain litigation claims asserted by the
City of San Antonio with respect to the South Texas Project, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in order to take advantage of each system's lower cost
resources. In January 2000, the contract term was extended for three years and
is expected to terminate in 2009. Under the terms of the joint operations
agreement entered into between CPS and Electric Operations, the Company has
guaranteed CPS minimum annual savings of $10 million up to a total cumulative
savings of $150 million over the term of the agreement. It is anticipated that
the cumulative obligation will be met in the first quarter of 2001. In 1998,
1999 and 2000, savings generated for CPS' account were $14 million, $14 million
and $60 million, respectively. Through December 31, 2000, cumulative savings
generated for CPS' account were $124 million.
(k) Nuclear Insurance.
The Company and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of December 31, 2000. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. The Company and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan.
There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.
(l) Nuclear Decommissioning.
The Company contributes $14.8 million per year to a trust established to
fund its share of the decommissioning costs for the South Texas Project. For a
discussion of the accounting treatment for the securities held in the Company's
nuclear decommissioning trust, see Note 2(l). In July 1999, an outside
consultant estimated the Company's portion of decommissioning costs to be
approximately $363 million. While the current and projected funding levels
currently exceed minimum NRC requirements, no assurance can be given that the
amounts held in trust will be adequate to cover the actual decommissioning costs
of the South Texas Project. Such costs may vary because of changes in the
assumed date of decommissioning and changes in regulatory requirements,
technology and costs of labor, materials and equipment. Pursuant to the
Legislation, costs associated with nuclear decommissioning that have not been
recovered as of January 1, 2002, will continue to be subject to cost-of-service
rate regulation and will be included in a non-bypassable charge to transmission
and distribution customers. For information regarding the effect of the Business
Separation Plan on funding of the nuclear decommissioning trust fund, see Note
4(b).
131
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(15) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
DECEMBER 31,
-------------------------------------
1999 2000
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- ------
(IN MILLIONS)
Financial assets:
Energy derivatives -- non-trading....................... $ -- $ 3 $ -- $ 520
Foreign currency swaps.................................. 6 6 -- --
Financial liabilities:
Long-term debt (excluding capital leases)............... 9,210 9,092 6,607 6,512
Trust preferred securities.............................. 705 599 705 665
Energy derivatives -- non-trading....................... -- 1 -- 69
Foreign currency swaps.................................. -- -- 62 68
The fair values of cash and cash equivalents, investments in debt and
equity securities classified as "available-for-sale" and "trading" in accordance
with SFAS No. 115, and short-term borrowings are estimated to be equivalent to
carrying amounts and have been excluded from the above table. The fair value of
financial instruments included in the trading operations are marked-to-market at
December 31, 1999 and 2000 (see Note 5). Therefore, they are stated at fair
value and are excluded from the above table. The remaining fair values have been
determined using quoted market prices for the same or similar securities when
available or other estimation techniques.
(16) EARNINGS PER SHARE
The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share (EPS) calculations:
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------
1998 1999 2000
--------------- --------------- ---------------
(IN MILLIONS, EXCEPT PER SHARE AND SHARE AMOUNTS)
Basic EPS calculation:
(Loss) income from continuing operations before
extraordinary item............................ $ (278) 1,674 771
Discontinued operations.......................... 137 (9) (331)
Extraordinary (loss) gain........................ -- (183) 7
------------ ------------ ------------
Net (loss) income................................ $ (141) $ 1,482 $ 447
============ ============ ============
Weighted average shares outstanding.............. 284,095,000 285,040,000 284,652,000
Basic EPS:
(Loss) income from continuing operations before
extraordinary item............................ $ (0.98) $ 5.87 $ 2.71
Discontinued operations.......................... 0.48 (0.03) (1.17)
Extraordinary (loss) gain........................ -- (0.64) 0.03
------------ ------------ ------------
Net (loss) income................................ $ (0.50) $ 5.20 $ 1.57
============ ============ ============
132
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FOR THE YEAR ENDED DECEMBER 31,
---------------------------------------------------
1998 1999 2000
--------------- --------------- ---------------
(IN MILLIONS, EXCEPT PER SHARE AND SHARE AMOUNTS)
Diluted EPS calculation:
Net (loss) income................................ $ (141) $ 1,482 $ 447
Plus: Income impact of assumed conversions
Interest on 6 1/4% convertible trust preferred
securities.................................... -- -- --
------------ ------------ ------------
Total earnings effect assuming dilution.......... $ (141) $ 1,482 $ 447
============ ============ ============
Weighted average shares outstanding................ 284,095,000 285,040,000 284,652,000
Plus: Incremental shares from assumed conversions
(1)
Stock options................................. -- 260,000 1,652,000
Restricted stock.............................. -- 698,000 955,000
6 1/4% convertible trust preferred
securities.................................. -- 23,000 14,000
------------ ------------ ------------
Weighted average shares assuming dilution........ 284,095,000 286,021,000 287,273,000
============ ============ ============
Diluted EPS:
(Loss) income from continuing operations before
extraordinary item............................ $ (0.98) $ 5.85 $ 2.68
Discontinued operations.......................... 0.48 (0.03) (1.15)
Extraordinary (loss) gain........................ -- (0.64) 0.03
------------ ------------ ------------
Net (loss) income................................ $ (0.50) $ 5.18 $ 1.56
============ ============ ============
- ---------------
(1) No assumed conversions were included in the computation of diluted earnings
per share for 1998 because additional shares outstanding would result in an
anti-dilutive per share amount. The computation of diluted EPS for 1998
excludes 492,000 shares of restricted stock and purchase options for 434,000
shares of common stock, which would be anti-dilutive if exercised.
Options to purchase 433,915 and 442,385 shares were outstanding for the
years ended December 31, 1999 and 2000, respectively, but were not included in
the computation of diluted EPS because the options' exercise price was greater
than the average market price of the common shares for the respective years.
133
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(17) UNAUDITED QUARTERLY INFORMATION
Summarized quarterly financial data is as follows:
YEAR ENDED DECEMBER 31, 1999
-----------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues................................................... $2,695 $3,614 $4,913 $4,001
Operating income........................................... 266 275 479 238
(Loss) income from continuing operations before
extraordinary item....................................... (137) 62 1,676 73
(Loss) income from discontinued operations, net of tax..... (73) 13 14 37
Extraordinary item, net of tax............................. -- -- -- (183)
Net (loss) income attributable to common stockholders...... (210) 75 1,690 (73)
Basic (loss) earnings per share: (1)
(Loss) income from continuing operations before
extraordinary item.................................... (0.48) 0.21 5.87 0.26
(Loss) income from discontinued operations, net of tax... (0.26) 0.05 0.05 0.13
Extraordinary item, net of tax........................... -- -- -- (0.65)
Net (loss) income attributable to common stockholders.... (0.74) 0.26 5.92 (0.26)
Diluted (loss) earnings per share: (1)
(Loss) income from continuing operations before
extraordinary item.................................... (0.48) 0.21 5.85 0.26
(Loss) income from discontinued operations, net of tax... (0.26) 0.05 0.05 0.13
Extraordinary item, net of tax........................... -- -- -- (0.65)
Net (loss) income attributable to common stockholders.... (0.74) 0.26 5.90 (0.26)
YEAR ENDED DECEMBER 31, 2000
-----------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
-------- -------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE AMOUNTS)
Revenues................................................... $4,213 $5,755 $9,502 $9,869
Operating income........................................... 342 513 776 248
Income from continuing operations before extraordinary
item..................................................... 134 236 395 6
Loss from discontinued operations, net of tax.............. (1) (19) (6) (146)
Loss on disposal of discontinued operations, net of tax.... -- -- -- (159)
Extraordinary item, net of tax............................. -- 7 -- --
Net income (loss) attributable to common stockholders...... 133 224 389 (299)
Basic earnings (loss) per share: (1)
Income from continuing operations before extraordinary
item.................................................. 0.47 0.83 1.38 0.02
Loss from discontinued operations, net of tax............ -- (0.07) (0.02) (0.51)
Loss on disposal of discontinued operations, net of
tax................................................... -- -- -- (0.55)
Extraordinary item, net of tax........................... -- 0.03 -- --
Net income (loss) attributable to common stockholders.... 0.47 0.79 1.36 (1.04)
Diluted earnings (loss) per share: (1)
Income from continuing operations before extraordinary
item.................................................. 0.47 0.82 1.36 0.02
Loss from discontinued operations, net of tax............ -- (0.07) (0.02) (0.51)
Loss on disposal of discontinued operations, net of
tax................................................... -- -- -- (0.55)
Extraordinary item, net of tax........................... -- 0.03 -- --
Net income (loss) attributable to common stockholders.... 0.47 0.78 1.34 (1.04)
134
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(1) Quarterly earnings per common share are based on the weighted average number
of shares outstanding during the quarter, and the sum of the quarters may
not equal annual earnings per common share.
The quarterly operating results incorporate the results of operations of
REMA and UNA from their respective acquisition dates as discussed in Note 3. The
variances in revenues from quarter to quarter were primarily due to these
acquisitions, the seasonal fluctuations in demand for energy and energy services
and changes in energy commodity prices. Changes in operating (loss) income and
net (loss) income from quarter to quarter were primarily due to these
acquisitions, the seasonal fluctuations in demand for energy and energy
services, changes in energy commodity prices and the timing of maintenance
expenses on electric generation plants.
(18) REPORTABLE SEGMENTS
The Company's determination of reportable segments considers the strategic
operating units under which the Company manages sales, allocates resources and
assesses performance of various products and services to wholesale or retail
customers in differing regulatory environments. Financial information for REMA
and UNA are included in the segment disclosures only for periods beginning on
their respective acquisition dates. The accounting policies of the segments are
the same as those described in the summary of significant accounting policies
except that some executive benefit costs have not been allocated to segments.
The Company evaluates performance based on operating income excluding some
corporate costs not allocated to the segments. The Company accounts for
intersegment sales as if the sales were to third parties, that is, at current
market prices. In the fourth quarter of 2000, the Company transferred its
non-rate regulated retail gas marketing operations from Other Operations to
Natural Gas Distribution and its natural gas gathering business from Wholesale
Energy to Pipelines and Gathering. Reportable segments from previous years have
been restated to conform to the 2000 presentation.
135
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
The Company has identified the following reportable segments: Electric
Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy,
European Energy and Other Operations. For a description of the financial
reporting segments, see Note 1. Financial data for business segments, products
and services and geographic areas are as follows:
NATURAL PIPELINES
ELECTRIC GAS AND WHOLESALE EUROPEAN OTHER DISCONTINUED
OPERATIONS DISTRIBUTION GATHERING ENERGY ENERGY OPERATIONS OPERATIONS
---------- ------------ --------- --------- -------- ---------- ------------
(IN MILLIONS)
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
1998:
Revenues from external
customers.............. $ 4,350 $2,363 $ 168 $4,248 $ -- $ 101 $ --
Intersegment revenues.... -- 63 178 168 -- 1 --
Depreciation and
amortization........... 663 131 48 14 -- 10 --
Operating income
(loss)................. 1,002 167 146 42 -- (77) --
Total assets............. 10,025 3,061 2,217 1,458 -- 1,523 1,041
Equity investments in
unconsolidated
subsidiaries........... -- -- -- 42 -- -- --
Expenditures for
long-lived assets...... 433 162 76 347 -- 28 --
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
1999:
Revenues from external
customers.............. 4,483 2,742 163 7,648 153 34 --
Intersegment revenues.... -- 46 168 264 -- 1 --
Depreciation and
amortization........... 667 137 53 21 21 6 --
Operating income
(loss)................. 981 158 131 27 32 (71) --
Total assets............. 9,941 3,700 2,486 2,821 3,247 4,308 1,078
Equity investments in
unconsolidated
subsidiaries........... -- -- -- 78 -- -- --
Expenditures for
long-lived assets...... 573 206 79 481 834 89 --
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
2000:
Revenues from external
customers.............. 5,494 4,379 177 18,655 579 55 --
Intersegment revenues.... -- 33 207 579 -- -- --
Depreciation and
amortization........... 507 145 56 109 75 14 --
Operating income
(loss)................. 1,230 113 137 482 89 (172) --
Total assets............. 10,691 4,462 2,357 11,312 2,473 1,648 195
Equity investments in
unconsolidated
subsidiaries........... -- -- -- 109 -- -- --
Expenditures for
long-lived assets...... 643 195 61 1,966 995 91 --
RECONCILING
ELIMINATIONS CONSOLIDATED
------------ ------------
(IN MILLIONS)
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
1998:
Revenues from external
customers.............. $ -- $11,230
Intersegment revenues.... (410) --
Depreciation and
amortization........... -- 866
Operating income
(loss)................. -- 1,280
Total assets............. (358) 18,967
Equity investments in
unconsolidated
subsidiaries........... -- 42
Expenditures for
long-lived assets...... -- 1,046
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
1999:
Revenues from external
customers.............. -- 15,223
Intersegment revenues.... (479) --
Depreciation and
amortization........... -- 905
Operating income
(loss)................. -- 1,258
Total assets............. (1,125) 26,456
Equity investments in
unconsolidated
subsidiaries........... -- 78
Expenditures for
long-lived assets...... -- 2,262
AS OF AND FOR THE YEAR
ENDED DECEMBER 31,
2000:
Revenues from external
customers.............. -- 29,339
Intersegment revenues.... (819) --
Depreciation and
amortization........... -- 906
Operating income
(loss)................. -- 1,879
Total assets............. (1,061) 32,077
Equity investments in
unconsolidated
subsidiaries........... -- 109
Expenditures for
long-lived assets...... -- 3,951
136
142
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31,
---------------------------
1998 1999 2000
------- ------- -------
(IN MILLIONS)
RECONCILIATION OF OPERATING INCOME TO NET INCOME (LOSS)
ATTRIBUTABLE TO COMMON STOCKHOLDERS:
Operating income............................................ $ 1,280 $ 1,258 $ 1,879
(Loss) income of equity investments......................... (1) (1) 43
Other income................................................ 68 60 83
Gain (loss) on AOL Time Warner investment................... -- 2,452 (205)
(Loss) gain on indexed debt securities...................... (1,176) (629) 102
Interest expense and other charges.......................... (532) (550) (754)
Income tax benefit (expense)................................ 83 (916) (377)
Income (loss) from discontinued operations.................. 137 (9) (172)
Loss on disposal of discontinued operations................. -- -- (159)
Extraordinary (loss) gain, net of tax....................... -- (183) 7
------- ------- -------
Net (loss) income attributable to common
stockholders.................................... $ (141) $ 1,482 $ 447
======= ======= =======
REVENUES BY PRODUCTS AND SERVICES:
Retail power sales.......................................... $ 4,350 $ 4,483 $ 5,494
Retail gas sales............................................ 2,372 2,669 4,291
Wholesale energy and energy related sales................... 4,248 7,808 19,290
Gas transport............................................... 168 158 122
Energy products and services................................ 92 105 142
------- ------- -------
Total............................................. $11,230 $15,223 $29,339
======= ======= =======
REVENUES AND LONG-LIVED ASSETS BY >GEOGRAPHIC AREAS:
Revenues:
US........................................................ $11,230 $14,954 $27,710
Netherlands............................................... -- 153 579
Other..................................................... -- 116 1,050
------- ------- -------
Total............................................. $11,230 $15,223 $29,339
======= ======= =======
Long-lived assets:
US........................................................ $16,287 $16,862 $19,734
Netherlands............................................... -- 3,058 2,335
------- ------- -------
Total............................................. $16,287 $19,920 $22,069
======= ======= =======
(19) DISCONTINUED OPERATIONS
Effective December 1, 2000 (the Measurement Date), the Company's Board of
Directors approved a plan to dispose of its Latin America business segment,
through sales of its Latin American assets. Accordingly, the Company is
reporting the results of its Latin America business segment as discontinued
operations for all periods presented in the Consolidated Financial Statements in
accordance with Accounting Principles Board Opinion No. 30.
In the fourth quarter of 2000, prior to the Measurement Date, the Latin
America business segment sold its investments in El Salvador and a portion of
its investments in Colombia for an aggregate $303 million in after-tax proceeds.
The Company recorded a $127 million after-tax loss in connection with the sale
of these investments which is included in the after-tax loss from discontinued
operations of $172 million (net of an income tax benefit of $46 million) in
2000.
137
143
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Subsequent to the Measurement Date, the Latin America business segment sold
its investments in Brazil and its remaining investments in Colombia for an
aggregate $487 million in after-tax proceeds. The Company recorded a $114
million after-tax loss in connection with the sale of these investments which is
included in the after-tax loss on disposal of discontinued operations of $159
million (net of income taxes of $13 million) in 2000. The total provision for
the disposal of discontinued operations includes a $5 million reserve for
anticipated operating losses through the completion of the sales, which includes
$4 million in operating losses from Measurement Date through December 31, 2000.
There was no interest allocated to the discontinued operations. The Latin
America business segment's remaining investments include a wholly owned
cogeneration facility and a distribution company both located in Argentina and a
minority interest in a coke calcining plant in India. The Company anticipates
that the sale of the remainder of these assets will be completed by December
2001. The amounts that the Company will ultimately realize from this disposal
could be materially different from the amounts assumed in arriving at the
estimated loss on disposal of the discontinued operations. Components of amounts
reflected in the Company's Consolidated Statements of Operations through the
Measurement Date and the Company's Consolidated Balance Sheets are presented in
the following table.
YEAR ENDED
DECEMBER 31,
-------------------
1998 1999 2000
---- ---- -----
(IN MILLIONS)
Income Statement Data:
Revenues.................................................. $ 50 $ 93 $ 80
Operating expenses........................................ 73 98 81
---- ---- -----
Operating loss............................................ (23) (5) (1)
Income (loss) of equity investments....................... 71 (14) (29)
Gain (loss) on sales of assets............................ 138 -- (176)
Other income (expense).................................... 3 (7) (12)
Income tax benefit (expense).............................. (52) 17 46
---- ---- -----
Income (loss) from discontinued operations................ $137 $ (9) $(172)
==== ==== =====
DECEMBER 31,
-------------
1999 2000
------ ----
(IN MILLIONS)
Balance Sheet Data:
Current assets............................................ $ 38 $ 36
Equity investment and other............................... 990 46
Property, plant and equipment, net........................ 126 130
Current liabilities....................................... (63) (14)
Other liabilities......................................... (13) (3)
------ ----
Net assets of discontinued operations..................... $1,078 $195
====== ====
(20) SUBSEQUENT EVENTS
(a) Credit Facilities.
Between December 2000 and March 2001, Reliant Resources entered into eleven
bilateral credit facilities with financial institutions, which provide for an
aggregate of $1.6 billion in committed credit. The facilities became effective
subsequent to December 31, 2000 and expire on October 2, 2001. Concurrent with
the effectiveness of these facilities, $500 million of the facilities of a
financing subsidiary were canceled. Interest rates on the borrowings are based
on LIBOR plus a margin, a base rate or a rate determined through a bidding
138
144
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
process. These facilities contain various business and financial covenants
requiring Reliant Resources to, among other things, maintain a ratio of net debt
to the sum of net debt, subordinated affiliate debt and shareholders' equity not
to exceed 0.60 to 1.00. These covenants are not anticipated to materially
restrict Reliant Resources from borrowing funds or obtaining letters of credit
under these facilities. The credit facilities are subject to commitment and
usage fees that are calculated based on the amount of the facility and/or the
amounts outstanding under the facilities, respectively.
(b) RERC Corp. Debt Issuance.
In February 2001, RERC Corp. issued $550 million of unsecured notes that
bear interest at 7.75% per year and mature in February 2011. Net proceeds to
RERC Corp. were $545 million. RERC Corp. used the net proceeds from the sale of
the notes to pay a $400 million dividend to Reliant Energy, and for general
corporate purposes. Reliant Energy used the $400 million proceeds from the
dividend for general corporate purposes, including the repayment of short-term
borrowings.
(c) Florida Tolling Arrangement.
In the first quarter 2001, the Company entered into tolling arrangements
with a third party to purchase the right to utilize and dispatch electric
generating capacity of approximately 1,100 MW. This electricity is expected to
be generated by two gas-fired, simple-cycle peaking plants, with fuel oil
backup, to be constructed by the tolling partner in Florida, which are
anticipated to be completed by the summer of 2002, at which time the Company
will commence tolling payments.
139
145
INDEPENDENT AUDITORS' REPORT
Reliant Energy, Incorporated:
We have audited the accompanying consolidated balance sheets of Reliant
Energy, Incorporated and its subsidiaries (the Company) as of December 31, 1999
and 2000, and the related statements of consolidated operations, consolidated
comprehensive income, consolidated cash flows and consolidated stockholders'
equity for each of the three years in the period ended December 31, 2000. Our
audits also included the Company's financial statement schedule listed in Item
14(a)(2). These financial statements and the financial statement schedule are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and the financial statement schedule
based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
1999 and 2000, and the consolidated results of its operations and its cash flows
for each of the three years in the period ended December 31, 2000 in conformity
with accounting principles generally accepted in the United States of America.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
March 16, 2001
140
146
ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF RELIANT
ENERGY RESOURCES CORP. AND ITS CONSOLIDATED SUBSIDIARIES.
The following narrative and analysis should be read in combination with the
consolidated financial statements and notes of Reliant Energy Resources Corp.
(RERC Corp.) and its subsidiaries (collectively, RERC) contained in Item 8 of
the Form 10-K of RERC Corp.
RELIANT ENERGY RESOURCES CORP.
Because RERC Corp. is a wholly owned subsidiary of Reliant Energy,
Incorporated (Reliant Energy), RERC's determination of reportable segments
considers the strategic operating units under which Reliant Energy manages
sales, allocates resources and assesses performance of various products and
services to wholesale or retail customers in differing regulatory environments.
Reliant Energy has identified the following reportable segments: Electric
Operations, Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy,
European Energy, and Other Operations. Of these segments, the following
operations have historically been conducted by RERC:
- Natural Gas Distribution,
- Pipelines and Gathering,
- Wholesale Energy (which includes wholesale energy trading, marketing,
power origination and risk management services in North America but
excludes the operations of Reliant Energy Power Generation, Inc., an
indirect wholly owned subsidiary of Reliant Energy),
- European Energy (which includes the energy trading and marketing
operations initiated in the fourth quarter of 1999 in the Netherlands and
other countries in Europe but excludes N.V. UNA, a Dutch power company),
and
- Certain Other Operations.
On July 27, 2000, Reliant Energy announced its intention to divide into two
publicly traded companies in order to separate its unregulated businesses from
its regulated businesses. In August 2000, Reliant Energy formed Reliant
Resources, Inc. (Reliant Resources) to own and operate a substantial portion of
Reliant Energy's unregulated operations and to offer no more than 20% of Reliant
Resources' common stock in an initial public offering (Offering). Reliant Energy
expects the Offering to be followed by a distribution to Reliant Energy's or its
successor's shareholders of the remaining common stock of Reliant Resources
within twelve months after the Offering.
On December 31, 2000, RERC Corp. transferred all of the outstanding capital
stock of Reliant Energy Services International, Inc. (RESI), Arkla Finance
Corporation (Arkla Finance) and Reliant Energy Europe Trading & Marketing, Inc.
(RE Europe Trading), all of which were wholly owned subsidiaries of RERC Corp.,
to Reliant Resources (collectively, Stock Transfer). Both RERC Corp. and Reliant
Resources are wholly owned subsidiaries of Reliant Energy. As a result of the
Stock Transfer, RESI, Arkla Finance and RE Europe Trading each became a wholly
owned subsidiary of Reliant Resources.
Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources
merged with and into Reliant Energy Services, Inc. (Reliant Energy Services), a
wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the
surviving corporation (Merger). As a result of the Merger, Reliant Energy
Services became a wholly owned subsidiary of Reliant Resources. As consideration
for the Stock Transfer and the Merger, Reliant Resources paid $94 million to
RERC Corp.
Reliant Energy Services, together with RESI and RE Europe Trading, conduct
the Wholesale Energy segment's trading, marketing, power origination and risk
management business and operations of Reliant Energy. Arkla Finance is a company
that holds an investment in marketable equity securities.
RERC Corp. has guaranteed or indemnified the performance of a portion of
the obligations of Reliant Energy's trading, marketing, power origination and
risk management businesses. Some of these guarantees
141
147
and indemnities are for fixed amounts, others have a fixed maximum amount and
others do not specify a maximum amount. Pursuant to the master separation
agreement, Reliant Resources will agree to indemnify RERC Corp. for any amounts
RERC Corp. pays under these guarantees and indemnities.
The Stock Transfer and the Merger are part of Reliant Energy's previously
announced restructuring. RERC is reporting the results of RE Europe Trading as
discontinued operations for all periods presented in the consolidated financial
statements in accordance with Accounting Principles Board Opinion No. 30. For
additional information regarding the operating results of the entities
transferred to Reliant Resources, please read Note 13 to RERC's consolidated
financial statements.
RERC Corp. meets the conditions specified in General Instruction I (1)(a)
and (b) to Form 10-K and is thereby permitted to use the reduced disclosure
format for wholly owned subsidiaries of reporting companies specified therein.
Accordingly, RERC Corp. has omitted from this Combined Form 10-K the information
called for by Item 4 (submission of matters to a vote of security holders), Item
10 (directors and executive officers), Item 11 (executive compensation), Item 12
(security ownership of certain beneficial owners and management) and Item 13
(certain relationships and related party transactions) of Form 10-K. In lieu of
the information called for by Item 6 (selected financial data) and Item 7
(management's discussion and analysis of financial condition and results of
operations) of Form 10-K, RERC Corp. has included the following Management's
Narrative Analysis of the Results of Operations to explain material changes in
the amount of revenue and expense items of RERC between 1998, 1999 and 2000.
Reference is hereby made to Item 1 (Business), Item 2 (Properties), Item 3
(Legal Proceedings), Item 5 (Market for Reliant Energy's and RERC Corp's Common
Equity and Related Stockholder Matters), Item 7A (Quantitative and Qualitative
Disclosures about Market Risk) and Item 9 (Changes in and Disagreements with
Accountants on Accounting and Financial Disclosure) of this Combined Form 10-K
for additional information regarding RERC required by the reduced disclosure
format of General Instruction I to Form 10-K.
CONSOLIDATED RESULTS OF OPERATIONS
RERC's results of operations are affected by seasonal fluctuations in the
demand for natural gas and price movements of energy commodities. RERC's results
of operations are also affected by, among other things, the actions of various
federal and state governmental authorities having jurisdiction over rates
charged by RERC, competition in RERC's various business operations, debt service
costs and income tax expense. For a discussion of some other factors that may
affect RERC's future earnings please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Our Future Earnings -- Business Separation and Restructuring," "-- Competitive
and Other Factors Affecting RERC Operations" and "-- Environmental Expenditures"
in Item 7 of Reliant Energy's 2000 Form 10-K.
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148
The following table sets forth selected financial and operating data for
the years ended December 31, 1998, 1999 and 2000, followed by a discussion of
significant variances in period-to-period results:
SELECTED FINANCIAL RESULTS
YEAR ENDED DECEMBER 31,
-----------------------------
1998 1999 2000
------- -------- --------
(IN MILLIONS)
Operating Revenues.................................... $ 6,758 $ 10,543 $ 22,659
Operating Expenses.................................... (6,448) (10,242) (22,327)
------- -------- --------
Operating Income...................................... 310 301 332
Interest Expense, net................................. (111) (119) (143)
Distribution on Trust Preferred Securities............ (1) -- --
Other Income, net..................................... 8 11 2
Income Tax Expense.................................... (112) (89) (93)
------- -------- --------
Income from Continuing Operations..................... 94 104 98
Loss from Discontinued Operations..................... -- (4) (24)
------- -------- --------
Net Income.................................. $ 94 $ 100 $ 74
======= ======== ========
2000 Compared to 1999. RERC's net income for 2000 was $74 million compared
to net income of $100 million in 1999. The $26 million decrease in net income
was primarily due to:
- a decline in operating income of the Natural Gas Distribution segment,
- an after-tax impairment loss of $17 million on marketable equity
securities classified as "available-for-sale" incurred in 2000 by the
Other Operations segment,
- increased third-party interest expense primarily resulting from higher
levels of short-term borrowings and long-term debt during 2000 compared
to 1999, and
- increased start-up costs of the European trading and marketing operations
in 2000 included in loss from discontinued operations.
The above items were partially offset by improved operating results from
the Wholesale Energy segment's trading and marketing operations in North
America, increased operating income from the Pipelines and Gathering segment,
increased interest income earned on margin deposits on energy trading activities
and income resulting from a tax refund in 2000.
During 2000, RERC incurred a pre-tax impairment loss of $27 million on
marketable equity securities classified as "available-for-sale" by the Other
Operations segment. Management's determination to recognize this impairment
resulted from a combination of events occurring in 2000 related to this
investment. These events affecting the investment included changes occurring in
the investment's senior management, announcement of significant restructuring
charges and related downsizing for the entity, reduced earnings estimates for
this entity by brokerage analysts and the bankruptcy of a competitor of the
investment in the first quarter of 2000. These events, coupled with the stock
market value of RERC's investment in these securities continuing to be below
RERC's cost basis, caused management to believe the decline in fair value to be
other than temporary. This investment is held by Arkla Finance which was
transferred to Reliant Resources effective December 31, 2000.
Operating income increased in 2000 by $31 million, or 10%, from 1999. The
increase was primarily due to significantly improved operating margins (revenues
less natural gas and purchased power expenses) from the Wholesale Energy
segment's trading and marketing activity in the western U.S. market (primarily
California and Nevada), increased operating margins (revenues less natural gas
expenses) from the Natural Gas
143
149
Distribution segment and increased gathering and processing revenues from the
Pipelines and Gathering segment. These items were partially offset by increased
operating expenses, including:
- costs incurred in connection with non-rate regulated retail natural gas
business activities outside RERC's established market areas, which have
been discontinued,
- additional provisions against receivable balances resulting from the
implementation of a new billing system for Reliant Energy Arkla,
- increased costs associated with higher staffing levels to support
increased sales and expanded trading and marketing efforts,
- increased depreciation expenses of the Natural Gas Distribution segment,
and
- increased benefit expense related to an updated actuarial valuation of
employee benefit plans.
RERC's operating revenues for 2000 were $22.7 billion compared to $10.5
billion for 1999. The $12.2 billion, or 115%, increase was primarily due to the
increase in the Wholesale Energy segment's trading and marketing revenues from
increased trading volumes for power and natural gas, as well as higher sale
prices for these commodities.
RERC's operating expenses for 2000 were $22.3 billion compared to $10.2
billion in 1999. The $12.1 billion, or 118%, increase was primarily due to an
increase in volumes and cost of purchased power and natural gas, as discussed
above. Other operating expenses also increased due to the increase in expenses
discussed above.
RERC's effective tax rate in 2000 was 49% compared to 46% in 1999. This
increase was primarily due to an increase in state income taxes in 2000 as
compared to 1999.
RERC is reporting the results of RE Europe Trading as discontinued
operations for all periods presented in RERC's consolidated financial statements
in accordance with Accounting Principles Board Opinion No. 30. For additional
information, please read Note 13 to RERC's consolidated financial statements.
The European Energy segment was created in the fourth quarter of 1999 with the
acquisition of N.V. UNA by a subsidiary of Reliant Energy. Beginning in the
second half of 2000, the European Energy segment's trading and marketing
operations began participating in the emerging wholesale energy trading and
marketing industry in Northwest Europe. Losses from discontinued operations in
1999 and 2000 are primarily related to start-up costs for the European trading
and marketing operations. For additional information regarding the operating
results of the other entities transferred to Reliant Resources, please read Note
13 to RERC's consolidated financial statements.
1999 Compared to 1998. RERC's net income for 1999 was $100 million
compared to net income of $94 million in 1998. The $6 million increase was
primarily due to:
- a significant increase in operating margins of the Wholesale Energy
segment's trading and marketing operations, and
- a decrease in RERC's effective tax rate.
The above items were partially offset by decreased earnings in the Natural
Gas Distribution and Pipelines and Gathering segments and increased general
insurance liability expense.
Although results of the Wholesale Energy segment's trading and marketing
operations significantly improved, it continues to incur higher operating
expenses relating to staffing and personnel to support its increased sales and
marketing efforts.
Operating income decreased in 1999 by $9 million, or 3%, from 1998. The
decline was primarily due to increased operating expenses, in particular
employee benefit expenses at the Natural Gas Distribution and Pipelines and
Gathering segments and increased general liability insurance expense. The
decline was partially offset by increased operating income of the Wholesale
Energy segment's trading and marketing operations.
144
150
RERC's operating revenues for 1999 were $10.5 billion compared to $6.8
billion for 1998. The $3.7 billion, or 56%, increase was primarily due to
increased wholesale trading and marketing revenues from increased trading
volumes for power, natural gas and oil, as well as higher sale prices for these
commodities.
RERC's operating expenses for 1999 were $10.2 billion compared to $6.4
billion in 1998. The $3.8 billion, or 59%, increase was primarily attributable
to an increase in volumes and cost of purchased power, natural gas and oil, as
discussed above. In addition, operating expenses also increased due to:
- increased employee benefit expenses for the Natural Gas Distribution and
Pipelines and Gathering segments,
- increased operating expenses to support increased sales and marketing of
the Wholesale Energy segment's trading and marketing operations (as
discussed above), and
- increased general insurance liability expense.
RERC's effective tax rate in 1999 was 46% compared to 54% in 1998. This
decrease was primarily due to a decrease in state income taxes in 1999 as
compared to 1998.
NEW ACCOUNTING PRONOUNCEMENTS
Reference is made to "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- New Accounting Pronouncements" in Item 7
of Reliant Energy's 2000 Form 10-K, which section is incorporated by reference
herein, and Note 2(q) to RERC's consolidated financial statements, for
discussion of new accounting issues that affect RERC.
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
For information regarding RERC's exposure to interest rate, equity market,
foreign currency and commodity price risk, please read the related "Quantitative
and Qualitative Disclosures About Market Risk" in Item 7A of Reliant Energy's
2000 Form 10-K, which information, to the extent it relates to RERC, is
incorporated herein by reference.
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151
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF RERC.
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31,
--------------------------------------
1998 1999 2000
---------- ----------- -----------
REVENUES............................................... $6,758,412 $10,543,545 $22,658,903
EXPENSES:
Natural gas and purchased power........................ 5,603,973 9,307,445 21,241,121
Operation and maintenance.............................. 539,985 632,881 758,827
Depreciation and amortization.......................... 191,891 198,664 214,259
Taxes other than income taxes.......................... 112,258 103,192 112,951
---------- ----------- -----------
6,448,107 10,242,182 22,327,158
---------- ----------- -----------
OPERATING INCOME....................................... 310,305 301,363 331,745
---------- ----------- -----------
OTHER INCOME (EXPENSE):
Interest expense, net.................................. (111,337) (119,492) (142,861)
Distribution on trust preferred securities............. (632) (357) (29)
Other, net............................................. 7,318 11,138 2,645
---------- ----------- -----------
(104,651) (108,711) (140,245)
---------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME
TAXES................................................ 205,654 192,652 191,500
Income Tax Expense..................................... 111,830 88,781 93,272
---------- ----------- -----------
INCOME FROM CONTINUING OPERATIONS...................... 93,824 103,871 98,228
Loss from Discontinued Operations, net of tax of
zero................................................. -- (3,670) (23,861)
---------- ----------- -----------
NET INCOME............................................. $ 93,824 $ 100,201 $ 74,367
========== =========== ===========
See Notes to RERC's Consolidated Financial Statements
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152
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY
AND COMPREHENSIVE INCOME
(THOUSANDS OF DOLLARS)
ACCUMULATED
COMMON STOCK OTHER TOTAL TOTAL
--------------- PAID IN RETAINED COMPREHENSIVE STOCKHOLDER'S COMPREHENSIVE
SHARES AMOUNT CAPITAL EARNINGS INCOME (LOSS) EQUITY INCOME
------ ------ ---------- --------- ------------- ------------- -------------
Stockholder's Equity at December 31,
1997................................. 1,000 $1 $2,463,831 $ 20,847 $ (5,634) $2,479,045
Net Income............................. 93,824 93,824 $ 93,824
Unrealized loss on available-for-sale
securities, net of tax of $5,877..... (10,370) (10,370) (10,370)
--------
Comprehensive Income................... $ 83,454
----- -- ---------- --------- -------- ---------- ========
Balance at December 31, 1998........... 1,000 1 2,463,831 114,671 (16,004) 2,562,499
----- -- ---------- --------- -------- ----------
Net Income............................. 100,201 100,201 $100,201
Foreign currency translation
adjustments from discontinued
operations, net of tax of $16........ 30 30 30
Unrealized loss on available-for-sale
securities, net of tax of $373....... (1,224) (1,224) (1,224)
--------
Comprehensive Income................... $ 99,007
----- -- ---------- --------- -------- ---------- ========
Balance at December 31, 1999........... 1,000 1 2,463,831 214,872 (17,198) 2,661,506
----- -- ---------- --------- -------- ----------
Net Income............................. 74,367 74,367 $ 74,367
Foreign currency translation
adjustments
from discontinued operations, net of
tax of $1,340........................ (2,490) (2,490) (2,490)
Unrealized loss on available-for-sale
securities, net of tax of $1,492..... (2,264) (2,264) (2,264)
Reclassification adjustment for
impairment loss on available-for-sale
securities realized in net income,
net of tax of $9,276................. 17,228 17,228 17,228
Additional minimum non-qualified
pension liability adjustment, net of
tax of $6,068........................ (9,747) (9,747) (9,747)
Transfer of subsidiaries to Reliant
Resources, Inc. ..................... (53,115) (289,239) 4,724 (337,630)
--------
Comprehensive Income................... $ 77,094
----- -- ---------- --------- -------- ---------- ========
Balance at December 31, 2000........... 1,000 $1 $2,410,716 $ -- $ (9,747) $2,400,970
===== == ========== ========= ======== ==========
See Notes to RERC's Consolidated Financial Statements
147
153
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31, DECEMBER 31,
1999 2000
------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents................................. $ 80,127 $ 22,576
Accounts and notes receivable, principally customers,
net..................................................... 980,366 794,904
Unbilled revenue.......................................... 150,961 550,183
Inventory................................................. 115,256 116,101
Price risk management assets.............................. 722,429 --
Prepayments and other current assets...................... 80,331 45,926
---------- ----------
Total current assets........................... 2,129,470 1,529,690
---------- ----------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 2,963,141 3,029,357
---------- ----------
OTHER ASSETS:
Goodwill, net............................................. 1,993,135 1,787,015
Prepaid pension asset..................................... 110,626 141,882
Price risk management assets.............................. 173,590 --
Other..................................................... 151,463 87,821
---------- ----------
Total other assets............................. 2,428,814 2,016,718
---------- ----------
Total Assets................................... $7,521,425 $6,575,765
========== ==========
LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt......................... $ 223,451 $ 146,252
Short-term borrowings..................................... 534,584 635,000
Accounts payable, principally trade....................... 775,621 704,524
Accounts and notes payable -- affiliated companies, net... 91,879 134,707
Taxes accrued............................................. 48,266 69,877
Interest accrued.......................................... 27,965 35,725
Customer deposits......................................... 33,255 33,357
Price risk management liabilities......................... 718,228 --
Other..................................................... 119,111 96,375
---------- ----------
Total current liabilities...................... 2,572,360 1,855,817
---------- ----------
OTHER LIABILITIES:
Accumulated deferred income taxes......................... 532,725 583,857
Price risk management liabilities......................... 142,305 --
Payable under capacity lease agreement.................... 41,000 12,524
Benefit obligations....................................... 161,144 175,144
Notes payable -- affiliated companies, net................ -- 21,718
Net liabilities from discontinued operations.............. 1,314 --
Other..................................................... 187,473 132,329
---------- ----------
Total other liabilities........................ 1,065,961 925,572
---------- ----------
LONG-TERM DEBT.............................................. 1,220,631 1,392,798
---------- ----------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
RERC OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED
SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR
SUBORDINATED DEBENTURES OF RERC........................... 967 608
---------- ----------
STOCKHOLDER'S EQUITY........................................ 2,661,506 2,400,970
---------- ----------
Total Liabilities and Stockholder's Equity..... $7,521,425 $6,575,765
========== ==========
See Notes to RERC's Consolidated Financial Statements
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154
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31,
-----------------------------------
1998 1999 2000
--------- --------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income............................................... $ 93,824 $ 100,201 $ 74,367
Adjustments to reconcile net income to net cash provided
by (used in) operating activities:
Depreciation and amortization.......................... 191,891 198,664 214,259
Deferred income taxes.................................. 31,810 58,055 29,123
Impairment of marketable equity securities............. -- -- 26,504
Changes in other assets and liabilities:
Accounts and notes receivable, net.................. 141,565 (303,644) (1,984,240)
Accounts receivable/payable, affiliates............. 45,670 (5,065) 6,199
Inventory........................................... (102,125) 79,776 (16,539)
Other current assets................................ 9,422 (15,965) (114,850)
Accounts payable.................................... (115,010) 205,145 1,790,040
Interest and taxes accrued.......................... 13,454 (15,381) 58,237
Other current liabilities........................... (12,531) (35,288) 4,041
Net price risk management assets.................... (18,433) (17,053) 2,808
Margin deposits on energy trading activities........ 42,630 (59,467) (206,480)
Federal tax refund.................................. -- -- 26,278
Other assets........................................ (39,547) 30,298 51,413
Other liabilities................................... 3,339 (76,469) 12,856
--------- --------- -----------
Net cash provided by (used in) operating
activities................................... 285,959 143,807 (25,984)
--------- --------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures..................................... (253,972) (288,138) (290,565)
Other, net............................................... 8,068 (6,002) 29,708
--------- --------- -----------
Net cash used in investing activities.......... (245,904) (294,140) (260,857)
--------- --------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Payments of long-term debt............................... (249,253) (255,293) (221,500)
Proceeds from long-term debt............................. 812,849 -- 325,000
Increase (decrease) in short-term borrowings, net........ (390,000) 234,584 100,416
Increase (decrease) in notes with affiliates, net........ (202,800) 242,135 34,265
Other, net............................................... (19,957) (17,542) (8,891)
--------- --------- -----------
Net cash (used in) provided by financing
activities................................... (49,161) 203,884 229,290
--------- --------- -----------
NET (DECREASE) INCREASE IN CASH AND CASH EQUIVALENTS..... (9,106) 53,551 (57,551)
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR....... 35,682 26,576 80,127
--------- --------- -----------
CASH AND CASH EQUIVALENTS AT END OF THE YEAR............. $ 26,576 $ 80,127 $ 22,576
========= ========= ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized).................. $ 111,217 $ 142,399 $ 138,365
Income taxes........................................... 46,522 45,540 37,349
See Notes to RERC's Consolidated Financial Statements
149
155
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(1) BACKGROUND AND BASIS OF PRESENTATION
Reliant Energy Resources Corp. (RERC Corp.), together with its subsidiaries
(collectively, RERC), distributes natural gas, transports natural gas through
its interstate pipelines and provides natural gas gathering and pipeline
services. In addition, historically RERC provided energy services including
wholesale energy trading, marketing, power origination and risk management
services in North America and Western Europe. RERC Corp. is a Delaware
corporation and a wholly owned subsidiary of Reliant Energy, Incorporated
(Reliant Energy).
RERC's natural gas distribution operations (Natural Gas Distribution) are
conducted by three unincorporated divisions (Reliant Energy Entex, Reliant
Energy Minnegasco and Reliant Energy Arkla) and other non-rate regulated retail
gas marketing operations. RERC's pipelines and gathering operations (Pipelines
and Gathering) are conducted by two wholly owned pipeline subsidiaries, Reliant
Energy Gas Transmission Company (REGT) and Mississippi River Transmission
Corporation (MRT) and a wholly owned gas gathering subsidiary, Reliant Energy
Field Services, Inc. (REFS). RERC's principal operations are located in
Arkansas, Louisiana, Minnesota, Mississippi, Missouri, Oklahoma and Texas.
Historically, RERC's wholesale energy trading, marketing, power origination
and risk management activities in North America were conducted primarily by
Reliant Energy Services, Inc. (Reliant Energy Services), a wholly owned
subsidiary of RERC prior to January 1, 2001. RERC's European energy trading and
marketing activities were conducted by Reliant Energy Europe Trading &
Marketing, Inc. (RE Europe Trading), a wholly owned subsidiary of RERC prior to
January 1, 2001.
On July 27, 2000, Reliant Energy announced its intention to divide into two
publicly traded companies in order to separate its unregulated businesses from
its regulated businesses (Business Separation Plan). In August 2000, Reliant
Energy formed Reliant Resources, Inc. (Reliant Resources) to own and operate a
substantial portion of Reliant Energy's unregulated operations and to offer no
more than 20% of Reliant Resources' common stock in an initial public offering
(Offering). Reliant Energy expects the Offering to be followed by a distribution
to Reliant Energy's or its successor's shareholders of the remaining common
stock of Reliant Resources (Distribution) within twelve months after the
Offering (Distribution Date).
On December 31, 2000, RERC transferred all of the outstanding capital stock
of Reliant Energy Services International, Inc. (RESI), Arkla Finance Corporation
(Arkla Finance) and RE Europe Trading, all wholly owned subsidiaries of RERC
Corp., to Reliant Resources (collectively, the Stock Transfer). Both RERC Corp.
and Reliant Resources are wholly owned subsidiaries of Reliant Energy. As a
result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each
became a wholly owned subsidiary of Reliant Resources.
Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources
merged with and into Reliant Energy Services, with Reliant Energy Services as
the surviving corporation (Merger). As a result of the Merger, Reliant Energy
Services became a wholly owned subsidiary of Reliant Resources. Prior to the
Stock Transfer and Merger, RERC Corp. converted $278 million of its
subsidiaries' intercompany debt into contributed capital of those subsidiaries.
The $338 million of net assets transferred to Reliant Resources includes the
debt conversion, RERC Corp.'s investment of $155 million in those subsidiaries
and is net of $94 million of consideration paid to RERC Corp. by Reliant
Resources in connection with the Merger and the Stock Transfer. The Stock
Transfer and Merger were accounted for as a common control business combination.
Prior to January 1, 2001, Reliant Energy Services, RESI and RE Europe
Trading, conducted the trading, marketing, power origination and risk management
business and operations of RERC. Arkla Finance is a company that holds an
investment in marketable equity securities. The Stock Transfer and the Merger
are part of Reliant Energy's previously announced restructuring.
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156
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RERC is reporting the results of RE Europe Trading as discontinued
operations for all periods presented in RERC's Consolidated Financial Statements
in accordance with Accounting Principles Board Opinion No. 30. For additional
information, see Note 13.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Reclassifications and Use of Estimates.
Some amounts from the previous years have been reclassified to conform to
the 2000 presentation of financial statements. These reclassifications do not
affect earnings.
The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.
(b) Market Risk and Uncertainties.
RERC is subject to the risk associated with price movements of energy
commodities and, historically, the credit risk associated with RERC's risk
management activities. For additional information regarding these risks, see
Note 4. RERC is also subject to risks relating to the supply and prices of
natural gas, seasonal weather patterns, technological obsolescence and
regulatory environment in the United States.
(c) Principles of Consolidation.
The accounts of RERC and its wholly owned and majority owned subsidiaries
are included in RERC's Consolidated Financial Statements. All significant
intercompany transactions and balances are eliminated in consolidation. Other
investments, excluding marketable securities, are generally carried at cost.
(d) Revenues.
RERC records natural gas sales and services under the accrual method and
these revenues are generally recognized upon delivery. Natural gas sales and
services not billed by month-end are accrued based upon estimated natural gas
and services delivered. Pipelines and Gathering records revenues as
transportation services are provided. RERC's energy trading and marketing
operations were accounted for under mark-to-market accounting, as discussed in
Note 4.
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157
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(e) Long-lived Assets and Intangibles.
RERC records property, plant and equipment at historical cost. RERC
expenses all repair and maintenance costs as incurred. The cost of utility plant
and equipment retirements is charged to accumulated depreciation. Property,
plant and equipment includes the following:
DECEMBER 31,
ESTIMATED USEFUL ---------------
LIVES (YEARS) 1999 2000
---------------- ------ ------
(IN MILLIONS)
Natural gas distribution............................. 5-50 $1,696 $1,809
Pipelines and gathering.............................. 5-75 1,555 1,582
Other property....................................... 3-20 37 38
------ ------
Total...................................... 3,288 3,429
Accumulated depreciation............................. (325) (400)
------ ------
Property, plant and equipment, net......... $2,963 $3,029
====== ======
Goodwill is amortized on a straight-line basis over 40 years. RERC had $130
million and $170 million accumulated goodwill amortization at December 31, 1999
and 2000, respectively. The goodwill is primarily related to Reliant Energy's
merger with RERC Corp. in 1997. The acquisition of RERC by Reliant Energy was
recorded under the purchase method of accounting. The purchase price was pushed
down to RERC.
RERC periodically evaluates long-lived assets, including property, plant
and equipment, goodwill and specifically identifiable intangibles, when events
or changes in circumstances indicate that the carrying value of these assets may
not be recoverable. The determination of whether an impairment has occurred is
based on an estimate of undiscounted cash flows attributable to the assets, as
compared to the carrying value of the assets. To date, no impairment has been
indicated.
(f) Regulatory Assets.
RERC applies the accounting policies established in Statement of Financial
Accounting Standards (SFAS) No. 71 "Accounting for the Effects of Certain Types
of Regulation" (SFAS No. 71) to the accounts of the utility operations of
Natural Gas Distribution and MRT. As of December 31, 1999 and 2000, RERC had
recorded $4 million and $5 million, respectively, of net regulatory assets.
If, as a result of changes in regulation or competition, RERC's ability to
recover these assets and liabilities would not be assured, then pursuant to SFAS
No. 101, "Regulated Enterprises Accounting for the Discontinuation of
Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121, "Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed Of"
(SFAS No. 121), RERC would be required to write off or write down these
regulatory assets and liabilities. In addition, RERC would be required to
determine any impairment to the carrying costs of plant and inventory assets.
(g) Depreciation and Amortization Expense.
Depreciation is computed using the straight-line method based on economic
lives or a regulatory mandated method. Depreciation for 1998, 1999 and 2000 was
$137 million, $143 million and $153 million, respectively. Amortization of
goodwill for the same periods was $54 million, $53 million and $54 million,
respectively. Other amortization expense was $1 million, $3 million and $7
million in 1998, 1999 and 2000, respectively.
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(h) Capitalization of Interest.
Interest and allowance for funds used during construction (AFUDC) related
to debt for subsidiaries that apply SFAS No. 71 are capitalized as a component
of projects under construction and will be amortized over the assets' estimated
useful lives. During 1998, 1999 and 2000, RERC capitalized interest and AFUDC
related to debt of $2 million in each period.
(i) Income Taxes.
RERC is included in the consolidated income tax returns of Reliant Energy.
RERC calculates its income tax provision on a separate return basis under a tax
sharing agreement with Reliant Energy. RERC uses the liability method of
accounting for deferred income taxes and measures deferred income taxes for all
significant income tax temporary differences. Investment tax credits were
deferred and are being amortized over the estimated lives of the related
property. Current federal and state income taxes are payable to or receivable
from Reliant Energy. For additional information regarding income taxes, see Note
8.
(j) Allowance for Doubtful Accounts.
Accounts and notes receivable, principally customers, net, are net of an
allowance for doubtful accounts of $25 million and $33 million at December 31,
1999 and 2000, respectively. The provision for doubtful accounts in RERC's
Statements of Consolidated Income for 1998, 1999 and 2000 was $16 million, $16
million and $32 million, respectively.
(k) Inventory.
Inventory consists principally of materials and supplies, natural gas and
heating oil. Inventories are valued at the lower of average cost or market,
except for heating oil and natural gas used in the trading and marketing
operations which were accounted for under mark-to-market accounting as discussed
in Note 4(a). Inventory includes the following components:
DECEMBER 31,
-------------
1999 2000
----- -----
(IN MILLIONS)
Materials and supplies...................................... $ 35 $ 33
Natural gas................................................. 78 83
Heating oil................................................. 2 --
---- ----
Total inventory................................... $115 $116
==== ====
(l) Investment in Other Debt and Equity Securities.
In accordance with Statement of Financial Accounting Standards No. 115,
"Accounting for Certain Investments in Debt and Equity Securities" (SFAS No.
115), RERC reports "available-for-sale" securities at estimated fair value in
RERC's Consolidated Balance Sheets and any unrealized gain or loss, net of tax,
as a separate component of stockholder's equity and accumulated other
comprehensive income (loss).
As of December 31, 1999, RERC held marketable equity securities of $9
million classified as "available-for-sale." At December 31, 1999, the
accumulated unrealized loss, net of tax, relating to these equity securities was
$17 million. During 2000, pursuant to SFAS No. 115, RERC incurred a pre-tax
impairment loss equal to the $27 million of cumulative unrealized losses which
was recorded in other income (expense) in RERC's Statement of Consolidated
Income. Management's determination to recognize this impairment resulted from a
combination of events occurring in 2000 related to this investment. Such events
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
affecting the investment included changes occurring in the investment's senior
management, announcement of significant restructuring charges and related
downsizing for the entity, reduced earnings estimates for this entity by
brokerage analysts and the bankruptcy of a competitor of the investment in the
first quarter of 2000. These events, coupled with the stock market value of
RERC's investment in these securities continuing to be below RERC's cost basis,
caused management to believe the decline in fair value of these
"available-for-sale" securities to be other than temporary. On December 31,
2000, RERC transferred all of the outstanding capital stock of Arkla Finance,
which holds this investment, to Reliant Resources as described in Note 1.
(m) Environmental Costs.
RERC expenses or capitalizes environmental expenditures, as appropriate,
depending on their future economic benefit. RERC expenses amounts that relate to
an existing condition caused by past operations, and that do not have future
economic benefit. RERC records undiscounted liabilities related to these future
costs when environmental assessments and/or remediation activities are probable
and the costs can be reasonably estimated. Subject to SFAS No. 71, a
corresponding regulatory asset is recorded in anticipation of recovery through
the rate making process by subsidiaries that apply SFAS No. 71 in some
circumstances.
(n) Foreign Currency Adjustments.
Local currencies are the functional currency of RERC's foreign continuing
operations. Foreign subsidiaries' assets and liabilities 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 stockholder's
equity in other comprehensive income (loss).
(o) Statements of Consolidated Cash Flows.
For purposes of reporting cash flows, RERC considers cash equivalents to be
short-term, highly liquid investments readily convertible to cash.
(p) Changes in Accounting Principles.
In March 1998, the American Institute of Certified Public Accountants
(AICPA) issued Statement of Position (SOP) 98-1, "Accounting for the Costs of
Computer Software Developed or Obtained for Internal Use." This statement
requires capitalization of some costs of internal-use software. RERC adopted SOP
98-1 in the second quarter of 1998 without a material impact on RERC's results
of operations or financial position.
The AICPA's SOP 98-5, "Reporting on the Costs of Start-Up Activities," was
adopted by RERC in the fourth quarter of 1998. This statement requires that
certain costs of start-up activities and organizational costs be expensed as
incurred. The adoption of SOP 98-5 did not have a material impact on RERC's
results of operations or financial position.
RERC adopted Emerging Issues Task Force Issue (EITF) 98-10, "Accounting for
Contracts Involved in Energy Trading and Risk Management Activities" (EITF
98-10), on January 1, 1999. The adoption of EITF 98-10 had no material impact on
RERC's results of operations or financial position.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the Securities and Exchange Commission (SEC) on December 3, 1999. SAB
No. 101 summarizes certain of the SEC staff's views in applying generally
accepted accounting principles to revenue recognition in financial statements.
During 2000, RERC implemented SAB No. 101 without a material impact on RERC's
results of operations or financial position.
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(q) New Accounting Pronouncements.
Effective January 1, 2001, RERC was required to adopt SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" as amended (SFAS
No. 133), which establishes accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts and for hedging activities. This statement requires that derivatives
be recognized at fair value in the balance sheet and that changes in fair value
be recognized either currently in earnings or deferred as a component of other
comprehensive income, depending on the intended use of the derivative, its
resulting designation and its effectiveness. In addition, in June 2000, the
Financial Accounting Standards Board (FASB) issued an amendment that narrows the
applicability of the pronouncement to some purchase and sales contracts and
allows hedge accounting for some other specific hedging relationships. Adoption
of SFAS No. 133 resulted in a cumulative after-tax decrease in accumulated other
comprehensive loss of $38 million in the first quarter of 2001. The adoption
also increased current assets, long-term assets, current liabilities and
long-term liabilities by $88 million, $5 million, $53 million and $2 million,
respectively, in RERC's Consolidated Balance Sheet.
The total impact of our adoption of SFAS No. 133 on earnings and
accumulated other comprehensive income (loss) is dependent upon certain pending
interpretations, which are currently under consideration, including those
related to the "normal purchases and normal sales." The interpretations of this
issue, and others, are currently under consideration by the FASB. While the
ultimate conclusions reached on interpretations being considered by the FASB
could impact the effects of our adoption of SFAS No. 133, RERC does not believe
that such conclusions would have a material effect on its current estimate of
the impact of the adoption.
(3) HISTORICAL RELATED PARTY TRANSACTIONS
Reliant Energy has established a "money fund" through which RERC can borrow
or invest on a short-term basis. As of December 31, 1999 and 2000, RERC had net
borrowings, included in accounts and notes payable-affiliated companies,
totaling $62 million and $120 million, respectively. Net interest income on
these borrowings/investments was $5 million and $6 million for 1998 and 1999,
respectively. Net interest expense on these borrowings/investments was $3
million in 2000.
Reliant Energy Services supplies natural gas to, purchases electricity for
resale from, and provides marketing and risk management services to unregulated
power plants in deregulated markets, acquired or operated by Reliant Energy
Power Generation, Inc., an indirect wholly owned subsidiary of Reliant Energy,
or its subsidiaries. During 1998, 1999 and 2000, the sales and services to
Reliant Energy and its affiliates totaled $96 million, $197 million and $816
million, respectively. Purchases of electricity from Reliant Energy and its
affiliates were $29 million, $116 million and $391 million in 1998, 1999 and
2000, respectively. On December 31, 2000, Reliant Energy Services became a
subsidiary of Reliant Resources. See Note 1.
Reliant Energy provides some corporate services to RERC including various
corporate support services (including accounting, finance, investor relations,
planning, legal, communications, governmental and regulatory affairs and human
resources), information technology services and other shared services such as
corporate security, facilities management, accounts receivable, accounts payable
and payroll, office support services and purchasing and logistics. The costs of
services have been directly charged or allocated to RERC using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, operating expenses and employees. These charges and allocations are not
necessarily indicative of what would have been incurred had RERC been a separate
entity. Amounts charged and allocated to RERC for these services were $29
million, $34 million and $32 million for 1998, 1999 and 2000, respectively, and
are included primarily in operation and maintenance expenses.
155
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
As of December 31, 1999 and 2000, net accounts payable to Reliant Energy
and its subsidiaries, which are not owned by RERC, was $34 million and $75
million, respectively.
Some subsidiaries of RERC have entered into office rental agreements with
Reliant Energy. In 1998, 1999 and 2000, RERC paid $1 million, $2 million and $3
million of rent expense to Reliant Energy for each respective year.
RERC Corp. has guaranteed or indemnified the performance of a portion of
the obligations of Reliant Energy's trading, marketing, power origination and
risk management businesses. Some of these guarantees and indemnities are for
fixed amounts, others have a fixed maximum amount and others do not specify a
maximum amount. Pursuant to the master separation agreement, Reliant Resources
will agree to indemnify RERC Corp. for any amounts RERC Corp. pays under these
guarantees and indemnities.
(4) DERIVATIVE FINANCIAL INSTRUMENTS
(a) Price Risk Management and Trading Activities.
Historically, RERC offered energy price risk management services primarily
related to natural gas, electric power and other energy related commodities,
through Reliant Energy Services. As discussed in Note 1, effective December 31,
2000, Reliant Energy Services is no longer a part of RERC. RERC provided these
services by utilizing a variety of derivative financial instruments, including
(a) fixed and variable-priced physical forward contracts, (b) fixed and
variable-priced swap agreements, (c) options traded in the over-the-counter
financial markets and (d) exchange-traded energy futures and option contracts
(Trading Derivatives). Fixed-price swap agreements require payments to, or
receipts of payments from, counterparties based on the differential between a
fixed and variable price for the commodity. Variable-price swap agreements
require payments to, or receipts of payments from, counterparties based on the
differential between industry pricing publications or exchange quotations.
RERC applied mark-to-market accounting for all of its energy trading,
marketing and price risk management operations. Accordingly, these Trading
Derivatives are recorded at fair value with realized and unrealized gains
(losses) recorded as a component of revenues. The recognized, unrealized
balances are included in price risk management assets/liabilities.
The notional quantities, maximum terms and estimated fair value of Trading
Derivatives at December 31, 1999 are presented below (volumes in billions of
British thermal units equivalent (Bbtue) and dollars in millions):
VOLUME-FIXED
VOLUME-FIXED PRICE MAXIMUM
PRICE PAYOR RECEIVER TERM (YEARS)
------------ ------------ ------------
1999
Natural gas.................................... 1,278,953 1,251,319 9
Electricity.................................... 242,868 239,452 10
Oil and other.................................. 285,251 286,521 3
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
FAIR VALUE AVERAGE FAIR VALUE(1)
---------------------- ----------------------
ASSETS LIABILITIES ASSETS LIABILITIES
------ ----------- ------ -----------
1999
Natural gas................................. $581 $564 $550 $534
Electricity................................. 122 91 96 74
Oil and other............................... 193 206 183 187
---- ---- ---- ----
$896 $861 $829 $795
==== ==== ==== ====
- ---------------
(1) Computed using the ending balance of each quarter.
In addition to the fixed-price notional volumes above, RERC also had
variable-priced agreements, as discussed above, totaling 2,147,173 Bbtue as of
December 31, 1999. Notional amounts reflect the commodity volumes underlying the
transactions but do not represent the amounts exchanged by the parties to the
financial instruments. Accordingly, notional amounts do not accurately measure
RERC's exposure to market or credit risks.
All of the fair values shown in the table above at December 31, 1999, have
been recognized in income. RERC estimated the fair value as of December 31,
1999, using quoted prices where available and other valuation techniques when
market data was not available, for example in illiquid markets. For financial
instruments for which quoted prices are not available, RERC utilized alternative
pricing methodologies, including, but not limited to, extrapolation of forward
pricing curves using historically reported data from illiquid pricing points.
These same pricing techniques were used to evaluate a contract prior to taking
the position.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum and average terms disclosed herein are not
indicative of likely future cash flows, as these positions may be changed by new
transactions in the trading portfolio at any time in response to changing market
conditions, market liquidity and RERC's risk management portfolio needs and
strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
In addition to the risk associated with price movements, credit risk was
also inherent in RERC's risk management activities. Credit risk relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. The following table shows the composition of the total price risk
management assets of RERC as of December 31, 1999.
DECEMBER 31, 1999
------------------
INVESTMENT
GRADE(1) TOTAL
---------- -----
(IN MILLIONS)
Energy marketers............................................ $202 $230
Financial institutions...................................... 90 159
Gas and electric utilities.................................. 220 221
Oil and gas producers....................................... 31 31
Industrials................................................. 3 4
Others...................................................... 174 263
---- ----
Total............................................. $720 908
====
Credit and other reserves................................... (12)
----
Energy price risk management assets......................... $896
====
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
- ---------------
(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.
(b) Non-trading Activities.
To reduce the risk from market fluctuations in the revenues derived from
the sale of natural gas and related transportation, RERC enters into futures
transactions, forward contracts, swaps and options (Energy Derivatives) in order
to hedge some expected purchases of natural gas and sales of natural gas (a
portion of which are firm commitments at the inception of the hedge). Energy
Derivatives are also utilized to fix the price of compressor fuel or other
future operational gas requirements and to protect natural gas distribution
earnings against unseasonably warm weather during peak gas heating months,
although usage to date for this purpose has not been material. RERC applies
hedge accounting for its derivative financial instruments utilized in
non-trading activities. Unrealized changes in the market value of Energy
Derivatives utilized as hedges are not generally recognized in RERC's Statements
of Consolidated Income until the underlying hedged transaction occurs. Once it
becomes probable that an anticipated transaction will not occur, RERC recognizes
deferred gains and losses. In general, the financial impact of transactions
involving these Energy Derivatives is included in RERC's Statements of
Consolidated Income under the captions fuel expenses, in the case of natural gas
transactions and revenues, in the case of natural gas sales transactions. Cash
flows resulting from these transactions in Energy Derivatives are included in
RERC's Statements of Consolidated Cash Flows in the same category as the item
being hedged.
For transactions involving Energy Derivatives, hedge accounting is applied
only if the derivative reduces the risk of the underlying hedged item and is
designated as a hedge at its inception. Additionally, the derivatives must be
expected to result in financial impacts that are inversely correlated to those
of the item(s) to be hedged. This correlation, a measure of hedge effectiveness,
is measured both at the inception of the hedge and on an ongoing basis, with an
acceptable level of correlation of at least 80% for hedge designation. If and
when correlation ceases to exist at an acceptable level, hedge accounting ceases
and mark-to-market accounting is applied.
At December 31, 1999, RERC was a fixed-price payor and a fixed-price
receiver in Energy Derivatives covering 29,596 billion British thermal units
(Bbtu) and 5,481 Bbtu of natural gas, respectively. At December 31, 2000, RERC
was a fixed-price payor and a fixed-price receiver in Energy Derivatives
covering 40,991 Bbtu and 14,949 Bbtu of natural gas, respectively. In addition
to the fixed-price notional volumes, RERC also has variable-priced agreements
totaling 41,341 Bbtu and 12,630 Bbtu at December 31, 1999 and 2000,
respectively. The weighted average maturity of these instruments is less than
one year.
The notional amount is intended to be indicative of RERC's level of
activity in these derivatives. However, the amounts at risk are significantly
smaller because, in view of the price movement correlation required for hedge
accounting, changes in the market value of these derivatives generally are
offset by changes in the value associated with the underlying physical
transactions or in other derivatives. When Energy Derivatives are closed out in
advance of the underlying commitment or anticipated transaction, however, the
market value changes may not offset due to the fact that price movement
correlation ceases to exist when the positions are closed, as further discussed
above. Under these circumstances, gains (losses) are deferred and recognized as
a component of income when the underlying hedged item is recognized in income.
The average maturity discussed above and the fair value discussed in Note
10 are not necessarily indicative of likely future cash flows as these positions
may be changed by new transactions at any time in response to changing market
conditions, market liquidity and RERC's risk management portfolio needs and
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
strategies. Terms regarding cash settlements of these contracts vary with
respect to the actual timing of cash receipts and payments.
(c) Trading and Non-trading -- General Policy.
In addition to the risk associated with price movements, credit risk is
also inherent in RERC's risk management activities. Credit risk relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. RERC has off-balance sheet risk to the extent that the
counterparties to these transactions may fail to perform as required by the
terms of each contract. In order to minimize this risk, RERC enters into these
contracts primarily with counterparties having a minimum investment grade index
rating, i.e. a Standard & Poor's or Moody's rating of BBB- or Baa3,
respectively. For long-term arrangements, RERC periodically reviews the
financial condition of these firms in addition to monitoring the effectiveness
of these financial contracts in achieving RERC's objectives. If the
counterparties to these arrangements fail to perform, RERC would seek to compel
performance at law or otherwise obtain compensatory damages. RERC might be
forced to acquire alternative hedging arrangements or be required to replace the
underlying commitment at then-current market prices. In this event, RERC might
incur additional losses to the extent of amounts, if any, already paid to the
counterparties.
RERC's policies prohibit the use of leveraged financial instruments. A
leveraged instrument, for this purpose, is a transaction involving a derivative
whose financial impact will be based on an amount other than the notional amount
or volume of the instrument.
Reliant Energy has established a Risk Oversight Committee, comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including RERC's trading, marketing, power origination
and risk management activities. The committee's duties are to establish RERC's
commodity risk policies, allocate risk capital within limits established by
Reliant Energy's Board of Directors, approve trading of new products and
commodities, monitor risk positions and ensure compliance with Reliant Energy's
risk management policies and procedures and trading limits established by
Reliant Energy's Board of Directors.
(5) LONG-TERM DEBT AND SHORT-TERM BORROWINGS
DECEMBER 31, 1999 DECEMBER 31, 2000
---------------------- ----------------------
LONG-TERM CURRENT(1) LONG-TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Short-term borrowings:
Receivables facilities........................... $350 $350
Commercial paper................................. 185 285
---- ----
Total short-term borrowings.............. 535 635
---- ----
Long-term debt:
Convertible debentures 6.0% due 2012............. $ 93 -- $ 93 --
Debentures 6.38% to 8.90% due 2003 to 2008....... 962 -- 1,285 --
Notes payable 8.77% to 9.23% due 2001............ 150 223 -- 146
Unamortized discount and premium(2)................ 16 -- 15 --
------ ---- ------ ----
Total long-term debt..................... 1,221 223 1,393 146
------ ---- ------ ----
Total borrowings......................... $1,221 $758 $1,393 $781
====== ==== ====== ====
- ---------------
(1) Includes amounts due within one year of the date.
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(2) Included in unamortized discount and premium is unamortized premium related
to fair value adjustments of long-term debt of $18 million and $13 million
at December 31, 1999 and 2000, respectively. These fair value adjustments
resulted from Reliant Energy's acquisition of RERC and are being amortized
over the remaining term of the related long-term debt.
(a) Short-term Borrowings.
In 2000, RERC met its short-term financing needs primarily through a
receivables facility and the issuance of commercial paper in addition to
advances from subsidiaries of Reliant Energy. RERC has a $350 million revolving
credit facility (RERC Credit Facility) that expires in 2003. The RERC Credit
Facility is used to support RERC's issuance of up to $350 million of commercial
paper and includes a $65 million sub-facility under which letters of credit may
be obtained. Borrowings under the RERC Credit Facility are unsecured and bear
interest at a rate based upon either the London interbank offered rate (LIBOR)
plus a margin, a base rate or a rate determined through a bidding process. As of
December 31, 1999 and 2000, RERC had $185 million and $285 million,
respectively, of commercial paper outstanding with an average interest rate of
7.24% and 8.38%, respectively. Letters of credit outstanding under the
sub-facility aggregated $9 million and $65 million as of December 31, 1999 and
2000, respectively.
Under a trade receivables facility (Receivables Facility) which expires in
August 2001, RERC sells, with limited recourse, an undivided interest (limited
to a maximum of $350 million as of December 31, 1999 and 2000) in a designated
pool of accounts receivable. The amount advanced under the receivables facility
was $350 million at December 31, 1999 and 2000. The weighted average interest
rate was approximately 6.10% and 6.58% at December 31, 1999 and December 31,
2000, respectively.
(b) Long-term Debt.
Consolidated maturities of long-term debt and sinking fund requirements,
which are $7 million per year, for RERC are $152 million in 2001, $7 million in
2002, $507 million in 2003, $7 million in 2004 and $332 million in 2005.
At December 31, 2000, RERC Corp. had issued and outstanding $98 million
aggregate principal ($93 million carrying amount) amount of its 6% Convertible
Subordinated Debentures due 2012 (Subordinated Debentures). The holders of the
Subordinated Debentures receive interest quarterly and have the right at any
time on or before the maturity date thereof to convert each Subordinated
Debenture into 0.65 shares of Reliant Energy common stock and $14.24 in cash.
During 1999, RERC purchased $12 million aggregate principal amount of its
Subordinated Debentures.
In November 1998, RERC Corp. issued $500 million aggregate principal amount
of its 6 3/8% Term Enhanced ReMarketable Securities (TERM Notes). The TERM Notes
provide to the investment bank a call option, which gives it the right to have
the TERM Notes redeemed from the investors on November 1, 2003 and then
remarketed if it chooses to exercise the option. The TERM Notes are unsecured
obligations of RERC Corp. which bear interest at an annual rate of 6 3/8%
through November 1, 2003. On November 1, 2003, the holders of the TERM Notes are
required to tender their notes at 100% of their principal amount. The portion of
the proceeds attributable to the call option premium will be amortized over the
stated term of the securities. If the option is not exercised by the investment
bank, RERC Corp. will repurchase the TERM Notes at 100% of their principal
amount on November 1, 2003. If the option is exercised, the TERM Notes will be
remarketed on a date, selected by RERC Corp., within the 52-week period
beginning November 1, 2003. During this period and prior to remarketing, the
TERM Notes will bear interest at rates, adjusted weekly, based on an index
selected by RERC Corp. If the TERM Notes are remarketed, the final maturity date
of the TERM Notes will be November 1, 2013, subject to adjustment, and the
effective interest rate on
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(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
the remarketed TERM Notes will be 5.66% plus RERC Corp.'s applicable credit
spread at the time of such remarketing.
(c) Restrictions on Debt.
RERC Corp.'s facilities contain various business and financial covenants
requiring RERC Corp. to, among other things, maintain leverage (as defined in
the credit facilities), below specified ratios. These covenants are not
anticipated to materially restrict RERC Corp. from borrowing funds or issuing
letters of credit under these facilities. As of December 31, 2000, RERC Corp.
was in compliance with these debt covenants.
(6) TRUST PREFERRED SECURITIES
In June 1996, a Delaware statutory business trust created by RERC Corp.
(RERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. RERC Corp. accounts for RERC Trust as a wholly owned
consolidated subsidiary. RERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by RERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent RERC Trust's sole assets
and its entire operations. RERC Corp. considers its obligation under the Amended
and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to
the convertible preferred securities, taken together, to constitute a full and
unconditional guaranty by RERC Corp. of RERC Trust's obligations with respect to
the convertible preferred securities.
The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Reliant Energy common stock. During 1998, 1999 and 2000, convertible preferred
securities aggregating $16 million, $0.2 million and $0.3 million, respectively,
were converted, leaving $0.7 million and $0.4 million liquidation amount of
convertible preferred securities outstanding at December 31, 1999 and 2000,
respectively. The securities, and their underlying junior subordinated
debentures, bear interest at 6.25% and mature in June 2026. Subject to some
limitations, RERC Corp. has the option of deferring payments of interest on the
convertible junior subordinated debentures. During any deferral or event of
default, RERC Corp. may not pay dividends on its common stock to Reliant Energy.
As of December 31, 2000, no interest payments on the subordinated debentures had
been deferred.
(7) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS
(a) Incentive Compensation Plans.
RERC participates in Reliant Energy's Long-Term Incentive Compensation Plan
(LICP) and other incentive compensation plans that provide for the issuance of
stock-based incentives, including performance-based stock compensation,
restricted shares, stock options and stock appreciation rights, to key employees
of RERC, including officers. No stock appreciation rights have ever been issued
under the LICP. Stock-based incentive expense information presented herein
represents RERC's portion of the overall plans. As of December 31, 2000, 186
current and 15 former employees of RERC participate in the plans.
Performance-based shares and restricted shares are granted to employees
without cost to the participants. The performance shares vest three years after
the grant date based upon the performance of Reliant Energy and its subsidiaries
over a three-year cycle except as discussed below. The restricted shares vest to
the participants at various times ranging from immediate vesting to vesting at
the end of a three-year period. Upon
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
vesting, the shares are released to the plans' participants. During 1998, 1999
and 2000, RERC recorded compensation expense of $2 million, $1 million and $4
million, respectively, related to performance-based shares and restricted share
grants.
Outstanding performance shares under the LICP will vest for the performance
cycle ending December 31, 2000 according to the terms and conditions of the
plan. Assuming the Distribution occurs during the calendar year 2001, Reliant
Energy's compensation committee will determine as of the Distribution Date the
level at which the performance objectives are expected to have been achieved
through the end of the performance cycle ending December 31, 2001 and vest the
outstanding performance shares as of the Distribution Date as though the
performance objectives were achieved at that level. In addition, as of the
Distribution Date, Reliant Energy's compensation committee will convert
outstanding performance shares for the performance cycle ending December 31,
2002 to a number of time-based restricted shares of Reliant Energy's common
stock equal to the number of performance shares that would have vested if the
performance objectives for the performance cycle were achieved at the maximum
level. These time-based restricted shares will vest if the participant holding
the shares remains employed with RERC or its affiliates through December 31,
2002. On the Distribution Date, holders of these time-based restricted shares
will receive shares of Reliant Resources' common stock in the same manner as
other holders of Reliant Energy common stock, but these shares of common stock
will be subject to the same time-based vesting schedule as well as the terms and
conditions of the plan under which the original performance shares were granted.
Thus, following the Distribution, employees who held performance shares under
the LICP for the performance cycle ending December 31, 2002 will hold time-based
restricted shares of Reliant Energy common stock and time-based restricted
shares of Reliant Resources common stock which will vest following continuous
employment through December 31, 2002.
Reliant Energy stock options generally become exercisable in one-third
increments on each of the first through third anniversaries of the grant date.
The exercise price is the average of the high and low sales price of Reliant
Energy common stock on the New York Stock Exchange on the grant date. RERC
applies Accounting Principles Board Opinion No. 25, "Accounting for Stock Issued
to Employees" (APB No. 25), and related interpretations in accounting for its
stock option plans. Accordingly, no compensation expense has been recognized for
these fixed stock options.
In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation,"
RERC applies the guidance contained in APB No. 25, and discloses the required
pro forma effect on net income of the fair value based method of accounting for
stock compensation. The weighted average fair values at date of grant for
Reliant Energy options granted to RERC employees during 1998, 1999 and 2000 were
$4.27, $3.13 and $5.07, respectively, and were estimated using the Black-Scholes
option valuation model with the following weighted-average assumptions:
1998 1999 2000
------ ------ ------
Expected life in years..................................... 10 5 5
Interest rate.............................................. 5.65% 5.10% 6.57%
Volatility................................................. 24.01% 21.23% 24.00%
Expected common stock dividend............................. $ 1.50 $ 1.50 $ 1.50
Pro forma information for 1998, 1999 and 2000 is provided below, to take
into account the amortization of stock-based compensation to expense on a
straight line basis over the vesting period. Had compensation costs been
determined as prescribed by SFAS No. 123, RERC's net income would have been
reduced by $1 million in 1998 and 1999, respectively and $2 million in 2000.
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(b) Pension.
Prior to 1999, RERC had two noncontributory pension plans that covered
substantially all of its employees: (a) the plan that covered RERC's employees
other than Reliant Energy Minnegasco employees and (b) the plan that covered
Reliant Energy Minnegasco employees. These plans provided pension benefits based
on years of service and compensation. Effective January 1, 1999, the two
noncontributory pension plans were merged into Reliant Energy's noncontributory
pension plan. Effective January 1, 1999, Reliant Energy amended and restated its
plan and converted the present value of the accrued benefits under the existing
pension plan into a cash balance pension plan. In connection with this
conversion, Reliant Energy grandfathered the existing benefit formulas for all
employees participating in the prior plans on December 31, 1998 for a period of
ten years so that eligible individuals will receive the greater of the prior
pension plan benefit or the new cash balance benefit upon retirement. Under the
cash balance formula, each participant has an account, for recordkeeping
purposes only, to which credits are allocated annually based on a percentage of
the participant's pay. The applicable percentage for 1999 and 2000 was 4% in
each period.
Reliant Energy's funding policy is to review amounts annually in accordance
with applicable regulations in order to achieve adequate funding of projected
benefit obligations. The assets of the pension plan consist principally of
common stocks and high-quality, interest-bearing obligations. The net periodic
pension benefits and prepaid pension costs and benefit obligation were
determined separately for each plan prior to the above-described merger of the
plans. Since this merger into Reliant Energy's plan, the net periodic pension
benefits, prepaid pension costs and benefit obligation of RERC have been
determined based on the employees of RERC and their respective compensation
levels.
Net pension cost for RERC includes the following components:
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
(IN MILLIONS)
Service cost -- benefits earned during the period........... $ 14 $ 15 $ 12
Interest cost on projected benefit obligation............... 33 35 33
Expected return on plan assets.............................. (53) (61) (62)
Net amortization............................................ -- (2) (4)
---- ---- ----
Net pension benefit......................................... $ (6) $(13) $(21)
==== ==== ====
Reconciliations of RERC's beginning and ending balances of its retirement
plan benefit obligation, plan assets and funded status for 1999 and 2000 are set
forth below:
YEAR ENDED
DECEMBER 31,
-------------------
1999 2000
-------- --------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year....................... $ 553 $ 447
Service cost................................................ 15 12
Interest cost............................................... 35 33
Benefits paid............................................... (35) (41)
Transfer of trading operations to affiliate................. -- (1)
Transfer of obligation to non-qualified plan................ -- (10)
Actuarial (gain) loss....................................... (121) 59
-------- --------
Benefit obligation, end of year............................. $ 447 $ 499
======== ========
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED
DECEMBER 31,
-------------------
1999 2000
-------- --------
(IN MILLIONS)
CHANGE IN PLAN ASSETS
Plan assets, beginning of year.............................. $ 624 $ 620
Benefits paid............................................... (35) (41)
Transfer of trading operations to affiliate................. -- (1)
Actual investment return.................................... 31 20
-------- --------
Plan assets, end of year.................................... $ 620 $ 598
======== ========
RECONCILIATION OF FUNDED STATUS
Funded status............................................... $ 173 $ 99
Unrecognized prior service cost............................. (48) (45)
Unrecognized actuarial (gain) loss.......................... (14) 88
-------- --------
Net amount recognized at end of year........................ $ 111 $ 142
======== ========
ACTUARIAL ASSUMPTIONS
Discount rate............................................... 7.5% 7.5%
Rate of increase in compensation levels..................... 3.5-5.5% 3.5-5.5%
Expected long-term rate of return on assets................. 10.0% 10.0%
The effect of the January 1, 1999 amendment and restatement as described
above was reflected in the December 31, 1998 projected benefit obligation. The
actuarial gains and losses are due to changes in actuarial assumptions.
Prior to 1999, in addition to the noncontributory pension plans, RERC
maintained non-qualified pension plans which allowed participants to retain the
benefits to which they would have been entitled under its noncontributory
pension plans except for the federally mandated limits on these benefits or on
the level of salary on which these benefits may be calculated. Effective January
1, 1999, these non-qualified pension plans were merged into a similar plan of
Reliant Energy. Expense of $1 million associated with these non-qualified
pension plans was recorded each year during 1998 and 1999, respectively. Expense
of $13 million associated with these non-qualified plans was recorded in 2000.
As of December 31, 1999, RERC had recorded a prepaid benefit asset of $1 million
related to these plans. As of December 31, 2000, an accrued benefit liability of
$29 million was recorded related to these plans. During 2000, RERC recognized a
minimum benefit liability related to these non-qualified plans as a component of
accumulated other comprehensive loss of $16 million.
(c) Savings Plan.
Prior to April 1, 1999, RERC had an employee savings plan which covered
substantially all employees other than Reliant Energy Minnegasco employees.
Under the terms of the RERC savings plans, beginning January 1, 1999, employees
could contribute up to 16% of total compensation and RERC matched 75% of the
first 6% of each employee's compensation contributed. During 1998, employees
could contribute up to 12% of total compensation, and contributions up to 6%
were matched by RERC. Prior to April 1, 1999, Reliant Energy Minnegasco
employees were covered by a savings plan, the terms of which were somewhat
similar to the RERC savings plan; except that until January 1, 1999, Reliant
Energy Minnegasco matched 50% of the first 6% of each employee's compensation
contributed. Effective April 1, 1999, the RERC savings plan and the Reliant
Energy Minnegasco savings plan were merged into Reliant Energy's savings plan.
Employees of RERC participate in Reliant Energy's savings plan, which
qualifies as a cash or deferred arrangement under Section 401(k) of the Internal
Revenue Code of 1986, as amended (Code). Under
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Reliant Energy's plan, participating employees may contribute a portion of their
compensation, pre-tax or after-tax, up to a maximum of 16% of compensation. In
1999, the savings plan was amended so that Reliant Energy now matches 75% to
125% of the first 6% of each employee's compensation contributed. These matching
contributions are subject to a vesting schedule and a portion of the matching
contributions are subject to performance goals achieved by Reliant Energy and
its subsidiaries. A substantial portion of Reliant Energy's match is invested in
Reliant Energy common stock. Reliant Energy allocates to RERC the savings plan
benefit expense related to the employees of RERC.
Savings plan benefit expense related to RERC was $11 million, $10 million
and $18 million in 1998, 1999 and 2000, respectively.
(d) Postretirement Benefits.
RERC provides some postretirement benefits through Reliant Energy plans
(primarily medical care and life insurance benefits) for its retired employees,
substantially all of whom may become eligible for these benefits when they
retire. Effective January 1, 1999, Reliant Energy amended its retiree medical
plan to create an account balance for each participant based on credited service
at December 31, 1998. Under the new plan, each participant has an account, for
recordkeeping purposes only, to which a $750 credit is allocated annually.
Employees became eligible for this postretirement benefit after completing five
years of service after age 50. At retirement the account balance is converted
into one of several annuity options, the proceeds of which can be used solely to
offset the cost of purchasing medical benefits under Reliant Energy's medical
plans. The accounts may not be taken as a cash distribution.
Reliant Energy Minnegasco is required to fund postretirement benefit costs
for the amount included in its rates. RERC, excluding Reliant Energy Minnegasco,
will continue funding its postretirement benefits on a pay-as-you-go basis.
The net postretirement benefit cost includes the following components:
YEAR ENDED
DECEMBER 31,
------------------
1998 1999 2000
---- ---- ----
(IN MILLIONS)
Service cost -- benefits earned during the period........... $ 1 $ 2 $ 2
Interest cost on projected benefit obligation............... 6 9 9
Expected return on plan assets.............................. -- (1) (1)
Net amortization............................................ -- 2 1
--- --- ---
Net postretirement benefit cost............................. $ 7 $12 $11
=== === ===
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Following are reconciliations of RERC's beginning and ending balances of
its postretirement benefit plans benefit obligation, plan assets and funded
status for 1999 and 2000.
YEAR ENDED
DECEMBER 31,
---------------
1999 2000
------ ------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year....................... $ 144 $ 116
Service cost................................................ 2 2
Interest cost............................................... 9 9
Benefits paid............................................... (8) (10)
Participant contributions................................... 2 1
Plan amendments............................................. -- 3
Actuarial (gain) loss....................................... (33) 9
------ ------
Benefit obligation, end of year............................. $ 116 $ 130
====== ======
CHANGE IN PLAN ASSETS
Plan assets, beginning of year.............................. $ 6 $ 9
Benefits paid............................................... (8) (10)
Employer contributions...................................... 9 11
Participant contributions................................... 2 1
Actual investment return.................................... -- 1
------ ------
Plan assets, end of year.................................... $ 9 $ 12
====== ======
RECONCILIATION OF FUNDED STATUS
Funded status............................................... $ (107) $ (118)
Unrecognized prior service cost............................. 26 27
Unrecognized actuarial gain................................. (22) (12)
------ ------
Net amount recognized at end of year........................ $ (103) $ (103)
====== ======
ACTUARIAL ASSUMPTIONS
Discount rate............................................... 7.5% 7.5%
Expected long-term rate of return on assets................. 10.0% 10.0%
Health care cost trend rates -- Under 65.................... 5.8% 8.0%
Health care cost trend rates -- 65 and over................. 6.2% 9.0%
The assumed health care rates gradually decline to 5.5% for both medical
categories by 2010. The actuarial gains and losses are due to changes in
actuarial assumptions.
If the health care cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2000 would
increase by approximately 3.15%. The annual effect of the 1% increase on the
total of the service and interest costs would be an increase of approximately
2.58%. If the health care cost trend rate assumptions were decreased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2000 would
decrease by approximately 3.24%. The annual effect of the 1% decrease on the
total of the service and interest costs would be a decrease of 2.66%.
(e) Postemployment Benefits.
Net postemployment benefit costs for former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily health care and life insurance benefits for
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
participants in the long-term disability plan) were not material in 1998 and
were $11 million in 1999 and $1 million in 2000.
(f) Other Non-qualified Plans.
RERC participates in Reliant Energy's deferred compensation plans which
permit eligible participants to elect each year to defer a percentage of up to
100% of that year's salary and that year's annual bonus. In general, employees
who attain the age of 60 during employment and participate in Reliant Energy's
deferred compensation plans may elect to have their deferred compensation
amounts repaid in (a) 15 equal annual installments commencing at the later of
age 65 or termination of employment or (b) a lump-sum distribution following
termination of employment. Interest generally accrues on deferrals at a rate
equal to the average Moody's Long-Term Corporate Bond Index plus 2%, determined
annually until termination when the rate is fixed at the greater of the rate in
effect at age 64 or at age 65. During 1998, 1999 and 2000, RERC recorded
interest expense related to its deferred compensation obligation of $1 million
each year. The discounted deferred compensation obligation recorded by RERC was
$11 million and $10 million as of December 31, 1999 and 2000, respectively.
(g) Other Employee Matters.
As of December 31, 2000, approximately 27% of RERC's employees were subject
to collective bargaining arrangements, of which contracts covering 4% of RERC's
employees will expire prior to December 31, 2001.
(8) INCOME TAXES
The components of income from continuing operations before taxes are as
follows:
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
(IN MILLIONS)
United States............................................... $206 $193 $177
Foreign..................................................... -- -- 15
---- ---- ----
Income from continuing operations before income
taxes........................................... $206 $193 $192
==== ==== ====
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
RERC's current and deferred components of income tax expense are as
follows:
YEAR ENDED
DECEMBER 31,
------------------
1998 1999 2000
---- ---- ----
(IN MILLIONS)
Current
Federal................................................... $ 30 $27 $52
State..................................................... 7 4 9
Foreign................................................... -- -- 3
---- --- ---
Total current..................................... $ 37 $31 $64
---- --- ---
Deferred
Federal................................................... $ 61 $53 $24
State..................................................... 14 5 1
Foreign................................................... -- -- 4
---- --- ---
Total deferred.................................... $ 75 $58 $29
---- --- ---
Income tax expense.......................................... $112 $89 $93
==== === ===
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
------------------------
1998 1999 2000
------ ------ ------
(IN MILLIONS)
Income from continuing operations before income taxes....... $206 $193 $192
Federal statutory rate.................................... 35% 35% 35%
---- ---- ----
Income tax expense at statutory rate........................ 72 68 67
---- ---- ----
Increase (decrease) in tax resulting from:
State income taxes, net of valuation allowances and
federal income tax Benefit(1).......................... 15 5 6
Goodwill amortization..................................... 18 18 18
Other, net................................................ 7 (2) 2
---- ---- ----
Total............................................. 40 21 26
---- ---- ----
Income tax expense.......................................... $112 $ 89 $ 93
==== ==== ====
Effective Rate.............................................. 54.4% 46.1% 48.7%
- ---------------
(1) Calculation of the accrual for state income taxes at the end of each year
requires that RERC estimate the manner in which its income for that year
will be allocated and/or apportioned among the various states in which it
conducts business, which states have widely differing tax rules and rates.
These allocation/apportionment factors change from year to year and the
amount of taxes ultimately payable may differ from that estimated as a part
of the accrual process. For these reasons, the amount of state income tax
expense may vary significantly from year to year, even in the absence of
significant changes to state income tax valuation allowances or changes in
individual state income tax rates.
168
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Following were RERC's tax effects of temporary differences between the
carrying amounts of assets and liabilities in the financial statements and their
respective tax bases:
DECEMBER 31,
-------------
1999 2000
----- -----
(IN MILLIONS)
Deferred tax assets:
Employee benefits......................................... $ 23 $ 45
Allowance for doubtful accounts........................... 5 17
Operating loss carryforwards.............................. 39 63
Alternative minimum tax and other credit carryforwards.... 34 25
Other..................................................... 58 37
Valuation allowance....................................... (19) (48)
---- ----
Total deferred tax assets, net.................... 140 139
---- ----
Deferred tax liabilities:
Depreciation.............................................. 547 574
Deferred gas costs........................................ 33 58
Deferred state income taxes............................... 69 69
Other..................................................... 24 22
---- ----
Total deferred tax liabilities.................... 673 723
---- ----
Accumulated deferred income taxes, net............ $533 $584
==== ====
Tax Attribute Carryforwards. At December 31, 2000, RERC had $7 million and
$495 million of federal and state tax net operating loss carryforwards,
respectively. The loss carryforwards are available to offset future respective
federal and state taxable income through the year 2020.
At December 31, 2000, RERC had $9 million of federal alternative minimum
tax credits which are available to reduce future federal income taxes payable
over an indefinite period and approximately $1 million of state alternative
minimum tax credits that are available to reduce future state income taxes
payable through the year 2002.
The valuation allowance reflects a net increase of $10 million and $29
million in 1999 and 2000, respectively. These net increases resulted from a
reassessment of RERC's future ability to use state tax net operating loss
carryforwards, offset by changes in valuation allowances provided for expiring
state net operating loss carryforwards.
Tax Refund Case. In December 2000, RERC received a refund from the IRS of
$32 million in taxes and interest following an audit of its tax returns and
refund claims for the 1979 through 1993 tax years. Interest of $26 million
related to the period prior to the acquisition of RERC by Reliant Energy was
recorded as a reduction of goodwill. The income statement effect of $4 million
(after-tax) was recorded in RERC's Statement of Consolidated Income in 2000. All
of RERC Corp.'s consolidated federal income tax returns have been audited and
settled.
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(9) COMMITMENTS AND CONTINGENCIES
(a) Lease Commitments.
The following table sets forth information concerning RERC's obligations
under non-cancelable long-term operating leases principally consisting of rental
agreements for building space, data processing equipment and vehicles, including
major work equipment (in millions):
2001........................................................ $13
2002........................................................ 8
2003........................................................ 7
2004........................................................ 5
2005........................................................ 4
2006 and beyond............................................. 18
---
Total............................................. $55
===
RERC has a master leasing agreement which provides for the lease of
vehicles, construction equipment, office furniture, data processing equipment
and other property. For accounting purposes, the lease is treated as an
operating lease. At December 31, 2000, the unamortized value of equipment
covered by the master leasing agreement was $10 million. RERC does not expect to
lease additional property under this lease agreement.
Total rental expense for all leases was $25 million, $33 million and $19
million in 1998, 1999 and 2000, respectively.
(b) Transportation Agreement.
A predecessor of Reliant Energy Services had an agreement (ANR Agreement)
with ANR Pipeline Company (ANR) which contemplated that RERC would transfer to
ANR an interest in some of RERC's pipeline and related assets. The interest
represented capacity of 250 Mmcf/day. Under the ANR Agreement, an ANR affiliate
advanced $125 million to RERC. Subsequently, the parties restructured the ANR
Agreement and RERC refunded in 1995 and 1993, respectively, $50 million and $34
million to ANR or an affiliate. Reliant Energy Services recorded a liability
reflecting ANR's or its affiliates' use of 130 Mmcf/day of capacity in some of
RERC's transportation facilities. The level of transportation will decline to
100 Mmcf/day in the year 2003 with a refund of $5 million to an ANR affiliate.
The ANR Agreement will terminate in 2005 with a refund of the $36 million. RERC
has agreed to reimburse Reliant Energy Services for any transportation payments
made under the ANR agreement and for the refund of the $41 million. In RERC's
Consolidated Balance Sheets, RERC has recorded a long-term notes payable to
Reliant Energy Services of $28 million and a deferred obligation to ANR of $13
million as of December 31, 2000.
(c) Environmental Matters.
Manufactured Gas Plant Sites. RERC and its predecessors operated a
manufactured gas plant (MGP) adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works (MGW) until 1960. RERC has substantially
completed remediation of the main site other than ongoing water monitoring and
treatment. The manufactured gas was stored in separate holders. RERC is
negotiating cleanup of one such holder. There are six other former MGP sites in
the Minnesota service territory. Remediation has been completed on one site. Of
the remaining five sites, RERC believes that two were neither owned nor operated
by RERC. RERC believes it has no liability with respect to the sites it neither
owned nor operated.
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RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
At December 31, 1999 and 2000, RERC had accrued $19 million and $17
million, respectively, for remediation of the Minnesota sites. At December 31,
2000, the estimated range of possible remediation costs was $8 million to $36
million. The cost estimates of the MGW site are based on studies of that site.
The remediation costs for the other sites are based on industry average costs
for remediation of sites of similar size. The actual remediation costs will be
dependent upon the number of sites remediated, the participation of other
potentially responsible parties, if any, and the remediation methods used.
Other Minnesota Matters. At December 31, 1999 and 2000, RERC had recorded
accruals of $1 million and $2 million, respectively (with a maximum estimated
exposure for these accruals of approximately $13 million and $17 million at
December 31, 1999 and 2000, respectively), for other environmental matters in
Minnesota for which remediation may be required.
Issues relating to the identification and remediation of MGPs are common in
the natural gas distribution industry. RERC has received notices from the United
States Environmental Protection Agency and others regarding its status as a
potentially responsible party (PRP) for other sites. Based on current
information, RERC has not been able to quantify a range of environmental
expenditures for potential remediation expenditures with respect to other MGP
sites.
Mercury Contamination. RERC's pipeline and distribution operations have in
the past employed elemental mercury in measuring and regulating equipment. It is
possible that small amounts of mercury may have been spilled in the course of
normal maintenance and replacement operations and that these spills may have
contaminated the immediate area with elemental mercury. This type of
contamination has been found by RERC at some sites in the past, and RERC has
conducted remediation at sites found to be contaminated. Although RERC is not
aware of additional specific sites, it is possible that other contaminated sites
may exist and that remediation costs may be incurred for these sites. Although
the total amount of these costs cannot be known at this time, based on
experience by RERC and that of others in the natural gas industry to date and on
the current regulations regarding remediation of these sites, RERC believes that
the costs of any remediation of these sites will not be material to RERC's
financial position, results of operations or cash flows.
Potentially Responsible Party Notifications. From time to time RERC has
received notices from regulatory authorities or others regarding its status as a
PRP in connection with sites found to require remediation due to the presence of
environmental contaminants. Considering the information currently known about
such sites and the involvement of RERC in activities at these sites, RERC does
not believe that these matters will have a material adverse effect on RERC's
financial position, results of operations or cash flows.
(d) Other Legal Matters.
California Wholesale Market. Reliant Energy and Reliant Energy Services
have been named as defendants in class action lawsuits and other lawsuits filed
against a number of companies that own generation plants in California and other
sellers of electricity in California markets. RERC Corp. has also been named as
a defendant in one of the lawsuits. Pursuant to the terms of the master
separation agreement between Reliant Energy and Reliant Resources (see Note 1),
Reliant Resources will agree to indemnify Reliant Energy and RERC Corp. for any
damages arising under this lawsuit and may elect to defend this lawsuit at
Reliant Resources' own expense. This lawsuit was filed in Superior Court in San
Francisco County in January 2001. While plaintiffs alleged various violations by
the defendants of the state antitrust laws and state laws against unfair and
unlawful business practices, this lawsuit is grounded on the central allegation
that defendants conspired to drive up the wholesale price of electricity. In
addition to injunctive relief, the plaintiffs in this lawsuit seek restitution
of alleged overpayments, disgorgement of alleged unlawful profits for sales of
electricity during all or portions of 2000, costs of suit and attorneys' fees.
Defendants have filed petitions to remove this case to federal court.
Furthermore, defendants have filed a motion with the Panel on Multidistrict
Litigation seeking transfer and consolidation of all the cases. This lawsuit has
only recently been filed.
171
177
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Therefore, the ultimate outcome of this lawsuit cannot be predicted with any
degree of certainty at this time. However, RERC Corp. does not believe, based on
its analysis to date of the claims asserted in this lawsuit, the indemnification
agreement with Reliant Resources and the underlying facts, that resolution of
this lawsuit will have a material adverse effect on RERC's financial condition,
results of operations or cash flows.
RERC is a party to litigation (other than that specifically noted) which
arises in the normal course of business. Management regularly analyzes current
information and, as necessary, provides accruals for probable liabilities on the
eventual disposition of these matters. Management believes that the effects, if
any, from the disposition of these matters will not have a material adverse
effect on RERC's financial position, results of operations or cash flows.
(10) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
YEAR ENDED DECEMBER 31,
-------------------------------------
1999 2000
----------------- -----------------
CARRYING FAIR CARRYING FAIR
AMOUNT VALUE AMOUNT VALUE
-------- ------ -------- ------
(IN MILLIONS)
Financial assets of RERC:
Energy derivatives -- non-trading....................... $ -- $ 3 $ -- $ 93
Financial liabilities of RERC:
Long-term debt.......................................... 1,444 1,426 1,539 1,543
Trust preferred securities.............................. 1 1 1 1
Energy derivatives -- non-trading....................... -- 1 -- 34
The fair values of cash and cash equivalents, marketable equity securities
and short-term borrowings are estimated to be equivalent to carrying amounts.
The fair value of financial instruments included in the trading operations are
marked-to-market at December 31, 1999 (see Note 4). Therefore, they are stated
at fair value and are excluded from the table above as of December 31, 1999. The
remaining fair values have been determined using quoted market prices of the
same or similar securities when available or other estimation techniques.
(11) UNAUDITED QUARTERLY INFORMATION
Summarized quarterly financial data is as follows:
YEAR ENDED DECEMBER 31, 1999
-------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(IN MILLIONS)
Operating revenues......................................... $1,828 $2,431 $3,447 $2,837
Operating income........................................... 150 45 28 78
Income (loss) from continuing operations................... 71 6 (7) 34
Loss from discontinued operations, net of tax.............. -- -- -- (4)
Net income (loss).......................................... 71 6 (7) 30
172
178
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31, 2000
-------------------------------------
FIRST SECOND THIRD FOURTH
QUARTER QUARTER QUARTER QUARTER
------- ------- ------- -------
(IN MILLIONS)
Operating revenues......................................... $3,099 $4,005 $7,265 $8,290
Operating income........................................... 155 16 9 152
Income (loss) from continuing operations................... 59 (9) (19) 67
Loss from discontinued operations, net of tax.............. (4) (4) (8) (8)
Net income (loss).......................................... 55 (13) (27) 59
(12) REPORTABLE SEGMENTS
Because RERC Corp. is a wholly owned subsidiary of Reliant Energy, RERC's
determination of reportable segments considers the strategic operating units
under which Reliant Energy manages sales, allocates resources and assesses
performance of various products and services to wholesale or retail customers in
differing regulatory environments. Segment financial data includes information
for Reliant Energy and RERC on a combined basis, except for Electric Operations,
which has no RERC operations. Reconciling items included under the caption
"Elimination of Non-RERC Operations" reduce the consolidated Reliant Energy
amounts by those operations not conducted within the RERC legal entity.
Operations not owned or operated by RERC but included in segment information
before elimination include primarily the operations and assets of Reliant
Energy's non-rate regulated power generation business, Reliant Energy's Dutch
power generation operation (N.V. UNA), Reliant Energy's investment in AOL Time
Warner securities and non-RERC corporate expenses.
The accounting policies of the segments are the same as those described in
the summary of significant accounting policies except that some executive
benefit costs have not been allocated to segments. Reliant Energy evaluates
performance based on operating income, excluding some corporate costs not
allocated to the segments. Reliant Energy and RERC account for intersegment
sales as if the sales were to third parties, that is, at current market prices.
Reliant Energy's financial reporting segments include the following:
Electric Operations, Natural Gas Distribution, Pipelines and Gathering,
Wholesale Energy, European Energy and Other Operations. Natural Gas Distribution
consists of intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers, and some non-rate regulated
retail gas marketing operations. Pipelines and Gathering includes the interstate
natural gas pipeline operations and natural gas gathering and pipeline services.
Wholesale Energy is engaged in the acquisition, development and operation of
non-rate regulated power generation facilities as well as the wholesale energy
trading, marketing, power origination and risk management services in North
America. European Energy is engaged in the operation of power generation
facilities in the Netherlands, as well as the wholesale energy trading and
marketing in Europe. Other Operations includes unallocated general corporate
expenses, unregulated retail electric operations, a communications business, an
eBusiness group and non-operating investments. During 2000, Reliant Energy
transferred RERC's non-rate regulated retail gas marketing from Other Operations
to Natural Gas Distribution and RERC's natural gas gathering business from
Wholesale Energy to Pipelines and Gathering. Reportable segments from previous
years have been restated to conform to the 2000 presentation. All of RERC's
long-lived assets are in the United States.
173
179
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
Financial data for business segments and products and services are as
follows:
ELIMINATION
OF NON-
NATURAL GAS PIPELINES AND WHOLESALE OTHER RECONCILING RERC
DISTRIBUTION GATHERING ENERGY OPERATIONS ELIMINATIONS OPERATIONS CONSOLIDATED
------------ ------------- --------- ---------- ------------ ----------- ------------
(IN MILLIONS)
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 1998:
Revenues from external
customers................... $2,363 $ 168 $4,248 $ 101 $ -- $ (122) $ 6,758
Intersegment revenues......... 63 178 168 1 (410) -- --
Depreciation and
amortization................ 131 48 14 10 -- (11) 192
Operating income (loss)....... 167 146 42 (77) -- 32 310
Total assets.................. 3,061 2,217 1,458 1,523 (358) (1,293) 6,608
Expenditures for additions to
long-lived assets........... 162 76 347 28 -- (359) 254
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 1999:
Revenues from external
customers................... 2,742 163 7,648 34 -- (44) 10,543
Intersegment revenues......... 46 168 264 1 (479) -- --
Depreciation and
amortization................ 137 53 21 6 -- (18) 199
Operating income (loss)....... 158 131 27 (71) -- 56 301
Total assets.................. 3,700 2,486 2,821 4,308 (1,125) (4,669) 7,521
Expenditures for additions to
long-lived assets........... 206 79 481 89 -- (567) 288
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2000:
Revenues from external
customers................... 4,379 177 18,655 55 -- (607) 22,659
Intersegment revenues......... 33 207 579 -- (819) -- --
Depreciation and
amortization................ 145 56 109 14 -- (110) 214
Operating income (loss)....... 113 137 482 (172) -- (228) 332
Total assets.................. 4,462 2,357 11,312 1,648 (1,061) (12,142) 6,576
Expenditures for additions to
long-lived assets........... 195 61 1,966 91 -- (2,022) 291
174
180
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
YEAR ENDED DECEMBER 31,
--------------------------
1998 1999 2000
------ ------- -------
(IN MILLIONS)
RECONCILIATION OF OPERATING INCOME TO NET INCOME:
Operating income............................................ $ 310 $ 301 $ 332
Interest expense............................................ (111) (119) (143)
Distribution on trust preferred securities.................. (1) -- --
Other income................................................ 8 11 2
Income taxes................................................ (112) (89) (93)
Loss from discontinued operations........................... -- (4) (24)
------ ------- -------
Net income........................................ $ 94 $ 100 $ 74
====== ======= =======
REVENUES BY PRODUCTS AND SERVICES:
Retail gas sales............................................ $2,372 $ 2,669 $ 4,291
Wholesale energy and energy related sales................... 4,248 7,808 19,290
Gas transport............................................... 168 158 122
Energy products and services................................ 92 105 142
Elimination of non-RERC operations.......................... (122) (197) (1,186)
------ ------- -------
Total............................................. $6,758 $10,543 $22,659
====== ======= =======
REVENUES BY GEOGRAPHIC AREAS
U.S......................................................... $6,758 $10,427 $21,609
Canada...................................................... -- 116 1,050
------ ------- -------
Total............................................. $6,758 $10,543 $22,659
====== ======= =======
(13) DISCONTINUED OPERATIONS
As discussed in Note 1, on December 31, 2000, RERC transferred all of the
outstanding stock of RE Europe Trading to Reliant Resources. As a result of the
transfer, RERC is reporting the results of RE Europe Trading as discontinued
operations for all periods presented in RERC's Consolidated Financial Statements
in accordance with Accounting Principles Board Opinion No. 30 (APB No. 30).
Below is a table of the operating results of RE Europe Trading for the years
ended December 31, 1999 and 2000. There were no operations of RE Europe Trading
in 1998.
YEAR ENDED
DECEMBER 31,
-------------
1999 2000
----- -----
(IN MILLIONS)
Revenues.................................................... $-- $ 37
Operating expenses.......................................... 4 61
Operating loss.............................................. (4) (24)
Net loss.................................................... (4) (24)
In addition to RE Europe Trading, RERC transferred its interests in RESI,
Arkla Finance and Reliant Energy Services to Reliant Resources as described in
Note 1. The transfer of these operations did not result in the disposal of a
segment of business as defined under APB No. 30. Revenues for these operations
were $4 billion, $8 billion, and $19 billion for 1998, 1999 and 2000,
respectively. These operations had a net loss of $4 million in 1998. These
operations had net income of $21 million and $6 million in 1999 and 2000,
respectively.
175
181
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)
(14) SUBSEQUENT EVENT
In February 2001, RERC Corp. issued $550 million of unsecured
unsubordinated notes that bear interest at 7.75% per year and mature in February
2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net
proceeds from the sale of the notes to pay a $400 million dividend to Reliant
Energy and for general corporate purposes.
176
182
INDEPENDENT AUDITORS' REPORT
Reliant Energy Resources Corp.:
We have audited the accompanying consolidated balance sheets of Reliant
Energy Resources Corp. and its subsidiaries (RERC) as of December 31, 1999 and
2000, and the related statements of consolidated income, consolidated
stockholder's equity and comprehensive income and consolidated cash flows for
each of the three years in the period ended December 31, 2000. Our audits also
included the RERC's financial statement schedule listed in Item 14(a)(2). These
financial statements and the financial statement schedule are the responsibility
of RERC's management. Our responsibility is to express an opinion on these
financial statements and the financial statement schedule based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of Reliant Energy Resources Corp.
and its subsidiaries at December 31, 1999 and 2000, and the results of their
operations and their cash flows for each of the three years in the period ended
December 31, 2000 in conformity with accounting principles generally accepted in
the United States of America. Also, in our opinion, such financial statement
schedule, when considered in relation to the basic consolidated financial
statements taken as a whole, presents fairly in all material respects the
information set forth therein.
DELOITTE & TOUCHE LLP
Houston, Texas
March 16, 2001
177
183
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF RELIANT ENERGY AND RERC CORP.
(a) Reliant Energy.
The information called for by Item 10, to the extent not set forth in
"Executive Officers of Reliant Energy" in Item 1, is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2001 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 10 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
(b) RERC Corp.
The information called for by Item 10 with respect to RERC Corp. is omitted
pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain
Wholly Owned Subsidiaries).
ITEM 11. EXECUTIVE COMPENSATION.
(a) Reliant Energy.
The information called for by Item 11 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2001 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 11 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
(b) RERC Corp.
The information called for by Item 11 with respect to RERC Corp. is omitted
pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain
Wholly Owned Subsidiaries).
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
(a) Reliant Energy.
The information called for by Item 12 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2001 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 12 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
(b) RERC Corp.
The information called for by Item 12 with respect to RERC Corp. is omitted
pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain
Wholly Owned Subsidiaries).
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
(a) Reliant Energy.
The information called for by Item 13 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2001 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 13 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.
178
184
(b) RERC Corp.
The information called for by Item 13 with respect to RERC Corp. is omitted
pursuant to Instruction I(2)(a) to Form 10-K (Omission of Information by Certain
Wholly Owned Subsidiaries).
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) Reliant Energy Financial Statements.
Statements of Consolidated Income for the Three Years Ended
December 31, 2000........................................... 75
Statements of Consolidated Comprehensive Income for the
Three Years Ended
December 31, 2000........................................... 76
Consolidated Balance Sheets at December 31, 2000 and 1999... 77
Statements of Consolidated Cash Flows for the Three Years
Ended
December 31, 2000........................................... 78
Statements of Consolidated Stockholders' Equity for the
Three Years Ended
December 31, 2000........................................... 79
Notes to Consolidated Financial Statements.................. 80
Independent Auditors' Report -- Company..................... 140
RERC Corp. Financial Statements.
Statements of Consolidated Income for the Years Ended
December 31, 2000........................................... 146
Statements of Consolidated Stockholder's Equity and
Comprehensive Income for the
Years Ended December 31, 2000............................... 147
Consolidated Balance Sheets at December 31, 2000 and 1999... 148
Statements of Consolidated Cash Flows for the Years Ended
December 31, 2000........................................... 149
Notes to Consolidated Financial Statements.................. 150
Independent Auditors' Report -- RERC Corp. ................. 177
Reliant Energy Financial Statement Schedules for the Three
(a)(2) Years Ended December 31, 2000.
Reliant Energy: II -- Reserves.............................. 181
RERC Corp. Financial Statement Schedules for the Three Years
Ended December 31, 2000.
RERC Corp.: II -- Reserves.................................. 182
The following schedules are omitted for each of Reliant Energy and RERC
Corp. because of the absence of the conditions under which they are
required or because the required information is included in the financial
statements:
I, III, IV and V.
(a)(3) Exhibits
See Index of Exhibits for Reliant Energy (page 186) and RERC Corp.
(page 193), which indexes also include the management contracts or
compensatory plans or arrangements required to be filed as exhibits
to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
(b) Reports on Form 8-K.
Reliant Energy:
- On October 25, 2000, a report on Form 8-K was filed reporting on Reliant
Energy's third quarter earnings.
- On January 26, 2000, a report on Form 8-K was filed reporting on Reliant
Energy's fourth quarter earnings.
179
185
RERC Corp.:
- On October 25, 2000, a report on Form 8-K was filed reporting on RERC
Corp.'s third quarter earnings.
- On January 14, 2001, a report on Form 8-K dated December 31, 2000 was
filed reporting the transfer of certain assets from RERC Corp. to another
subsidiary of Reliant Energy.
- On January 26, 2001, a report on Form 8-K was filed reporting on RERC
Corp.'s fourth quarter earnings.
- On February 21, 2001, a report on Form 8-K dated February 15, 2001 was
filed in order to file a supplemental indenture and related documents.
180
186
RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES
SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2000
(THOUSANDS OF DOLLARS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- ---------- --------------------- ---------- ----------
ADDITIONS
---------------------
BALANCE AT CHARGED CHARGED DEDUCTIONS BALANCE AT
BEGINNING TO TO OTHER FROM END OF
DESCRIPTION OF PERIOD INCOME ACCOUNTS(1) RESERVES PERIOD
- ----------- ---------- ------- ----------- ---------- ----------
Year Ended December 31, 2000:
Accumulated provisions:
Uncollectible accounts receivable... $33,519 $95,376 $ (597) $23,409 $104,889
Reserves deducted from price risk
management assets................. 11,511 54,621 -- -- 66,132
Reserves for accrue-in-advance major
maintenance....................... 47,809 41,306 (787) 61,253 27,075
Reserves for inventory.............. 5,806 372 17,053 16,004 7,227
Deferred tax asset valuation........ 19,139 48,798 -- -- 67,937
Year Ended December 31, 1999:
Accumulated provisions:
Uncollectible accounts receivable... 26,106 16,296 7,490 16,373 33,519
Reserves deducted from price risk
management assets................. 6,464 5,047 -- -- 11,511
Reserves for accrue-in-advance major
maintenance....................... 35,249 5,826 17,411 10,677 47,809
Reserves for inventory.............. 6,574 72 -- 840 5,806
Deferred tax asset valuation........ 8,591 10,548 -- -- 19,139
Year Ended December 31, 1998:
Accumulated provisions:
Uncollectible accounts receivable... 16,166 20,871 -- 10,931 26,106
Reserves deducted from price risk
management assets................. -- 6,464 -- -- 6,464
Reserves for accrue-in-advance major
maintenance....................... -- 4,181 31,068 -- 35,249
Reserves for inventory.............. 106 79 7,026 637 6,574
Deferred tax asset valuation........ 6,353 2,238 -- -- 8,591
- ---------------
(1) Charged to Other Accounts primarily relates to obligations acquired in
business acquisitions.
181
187
RELIANT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(A WHOLLY OWNED SUBSIDIARY OF RELIANT ENERGY, INCORPORATED)
SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2000
(THOUSANDS OF DOLLARS)
COLUMN A COLUMN B COLUMN C COLUMN D COLUMN E
-------- ---------- --------------------- ---------- ----------
ADDITIONS
---------------------
BALANCE AT CHARGED CHARGED DEDUCTIONS BALANCE AT
BEGINNING TO TO OTHER FROM END OF
DESCRIPTION OF PERIOD INCOME ACCOUNTS(1) RESERVES PERIOD
- ----------- ---------- ------- ----------- ---------- ----------
Year Ended December 31, 2000:
Accumulated provisions:
Uncollectible accounts
receivable....................... $25,287 $32,119 $ (7,803) $17,079 $32,524
Reserves deducted from price risk
management assets................ 11,511 54,621 (66,132) -- --
Reserves for inventory............. 90 372 -- 63 399
Deferred tax asset valuation....... 19,139 28,538 -- -- 47,677
Year Ended December 31, 1999:
Accumulated provisions:
Uncollectible accounts
receivable....................... 21,566 16,296 -- 12,575 25,287
Reserves deducted from price risk
management assets................ 6,464 5,047 -- -- 11,511
Reserves for inventory............. 69 72 -- 51 90
Deferred tax asset valuation....... 8,591 10,548 -- -- 19,139
Year Ended December 31, 1998:
Accumulated provisions:
Uncollectible accounts
receivable....................... 16,783 15,714 -- 10,931 21,566
Reserves deducted from price risk
management assets................ -- 6,464 -- -- 6,464
Reserves for inventory............. 106 79 -- 116 69
Deferred tax asset valuation....... 6,353 2,238 -- -- 8,591
- ---------------
(1) Charged to Other Accounts in 2000 relates to reserves that were transferred
to Reliant Resources, Inc.
182
188
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the fifteenth day of March, 2001.
RELIANT ENERGY, INCORPORATED
(Registrant)
By: /s/ R. STEVE LETBETTER
----------------------------------
R. Steve Letbetter,
Chairman, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 15, 2001.
SIGNATURE TITLE
--------- -----
/s/ R. STEVE LETBETTER Chairman, President, Chief Executive Officer
- ----------------------------------------------------- and Director (Principal Executive Officer
(R. Steve Letbetter) and Director)
/s/ STEPHEN W. NAEVE Vice Chairman and Chief Financial Officer
- ----------------------------------------------------- (Principal Financial Officer)
(Stephen W. Naeve)
/s/ MARY P. RICCIARDELLO Senior Vice President and Chief Accounting
- ----------------------------------------------------- Officer (Principal Accounting Officer)
(Mary P. Ricciardello)
/s/ JAMES A. BAKER, III Director
- -----------------------------------------------------
(James A. Baker, III)
/s/ RICHARD E. BALZHISER Director
- -----------------------------------------------------
(Richard E. Balzhiser)
/s/ MILTON CARROLL Director
- -----------------------------------------------------
(Milton Carroll)
/s/ JOHN T. CATER Director
- -----------------------------------------------------
(John T. Cater)
/s/ O. HOLCOMBE CROSSWELL Director
- -----------------------------------------------------
(O. Holcombe Crosswell)
/s/ ROBERT J. CRUIKSHANK Director
- -----------------------------------------------------
(Robert J. Cruikshank)
183
189
SIGNATURE TITLE
--------- -----
/s/ LINNET F. DEILY Director
- -----------------------------------------------------
(Linnet F. Deily)
/s/ T. MILTON HONEA Director
- -----------------------------------------------------
(T. Milton Honea)
/s/ LAREE E. PEREZ Director
- -----------------------------------------------------
(Laree E. Perez)
184
190
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the fifteenth day of March, 2001.
RELIANT ENERGY RESOURCES CORP.
(Registrant)
By: /s/ R. STEVE LETBETTER
----------------------------------
R. Steve Letbetter,
Chairman, President and Chief
Executive Officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 15, 2001.
SIGNATURE TITLE
--------- -----
/s/ R. STEVE LETBETTER Chairman, President and Chief Executive
- --------------------------------------------- Officer (Principal Executive Officer and
(R. Steve Letbetter) Principal Financial Officer)
/s/ MARY P. RICCIARDELLO Senior Vice President (Principal Accounting
- --------------------------------------------- Officer)
(Mary P. Ricciardello)
/s/ STEPHEN W. NAEVE Sole Director
- ---------------------------------------------
(Stephen W. Naeve)
185
191
RELIANT ENERGY, INCORPORATED
RELIANT ENERGY RESOURCES CORP.
EXHIBITS TO THE COMBINED ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2000
INDEX OF EXHIBITS
Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated. Exhibits designated by an asterisk (*) are
management contracts or compensatory plans or arrangements required to be filed
as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.
(A) RELIANT ENERGY, INCORPORATED
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
2(a)(1) -- Agreement and Plan of Merger among former HI's Form 8-K dated August 11, 1-7629 2
Houston Industries Incorporated ("HI"), 1996
Houston Lighting & Power ("HL&P" or
"Reliant Energy"), HI Merger, Inc. and
NorAm dated August 11, 1996
2(a)(2) -- Amendment to Agreement and Plan of Merger Registration Statement on Form 333-11329 2(c)
among HI, HL&P, HI Merger, Inc. and NorAm S-4
dated August 11, 1996
2(b)(1) -- Share Subscription Agreement dated March Form 10-Q for the quarter ended 1-3187 10.2
29, 1999 among Reliant Energy Wholesale March 31, 1999
Holdings (Europe) Inc., Provincie Noord
Holland, Gemeente Amsterdam, N.V.
Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy
Power Generation, Inc. and UNA
2(b)(2) -- Share Purchase Agreement dated March 29, Form 10-Q for the quarter ended 1-3187 10.3
1999 among Reliant Energy Wholesale Holdings March 31, 1999
(Europe) Inc., Provincie Noord Holland,
Gemeente Amsterdam, N.V. Provinciaal En
Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy
Power Generation, Inc. and UNA
2(b)(3) -- Deed of Amendment dated September 2, 1999 Form 10-K for the year ended 1-3187 2(b)(3)
among Reliant Energy Wholesale Holdings December 31, 1999
(Europe) Inc., Provincie Noord Holland,
Gemeente Amsterdam, N.V. Provinciaal En
Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy
Power Generation, Inc. and UNA
2(c) -- Purchase Agreement dated as of February 19, Form 10-K for the year ended 1-3187 2(c)
2000 among Reliant Energy Power Generation, December 31, 1999
Inc., Reliant Energy, Sithe Energies, Inc.
and Sithe Northeast Generating Company,
Inc.
3(a) -- Restated Articles of Incorporation of Form 10-K for the year ended 1-3187 3(a)
Reliant Energy, restated as of September December 31, 1997
1997
3(b) -- Amendment to Restated Articles of Form 10-Q for the quarter ended 1-3187 3(b)
Incorporation of Reliant Energy, as of May March 31, 1999
5, 1999
3(c) -- Amended and Restated Bylaws of Reliant Form 10-Q for the quarter ended 1-3187 3
Energy adopted May 3, 2000 March 31, 2000
3(d) -- Statement of Resolution Establishing Series Form 10-Q for the quarter ended 1-3187 3(c)
of Shares designated Series C Preference March 31, 1998
Stock
3(e) -- Statement of Resolution Establishing Series Form 10-K for the year ended 1-3187 3(e)
of Shares designated Series D Preference December 31, 1999
Stock
186
192
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
3(f) -- Statement of Resolution Establishing Series Form 10-K for the year ended 1-3187 3(f)
of Shares designated Series E Preference December 31, 1999
Stock
3(g) -- Statement of Resolution Establishing Series Form 10-K for the year ended 1-3187 3(g)
of Shares designated Series F Preference December 31, 1999
Stock
3(h) -- Articles/Certificate of Correction relating Form 10-K for the year ended 1-3187 3(h)
to the Statement of Resolution Establishing December 31, 1999
Series of Shares designated Series F
Preference Stock
3(i) -- Statement of Resolution Establishing Series Form 10-K for the year ended 1-3187 3(i)
of Shares designated Series G Preference December 31, 1999
Stock
3(j) -- Statement of Resolution Establishing Series Form 10-Q for quarter ended June 1-3187 3(a)
of Shares designated Series H Preference 30, 2000
Stock
3(k) -- Statement of Resolution Establishing Series Form 10-Q for quarter ended June 1-3187 3(b)
of Shares designated Series I Preference 30, 2000
Stock
3(l) -- Statement of Resolution Establishing Series Form 10-Q for quarter ended June 1-3187 3(c)
of Shares designated Series J Preference 30, 2000
Stock
3(m) -- Statement of Resolution Establishing Series Form 10-Q for quarter ended 1-3187 3
of Shares designated Series K Preference September 30, 2000
Stock
+3(n) -- Statement of Resolution Establishing Series
of Shares designated Series L Preference
Stock
+3(o) -- Statement of Resolution Establishing Series
of Shares designated Series M Preference
Stock
+3(p) -- Statement of Resolution Establishing Series
of Shares designated Series N Preference
Stock
+3(q) -- Statement of Resolution Establishing Series
of Shares designated Series O Preference
Stock
+3(r) -- Statement of Resolution Establishing Series
of Shares designated Series P Preference
Stock
+3(s) -- Statement of Resolution Establishing Series
of Shares designated Series Q Preference
Stock
+3(t) -- Statement of Resolution Establishing Series
of Shares designated Series R Preference
Stock
+3(u) -- Statement of Resolution Establishing Series
of Shares designated Series S Preference
Stock
+3(v) -- Statement of Resolution Establishing Series
of Shares designated Series T Preference
Stock
+3(w) -- Statement of Resolution Establishing Series
of Shares designated Series U Preference
Stock
+3(x) -- Statement of Resolution Establishing Series
of Shares designated Series V Preference
Stock
4(a)(1) -- Mortgage and Deed of Trust, dated November Form S-7 of HL&P filed on August 2-59748 2(b)
1, 1944 between HL&P and Chase Bank of 25, 1977
Texas, National Association (formerly,
South Texas Commercial National Bank of
Houston), as Trustee, as amended and
supplemented by 20 Supplemental Indentures
thereto
4(a)(2) -- Twenty-First through Fiftieth Supplemental HL&P's Form 10-K for the year 1-3187 4(a)(2)
Indentures to Exhibit 4(a)(1) ended December 31, 1989
4(a)(3) -- Fifty-First Supplemental Indenture to HL&P's Form 10-Q for the quarter 1-3187 4(a)
Exhibit 4(a)(1) dated as of March 25, 1991 ended June 30, 1991
4(a)(4) -- Fifty-Second through Fifty-Fifth HL&P's Form 10-Q for the quarter 1-3187 4
Supplemental Indentures to Exhibit 4(a)(1) ended March 31, 1992
each dated as of March 1, 1992
187
193
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
4(a)(5) -- Fifty-Sixth and Fifty-Seventh Supplemental HL&P's Form 10-Q for the quarter 1-3187 4
Indentures to Exhibit 4(a)(1) each dated as ended September 30, 1992
of October 1, 1992
4(a)(6) -- Fifty-Eighth and Fifty-Ninth Supplemental HL&P's Form 10-Q for the quarter 1-3187 4
Indentures to Exhibit 4(a)(1) each dated as ended March 31, 1993
of March 1, 1993
4(a)(7) -- Sixtieth Supplemental Indenture to Exhibit HL&P's Form 10-Q for the quarter 1-3187 4
4(a)(1) dated as of July 1, 1993 ended June 30, 1993
4(a)(8) -- Sixty-First through Sixty-Third HL&P's Form 10-K for the year 1-3187 4(a)(8)
Supplemental Indentures to Exhibit 4(a)(1) ended December 31, 1993
each dated as of December 1, 1993
4(a)(9) -- Sixty-Fourth and Sixty-Fifth Supplemental HL&P's Form 10-K for the year 1-3187 4(a)(9)
Indentures to Exhibit 4(a)(1) each dated as ended December 31, 1995
of July 1, 1995
4(b)(1) -- Rights Agreement, dated July 11, 1990, HI's Form 8-K dated July 11, 1990 1-7629 4(a)(1)
between the Company and Texas Commerce Bank,
National Association, as Rights Agent
(Rights Agent), which includes form of
Statement of Resolution Establishing Series
of Shares designated Series A Preference
Stock and form of Rights Certificate
4(b)(2) -- Agreement and Appointment of Agent, dated HI's Form 8-K dated July 11, 1990 1-7629 4(a)(2)
as of July 11, 1990, between the Company and
the Rights Agent
4(b)(3) -- Form of Amended and Restated Rights Registration Statement on Form 333-11329 4(b)(1)
Agreement executed on August 6, 1997, S-4
including form of Statement of Resolution
Establishing Series of Shares Designated
Series A Preference Stock and form of
Rights Agreement
4(b)(4) -- Amendment No. 1 to Rights Agreement, dated Form 10-Q for the quarter ended 1-3187 4
as of May 8, 2000, between Reliant Energy March 31, 2000
and Chase Bank of Texas, National
Association as Rights Agent
4(c) -- Indenture, dated as of April 1, 1991, HI's Form 10-Q for the quarter 1-7629 4(b)
between the Company and NationsBank of ended June 30, 1991
Texas, National Association, as Trustee
Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, Reliant Energy has
not filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of securities authorized do
not exceed 10% of the total assets of Reliant Energy and its subsidiaries on a
consolidated basis. Reliant Energy hereby agrees to furnish a copy of any such
instrument to the SEC upon request.
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
*10(a)(1) -- Executive Benefit Plan of the Company and HI's Form 10-Q for the quarter 1-7629 10(a)(1),
First and Second Amendments thereto ended March 31, 1987 10(a)(2),
effective as of June 1, 1982, July 1, and
1984, and May 7, 1986, respectively 10(a)(3)
+*10(a)(2) -- Third Amendment dated September 17, 1999
to the Executive Benefit Plan of the
Company
*10(b)(1) -- Executive Incentive Compensation Plan of HI's Form 10-K for the year ended 1-7629 10(b)
the Company effective as of January 1, December 31, 1991
1982
188
194
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
*10(b)(2) -- First Amendment to Exhibit 10(b)(1) HI's Form 10-Q for the quarter 1-7629 10(a)
effective as of March 30, 1992 ended March 31, 1992
*10(b)(3) -- Second Amendment to Exhibit 10(b)(1) HI's Form 10-K for the year ended 1-7629 10(b)
effective as of November 4, 1992 December 31, 1992
*10(b)(4) -- Third Amendment to Exhibit 10(b)(1) HI's Form 10-K for the year ended 1-7629 10(b)(4)
effective as of September 7, 1994 December 31, 1994
*10(b)(5) -- Fourth Amendment to Exhibit 10(b)(1) Form 10-K for the year ended 1-3187 10(b)(5)
effective as of August 6, 1997 December 31, 1997
*10(c)(1) -- Executive Incentive Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(b)(1)
the Company effective as of January 1, ended March 31, 1987
1985
*10(c)(2) -- First Amendment to Exhibit 10(c)(1) HI's Form 10-K for the year ended 1-7629 10(b)(3)
effective as of January 1, 1985 December 31, 1988
*10(c)(3) -- Second Amendment to Exhibit 10(c)(1) HI's Form 10-K for the year ended 1-7629 10(c)(3)
effective as of January 1, 1985 December 31, 1991
*10(c)(4) -- Third Amendment to Exhibit 10(c)(1) HI's Form 10-Q for the quarter 1-7629 10(b)
effective as of March 30, 1992 ended March 31, 1992
*10(c)(5) -- Fourth Amendment to Exhibit 10(c)(1) HI's Form 10-K for the year ended 1-7629 10(c)(5)
effective as of November 4, 1992 December 31, 1992
*10(c)(6) -- Fifth Amendment to Exhibit 10(c)(1) HI's Form 10-K for the year ended 1-7629 10(c)(6)
effective as of September 7, 1994 December 31, 1994
*10(c)(7) -- Sixth Amendment to Exhibit 10(c)(1) Form 10-K for the year ended 1-3187 10(c)(7)
effective as of August 6, 1997 December 31, 1997
*10(d) -- Executive Incentive Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(b)(2)
Houston Lighting & Power Company ended March 31, 1987
effective as of January 1, 1985
*10(e)(1) -- Executive Incentive Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(b)
the Company effective as of January 1, ended June 30, 1989
1989
*10(e)(2) -- First Amendment to Exhibit 10(e)(1) HI's Form 10-K for the year ended 1-7629 10(e)(2)
effective as of January 1, 1989 December 31, 1991
*10(e)(3) -- Second Amendment to Exhibit 10(e)(1) HI's Form 10-Q for the quarter 1-7629 10(c)
effective as of March 30, 1992 ended March 31, 1992
*10(e)(4) -- Third Amendment to Exhibit 10(e)(1) HI's Form 10-K for the year ended 1-7629 10(c)(4)
effective as of November 4, 1992 December 31, 1992
*10(e)(5) -- Fourth Amendment to Exhibit 10(e)(1) HI's Form 10-K for the year ended 1-7629 10(e)(5)
effective as of September 7, 1994 December 31, 1994
*10(f)(1) -- Executive Incentive Compensation Plan of HI's Form 10-K for the year ended 1-7629 10(b)
the Company effective as of January 1, December 31, 1990
1991
*10(f)(2) -- First Amendment to Exhibit 10(f)(1) HI's Form 10-K for the year ended 1-7629 10(f)(2)
effective as of January 1, 1991 December 31, 1991
*10(f)(3) -- Second Amendment to Exhibit 10(f)(1) HI's Form 10-Q for the quarter 1-7629 10(d)
effective as of March 30, 1992 ended March 31, 1992
*10(f)(4) -- Third Amendment to Exhibit 10(f)(1) HI's Form 10-K for the year ended 1-7629 10(f)(4)
effective as of November 4, 1992 December 31, 1992
*10(f)(5) -- Fourth Amendment to Exhibit 10(f)(1) HI's Form 10-K for the year ended 1-7629 10(f)(5)
effective as of January 1, 1993 December 31, 1992
*10(f)(6) -- Fifth Amendment to Exhibit 10(f)(1) HI's Form 10-K for the year ended 1-7629 10(f)(6)
effective in part, January 1, 1995, and in December 31, 1994
part, September 7, 1994
*10(f)(7) -- Sixth Amendment to Exhibit 10(f)(1) HI's Form 10-Q for the quarter 1-7629 10(a)
effective as of August 1, 1995 ended June 30, 1995
*10(f)(8) -- Seventh Amendment to Exhibit 10(f)(1) HI's Form 10-Q for the quarter 1-7629 10(a)
effective as of January 1, 1996 ended June 30, 1996
189
195
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
*10(f)(9) -- Eighth Amendment to Exhibit 10(f)(1) HI's Form 10-Q for the quarter 1-7629 10(a)
effective as of January 1, 1997 ended June 30, 1997
*10(f)(10) -- Ninth Amendment to Exhibit 10(f)(1) Form 10-K for the year ended 1-3187 10(f)(10)
effective in part, January 1, 1997, and December 31, 1997
in part, January 1, 1998
*10(g) -- Benefit Restoration Plan of the Company, HI's Form 10-Q for the quarter 1-7629 10(c)
effective as of June 1, 1985 ended March 31, 1987
*10(h) -- Benefit Restoration Plan of the Company HI's Form 10-K for the year ended 1-7629 10(g)(2)
as amended and restated effective as of December 31, 1991
January 1, 1988
*10(i)(1) -- Benefit Restoration Plan of the Company, HI's Form 10-K for the year ended 1-7629 10(g)(3)
as amended and restated effective as of December 31, 1991
July 1, 1991
*10(i)(2) -- First Amendment to Exhibit 10(i)(1) Form 10-K for the year ended 1-3187 10(i)(2)
effective in part, August 6, 1997, in December 31, 1997
part, September 3, 1997, and in part,
October 1, 1997
*10(j)(1) -- Deferred Compensation Plan of the Company HI's Form 10-Q for the quarter 1-7629 10(d)
effective as of September 1, 1985 ended March 31, 1987
*10(j)(2) -- First Amendment to Exhibit 10(j)(1) HI's Form 10-K for the year ended 1-7629 10(d)(2)
effective as of September 1, 1985 December 31, 1990
*10(j)(3) -- Second Amendment to Exhibit 10(j)(1) HI's Form 10-Q for the quarter 1-7629 10(e)
effective as of March 30, 1992 ended March 31, 1992
*10(j)(4) -- Third Amendment to Exhibit 10(j)(1) HI's Form 10-K for the year ended 1-7629 10(h)(4)
effective as of June 2, 1993 December 31, 1993
*10(j)(5) -- Fourth Amendment to Exhibit 10(j)(1) HI's Form 10-K for the year ended 1-7629 10(h)(5)
effective as of September 7, 1994 December 31, 1994
*10(j)(6) -- Fifth Amendment to Exhibit 10(j)(1) HI's Form 10-Q for the quarter 1-7629 10(d)
effective as of August 1, 1995 ended June 30, 1995
*10(j)(7) -- Sixth Amendment to Exhibit 10(j)(1) HI's Form 10-Q for the quarter 1-7629 10(b)
effective as of December 1, 1995 ended June 30, 1995
*10(j)(8) -- Seventh Amendment to Exhibit 10(j)(1) HI's Form 10-Q for the quarter 1-7629 10(b)
effective as of January 1, 1997 ended June 30, 1997
*10(j)(9) -- Eighth Amendment to Exhibit 10(j)(1) Form 10-K for the year ended 1-3187 10(j)(9)
effective as of September 1, 1997 December 31, 1997
*10(j)(10) -- Ninth Amendment to Exhibit 10(j)(1) Form 10-K for the year ended 1-3187 10(j)(10)
effective as of September 3, 1997 December 31, 1997
*10(k)(1) -- Deferred Compensation Plan of the Company HI's Form 10-Q for the quarter 1-7629 10(a)
effective as of January 1, 1989 ended June 30, 1989
*10(k)(2) -- First Amendment to Exhibit 10(k)(1) HI's Form 10-K for the year ended 1-7629 10(e)(3)
effective as of January 1, 1989 December 31, 1989
*10(k)(3) -- Second Amendment to Exhibit 10(k)(1) HI's Form 10-Q for the quarter 1-7629 10(f)
effective as of March 30, 1992 ended March 31, 1992
*10(k)(4) -- Third Amendment to Exhibit 10(k)(1) HI's Form 10-K for the year ended 1-7629 10(i)(4)
effective as of June 2, 1993 December 31, 1993
*10(k)(5) -- Fourth Amendment to Exhibit 10(k)(1) HI's Form 10-K for the year ended 1-7629 10(i)(5)
effective as of September 7, 1994 December 31, 1994
*10(k)(6) -- Fifth Amendment to Exhibit 10(k)(1) HI's Form 10-Q for the quarter 1-7629 10(c)
effective as of August 1, 1995 ended June 30, 1995
*10(k)(7) -- Sixth Amendment to Exhibit 10(k)(1) HI's Form 10-Q for the quarter 1-7629 10(c)
effective December 1, 1995 ended June 30, 1995
*10(k)(8) -- Seventh Amendment to Exhibit 10(k)(1) HI's Form 10-Q for the quarter 1-7629 10(c)
effective as of January 1, 1997 ended June 30, 1997
190
196
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
*10(k)(9) -- Eighth Amendment to Exhibit 10(k)(1) Form 10-K for the year ended 1-3187 10(k)(9)
effective in part October 1, 1997 and in December 31, 1997
part January 1, 1998
*10(k)(10) -- Ninth Amendment to Exhibit 10(k)(1) Form 10-K for the year ended 1-3187 10(k)(10)
effective as of September 3, 1997 December 31, 1997
*10(l)(1) -- Deferred Compensation Plan of the Company HI's Form 10-K for the year ended 1-7629 10(d)(3)
effective as of January 1, 1991 December 31, 1990
*10(l)(2) -- First Amendment to Exhibit 10(l)(1) HI's Form 10-K for the year ended 1-7629 10(j)(2)
effective as of January 1, 1991 December 31, 1991
*10(l)(3) -- Second Amendment to Exhibit 10(l)(1) HI's Form 10-Q for the quarter 1-7629 10(g)
effective as of March 30, 1992 ended March 31, 1992
*10(l)(4) -- Third Amendment to Exhibit 10(l)(1) HI's Form 10-K for the year ended 1-7629 10(j)(4)
effective as of June 2, 1993 December 31, 1993
*10(l)(5) -- Fourth Amendment to Exhibit 10(l)(1) HI's Form 10-K for the year ended 1-7629 10(j)(5)
effective as of December 1, 1993 December 31, 1993
*10(l)(6) -- Fifth Amendment to Exhibit 10(l)(1) HI's Form 10-K for the year ended 1-7629 10(j)(6)
effective as of September 7, 1994 December 31, 1994
*10(l)(7) -- Sixth Amendment to Exhibit 10(l)(1) HI's Form 10-Q for the quarter 1-7629 10(b)
effective as of August 1, 1995 ended June 30, 1995
*10(l)(8) -- Seventh Amendment to Exhibit 10(l)(1) HI's Form 10-Q for the quarter 1-7629 10(d)
effective as of December 1, 1995 ended June 30, 1996
*10(l)(9) -- Eighth Amendment to Exhibit 10(l)(1) HI's Form 10-Q for the quarter 1-7629 10(d)
effective as of January 1, 1997 ended June 30, 1997
*10(l)(10) -- Ninth Amendment to Exhibit 10(l)(1) Form 10-K for the year ended 1-3187 10(l)(10)
effective in part August 6, 1997, in part December 31, 1997
October 1, 1997, and in part January 1,
1998
*10(l)(11) -- Tenth Amendment to Exhibit 10(l)(1) Form 10-K for the year ended 1-3187 10(i)(11)
effective as of September 3, 1997 December 31, 1997
*10(m)(1) -- Long-Term Incentive Compensation Plan of HI's Form 10-Q for the quarter 1-7629 10(c)
the Company effective as of January 1, ended June 30, 1989
1989
*10(m)(2) -- First Amendment to Exhibit 10(m)(1) HI's Form 10-K for the year ended 1-7629 10(f)(2)
effective as of January 1, 1990 December 31, 1989
*10(m)(3) -- Second Amendment to Exhibit 10(m)(1) HI's Form 10-K for the year ended 1-7629 10(k)(3)
effective as of December 22, 1992 December 31, 1992
*10(m)(4) -- Third Amendment to Exhibit 10(m)(1) HI's Form 10-K for the year ended 1-3187 10(m)(4)
effective as of August 6, 1997 December 31, 1997
*10(n) -- Form of stock option agreement for non- HI's Form 10-Q for the quarter 1-7629 10(h)
qualified stock options granted under the ended March 31, 1992
Company's 1989 Long-Term Incentive
Compensation Plan
*10(o) -- Forms of restricted stock agreement for HI's Form 10-Q for the quarter 1-7629 10(i)
restricted stock granted under the ended March 31, 1992
Company's 1989 Long-Term Incentive
Compensation Plan
*10(p)(1) -- 1994 Long-Term Incentive Compensation HI's Form 10-K for the year ended 1-7629 10(n)(1)
Plan of the Company effective as of December 31, 1993
January 1, 1994
*10(p)(2) -- Form of stock option agreement for non- HI's Form 10-K for the year ended 1-7629 10(n)(2)
qualified stock options granted under the December 31, 1993
Company's 1994 Long-Term Incentive
Compensation Plan
*10(p)(3) -- First Amendment to Exhibit 10(p)(1) HI's Form 10-Q for the quarter 1-7629 10(e)
effective as of May 9, 1997 ended June 30, 1997
*10(p)(4) -- Second Amendment to Exhibit 10(p)(1) Form 10-K for the year ended 1-3187 10(p)(4)
effective as of August 6, 1997 December 31, 1997
191
197
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
*10(p)(5) -- Third Amendment to Exhibit 10(p)(1) Form 10-K for the year ended 1-3187 10(p)(5)
effective as of January 1, 1998 December 31, 1998
*10(q)(1) -- Savings Restoration Plan of the Company HI's Form 10-K for the year ended 1-7629 10(f)
effective as of January 1, 1991 December 31, 1990
*10(q)(2) -- First Amendment to Exhibit 10(q)(1) HI's Form 10-K for the year ended 1-7629 10(l)(2)
effective as of January 1, 1992 December 31, 1991
*10(q)(3) -- Second Amendment to Exhibit 10(q)(1) Form 10-K for the year ended 1-3187 10(q)(3)
effective in part, August 6, 1997, and in December 31, 1997
part, October 1, 1997
*10(r)(1) -- Director Benefits Plan, effective as of HI's Form 10-K for the year ended 1-7629 10(m)
January 1, 1992 December 31, 1991
*10(r)(2) -- First Amendment to Exhibit 10(r)(1) Form 10-K for the year ended 1-7629 10(m)(1)
effective as of August 6, 1997 December 31, 1998
*10(s)(1) -- Executive Life Insurance Plan of the HI's Form 10-K for the year ended 1-7629 10(q)
Company effective as of January 1, 1994 December 31, 1993
*10(s)(2) -- First Amendment to Exhibit 10(s)(1) HI's Form 10-Q for the quarter 1-7629 10
effective as of January 1, 1994 ended June 30, 1995
*10(s)(3) -- Second Amendment to Exhibit 10(s)(1) Form 10-K for the year ended 1-3187 10(s)(3)
effective as of August 6, 1997 December 31, 1997
*10(t) -- Employment and Supplemental Benefits HI's Form 10-Q for the quarter 1-7629 10(f)
Agreement between HL&P and Hugh Rice ended March 31, 1987
Kelly
*10(u)(1) -- Houston Industries Incorporated Savings Company's Form 10-K for the year 1-7629 10(s)(4)
Trust between the Company and The Northern ended December 31, 1995
Trust Company, as Trustee (as amended and
restated effective April 1, 1999)
10(u)(2) -- Note Purchase Agreement between the HI's Form 10-K for the year ended 1-7629 10(j)(3)
Company and the ESOP Trustee, dated as of December 31, 1990
October 5, 1990
10(u)(3) -- Reliant Energy, Incorporated Master Form 10-K for the year ended 1-3187 10(u)(3)
Retirement Trust (as amended and restated December 31, 1999
effective January 1, 1999 and renamed
effective May 5, 1999)
10(v)(1) -- Stockholder's Agreement dated as of July Schedule 13-D dated July 6, 1995 5-19351 2
6, 1995 between the Company and Time
Warner Inc.
10(v)(2) -- Amendment to Exhibit 10(v)(1) dated HI's Form 10-K for the year ended 1-7629 10(x)(4)
November 18, 1996 December 31, 1996
*10(w)(1) -- Houston Industries Incorporated Executive Form 10-K for the year ended 1-7629 10(7)
Deferred Compensation Trust, effective as December 31, 1995
of December 19, 1995
*10(w)(2) -- First Amendment to Exhibit 10(w)(1) Form 10-Q for the quarter ended 1-3187 10
effective as of August 6, 1997 June 30, 1998
*10(x) -- Consulting Agreement, dated January 14, HI's Form 10-K for the year ended 1-7629 10(bb)
1997, between the Company and Milton December 31, 1996
Carroll
+*10(y) -- Reliant Energy, Incorporated Common Stock
Participation Plan for Designated New
Employees and Non-Office Employees,
effective as of March 4, 1998
+*10(z) -- Reliant Energy, Incorporated Annual Definitive Proxy Statement for 1-3187 Appendix I
Incentive Compensation Plan, as 2000 Annual Meeting of
established effective January 1, 1999 Shareholders
+12 -- Computation of Ratios of Earnings to
Fixed Charges
192
198
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ----------
+21 -- Subsidiaries of Reliant Energy
+23 -- Consent of Deloitte & Touche LLP
(B) RELIANT ENERGY RESOURCES CORP.
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
2(a)(1) -- Agreement and Plan of Merger among the HI's Form 8-K dated August 11, 1-7629 2
Company, HL&P, HI Merger, Inc. and NorAm 1996
dated August 11, 1996
2(a)(2) -- Amendment to Agreement and Plan of Merger Registration Statement on Form 333-11329 2(c)
among the Company, HL&P, HI Merger, Inc. S-4
and NorAm dated August 11, 1996
2(b) -- Agreement and Plan of Merger dated December Registration Statement on Form 333-54526 2
29, 2000 merging Reliant Resources Merger S-3
Sub, Inc. with and into Reliant Energy
Services, Inc.
3(a)(1) -- Certificate of Incorporation of RERC Corp. Form 10-K for the year ended 1-3187 3(a)(1)
December 31, 1997
3(a)(2) -- Certificate of Merger merging former NorAm Form 10-K for the year ended 1-3187 3(a)(2)
Energy Corp. with and into HI Merger, Inc. December 31, 1997
dated August 6, 1997
3(a)(3) -- Certificate of Amendment changing the name Form 10-K for the year ended 1-3187 3(a)(3)
to Reliant Energy Resources Corp. December 31, 1998
3(b) -- Bylaws of RERC Corp. Form 10-K for the year ended 1-3187 3(b)
December 31, 1997
4(a)(1) -- Indenture, dated as of December 1, 1986, NorAm's Form 10-K for the year 1-13265 4.14
between NorAm and Citibank, N.A., as ended December 31, 1986
Trustee
4(a)(2) -- First Supplemental Indenture to Exhibit Form 10-K for the year ended 1-3187 4(a)(2)
4(a)(1) dated as of September 30, 1988 December 31, 1997
4(a)(3) -- Second Supplemental Indenture to Exhibit Form 10-K for the year ended 1-3187 4(a)(3)
4(a)(1) dated as of November 15, 1989 December 31, 1997
4(a)(4) -- Third Supplemental Indenture to Exhibit Form 10-K for the year ended 1-3187 4(a)(4)
4(a)(1) dated as of August 6, 1997 December 31, 1997
4(b)(1) -- Indenture, dated as of March 31, 1987, NorAm's Registration Statement on 33-14586 4.20
between NorAm and Chase Manhattan Bank, Form S-3
N.A., as Trustee, authorizing 6%
Convertible Subordinated Debentures due
2012
4(b)(2) -- Supplemental Indenture to Exhibit 4(b)(1) Form 10-K for the year ended 1-3187 4(b)(2)
dated as of August 6, 1997 December 31, 1997
4(c)(1) -- Indenture, dated as of April 15, 1990, NorAm's Registration Statement on 33-23375 4.1
between NorAm and Citibank, N.A., as Trustee Form S-3
4(c)(2) -- Supplemental Indenture to Exhibit 4(c)(1) Form 10-K for the year ended 1-3187 4(c)(2)
dated as of August 6, 1997 December 31, 1997
4(d)(1) -- Form of Indenture between NorAm and The NorAm's Registration Statement on 33-64001 4.8
Bank of New York as Trustee Form S-3
4(d)(2) -- Form of First Supplemental Indenture to NorAm's Form 8-K dated June 10, 1-13265 4.01
Exhibit 4(d)(1) 1996
4(d)(3) -- Second Supplemental Indenture to Exhibit Form 10-K for the year ended 1-3187 4(d)(3)
4(d)(1) dated as of August 6, 1997 December 31, 1997
4(e) -- Indenture, dated as of December 1, 1997, Registration Statement on Form 333-41017 4.1
between RERC Corp. and Chase Bank of Texas, S-3
National Association
193
199
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
4(f)(1) -- Indenture, dated as of February 1, 1998, Form 8-K dated February 5, 1998 1-13265 4.1
between RERC Corp. and Chase Bank of Texas,
National Association, as Trustee
4(f)(2) -- Supplemental Indenture No. 1, dated as of Form 8-K dated February 5, 1998 1-13265 4.2
February 1, 1998, providing for the
issuance of RERC Corp.'s 6 1/2% Debentures
due February 1, 2008
There have not been filed as exhibits to this Form 10-K certain long-term
debt instruments, including indentures, under which the total amount of
securities do not exceed 10% of the total assets of Resources. Resources hereby
agrees to furnish a copy of any such instrument to the SEC upon request.
REPORT OR SEC FILE OR
EXHIBIT REGISTRATION REGISTRATION EXHIBIT
NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE
------- ----------- ------------ ------------ ---------
10(a) -- Service Agreement by and between NorAm's Form 10-K for the year 1-13265 10.20
Mississippi River Transmission Corporation ended December 31, 1989
and Laclede Gas Company dated August 22,
1989
+12 -- Computation of Ratios of Earnings to Fixed
Charges
+23 -- Consent of Deloitte & Touche LLP Reliant Energy's Form 10-K for 1-7629 23
the year ended December 31, 2000
194