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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, 2001
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 1-16455
RELIANT RESOURCES, INC.
(Exact name of registrant as specified in its charter)
DELAWARE 76-0655566
(State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification Number)
1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-3000
(Address and zip code of principal executive offices) (Registrant's telephone number, including area code)
SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:
TITLE OF EACH CLASS NAME OF EACH EXCHANGE ON WHICH REGISTERED
Common Stock, par value $.001 per share, and associated New York Stock Exchange
rights to purchase Series A Preferred Stock
SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
Indicate by check mark whether the registrant: (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 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 Resources, Inc. (Reliant Resources) was $833,436,412 as of April 1,
2002, 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 April 1, 2002, Reliant Resources
had 289,354,781 shares of Common Stock outstanding including 240,000,000 shares
which were held by Reliant Energy, Incorporated. Excluded from the number of
shares of Common Stock outstanding are 10,449,219 shares held by Reliant
Resources as treasury stock.
Portions of the definitive proxy statement relating to the 2002 Annual
Meeting of Stockholders of Reliant Resources, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2001, 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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TABLE OF CONTENTS
PART I
Item 1. Business...................................................................................... 4
Item 2. Properties.................................................................................... 31
Item 3. Legal Proceedings............................................................................. 31
Item 4. Submission of Matters to a Vote of Security Holders........................................... 32
PART II
Item 5. Market for Our Common Equity and Related Stockholder Matters.................................. 33
Item 6. Selected Financial Data....................................................................... 34
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations......... 36
Item 7A. Quantitative and Qualitative Disclosures About Market Risk.................................... 80
Item 8. Financial Statements and Supplementary Data................................................... F-1
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.......... III-1
PART III
Item 10. Directors and Executive Officers.............................................................. III-1
Item 11. Executive Compensation........................................................................ III-1
Item 12. Security Ownership of Certain Beneficial Owners and Management................................ III-1
Item 13. Certain Relationships and Related Transactions................................................ III-1
PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form 8-K............................... IV-1
i
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," "forecast," "goal," "intends,"
"may," "objective," "plans," "potential," "predicts," "projection," "should,"
"will," or other similar words.
For a list of factors that could cause actual results to differ materially
from those expressed or implied in our forward-looking statements, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings" in Item 7 of this
Form 10-K.
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.
You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.
The following sections of this Form 10-K contain forward-looking
statements:
- Our Business --
- General
- Formation, Initial Public Offering and Anticipated
Distribution
- Wholesale Energy --
- Northeast Region --
- Facilities
- Midwest Region --
- Facilities
- Florida and Other Southeastern Markets --
- Facilities
- West Region --
- Facilities
- ERCOT Region
- Facilities
- Development Activities
- Domestic Trading, Marketing, Power Origination and Risk
Management Services Operations --
- Natural Gas Trading and Marketing
- European Energy --
- European Trading, and Power Origination
Operations
- Retail Energy --
- Market Framework
- Retail Energy Supply
- Regulation --
- Federal Energy Regulatory Commission --
- Electricity
- Texas -- Retail Energy
1
- Environmental Matters --
- General
- Air Emissions
- Water Issues
- Liability for Preexisting Conditions and Remediation
- European Energy
- Management's Discussion and Analysis of Financial Condition and
Results of Operations --
- Our Separation from Reliant Energy, Incorporated
- Consolidated Results of Operations --
- 2001 Compared to 2000 --
- Income Tax Expense
- Results of Operations by Business Segment --
- Retail Energy
- Other Operations --
- 2001 Compared to 2000
- Related-Party Transactions --
- Agreements Between Reliant Energy and Reliant
Resources --
- Service Agreements
- Payment to Reliant Energy
- Common Directors on Reliant Resources' and Reliant
Energy's Board of Directors
- Certain Factors Affecting Out Future Earnings --
- Factors Affecting the Results of Our Wholesale Energy
Operations --
- Price Volatility
- Risk Associated with Our Hedging and Risk
Management Activities
- Uncertainty in the California Market
- Industry Restructuring, the Risk or Re-regulation
and the Impact of Current Regulations
- Uncertainty Related to the New York Regulatory
Environment
- Integration and Other Risks Associated with Our
Orion Power Assets
- Operating Risks
- Factors Affecting Our Acquisition and Project
Development Activities
- Increasing Competition in Our Industry
- Hydroelectric Facilities Licensing
- Factors Affecting the Results of Our European Energy
Operations --
- General
- Competition in the European Market
- Deregulation of the Dutch Market
- Plant Outages
- Other Factors
- Factors Affecting the Results of Our Retail Energy
Operations --
- General
- Competition in the Texas Market
- Obligations as a Provider of Last Resort
- "Clawback" Payment to Reliant Energy
- Operational Risks
- Factors Related to our Separation from Reliant Energy --
- Distribution
- Reliant Energy as a 80+% Stockholder
- Possible Conflicts of Interest
- Adverse Tax Consequences
- Deconsolidation from the Reliant Energy
Consolidated Tax Group
- Other Factors --
- Terrorist Attacks and Acts of War
- Environmental Regulation
- Holding Company Organizational Structure
- Liquidity Concerns
2
- Liquidity and Capital Resources --
- Consolidated Capital Requirements and Uses of Cash --
- Environmental Expenditures
- Mid-Atlantic Assets Lease Obligation
- Naming Rights to Houston Sports Complex
- Payment to Reliant Energy
- Treasury Stock Purchases
- Downgrade in Our Credit Rating
- Counterparty Credit Risk
- Consolidated Sources or Cash --
- Reliant Resources Restricted Cash
- Credit Facilities
- Reliant Resources Credit Facilities Covenants
- Orion Power Credit Facilities
- Potential Future Liquidity Sources --
- Commercial Paper Program
- Debt Securities in the Capital Markets
- Settlement of Indemnification of REPGB Stranded
Costs
- Factors Affecting Our Sources of Cash and Liquidity --
- Credit Ratings
- Off-Balance Sheet Transactions --
- Construction Agency Agreements
- Equipment Financing Structure
- New Accounting Pronouncements and Critical Accounting
Policies --
- New Accounting Pronouncements
- Critical Accounting Policies
- Quantitative and Qualitative Disclosures About Market Risk --
- Market Risk
- Trading Market Risk
- Non-trading Market Risk
- Risk Management Structure
- Credit Risk
3
ITEM 1. BUSINESS.
OUR BUSINESS
GENERAL
Reliant Resources, Inc., a Delaware corporation, was incorporated in
August 2000. In this Form 10-K, we refer to Reliant Resources, Inc. as "Reliant
Resources," and to Reliant Resources and its subsidiaries collectively, as "we"
or "us," unless the context clearly indicates otherwise. The executive offices
of Reliant Resources are located at 1111 Louisiana, Houston, TX 77002 (telephone
number 713-207-3000).
We provide electricity and energy services with a focus on the competitive
wholesale and retail segments of the electric power industry in the United
States. We acquire, develop and operate electric power generation facilities
that are not subject to traditional cost-based regulation and therefore can
generally 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.
As of December 31, 2001, we owned or leased electric power generation
facilities with an aggregate net generating capacity of 14,585 megawatts (MW),
including 11,109 MW in the United States and 3,476 MW in the Netherlands. Of the
11,109 MW in the United States, 1,179 MW represent our entitlement to capacity
of facilities that we lease under operating leases. For additional information
regarding these operating leases, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Consolidated Capital Requirements and Uses of Cash" in Item
7 of this Form 10-K, and Note 13(c) to our consolidated financial statements,
which, together with the notes related to these statements, we refer to in this
Form 10-K as our "consolidated financial statements." We acquired our first
power generation facilities in 1998 and have increased our net generating
capacity since then through a combination of acquisitions and development of new
generation projects. Since December 31, 2001, we have added 5,644 MW of
additional net generating capacity to our asset portfolio through our
acquisition of Orion Power Holdings, Inc. According to Resource Data
International, Inc., we are the second largest independent electric power
producer in the United States based on total MW of wholesale generation capacity
in operation as of February 28, 2002.
As of December 31, 2001, we had 3,587 MW (3,391 MW, net of 196 MW to be
retired upon completion of one facility) of additional net generating capacity
under construction, including 2,120 MW of facilities owned by off-balance sheet
special purpose entities that are being constructed under construction agency
agreements pursuant to synthetic leasing arrangements. Upon the completion of
construction, we expect that we will lease these facilities from their owners.
For additional information regarding the construction agency agreements, please
read "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Off-Balance Sheet Transactions"
in Item 7 of this Form 10-K and Note 13(h) to our consolidated financial
statements. We consider a project to be "under construction" once we have
acquired the necessary permits to begin construction, broken ground on the
project site and contracted to purchase machinery for the project, including the
combustion turbines.
Additionally, we became a retail electric provider (i.e., a seller of
electricity to retail customers) in Texas when that market began opening to
retail electric competition in late 2001 and fully opened to retail competition
in January 2002. Since then, all classes of customers of most investor-owned
Texas utilities, as well as those of any municipal utility or electric
cooperative that opted to participate in the competitive marketplace, have been
able to choose their retail electric provider. Under Texas regulation, retail
electric providers procure or buy electricity from wholesale generators at
unregulated rates, sell electricity at generally unregulated rates to their
retail customers and pay the local transmission and distribution regulated
utilities a regulated tariff rate for delivering the electricity to their
customers. In January 2002, we became the retail electric provider for all of
Reliant Energy HL&P's (formerly the integrated electric utility serving the
Houston, Texas metropolitan area) (Reliant Energy's electric utility)
approximately 1.7 million customers in the Houston area who did not take action
to select another retail electric provider. At that time, we were also able to
acquire and serve new retail electric customers in other Texas competitive
markets.
4
We conduct our operations through the following business segments:
- Wholesale Energy -- provides electricity and energy services in the
competitive segments of the United States wholesale energy
industries,
- European Energy -- includes power generation assets in the
Netherlands and a related trading and power origination business,
- Retail Energy -- provides electricity and related services to retail
customers primarily in Texas, and
- Other Operations -- includes the operations of our venture capital
and Communications businesses, and unallocated corporate costs.
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 and Note 18 to our consolidated financial statements. For information
regarding the decision to exit our Communications business, please read Note 16
to our consolidated financial statements.
FORMATION, INITIAL PUBLIC OFFERING AND ANTICIPATED DISTRIBUTION
Reliant Energy, Incorporated (Reliant Energy) owns more than 80% of our
outstanding common stock. Reliant Energy has adopted a business separation plan
in response to the Texas Electric Choice Plan (Texas electric restructuring law)
adopted by the Texas legislature in June 1999. The Texas electric restructuring
law substantially amended the regulatory structure governing electric utilities
in Texas in order to allow retail electric competition with respect to all
customer classes beginning in January 2002. Under its business separation plan
filed with the Public Utility Commission of Texas (Texas Utility Commission),
Reliant Energy has transferred substantially all of its unregulated businesses
to us in order to separate its regulated and unregulated operations. In
accordance with the plan, we completed our initial public offering (IPO) of
nearly 20% of our common stock in May 2001 and received net proceeds from the
IPO of $1.7 billion. Pursuant to the terms of the master separation agreement
between Reliant Energy and us, we used $147 million of the net proceeds to repay
certain indebtedness owed to Reliant Energy. We used the remainder of the net
proceeds of the IPO for repayment of third party borrowings, capital
expenditures, repurchases of our common stock and to increase our working
capital. For additional information regarding the IPO, please read Notes 1 and
9(a) to our consolidated financial statements. For additional information
regarding agreements and transactions between Reliant Resources and Reliant
Energy, please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Related-Party Transactions" in Item 7 of this Form
10-K and Notes 3 and 4 to our consolidated financial statements.
As part of its business separation plan, Reliant Energy has publicly
disclosed that it intends to restructure its corporate organization into a
public utility holding company structure (Reorganization) and to distribute,
subject to further governmental and corporate approvals, market and other
conditions, its remaining equity interest in our common stock to its or its
successor's shareholders (Distribution). In December 2001, Reliant Energy's
shareholders voted to approve the merger required for the holding company
reorganization. As a result of the Reorganization and the Distribution, Reliant
Energy's successor holding company will be named "CenterPoint Energy, Inc." and
will own essentially all of Reliant Energy's regulated businesses (CenterPoint
Energy), and we will become a separate company unaffiliated with CenterPoint
Energy. Reliant Energy has publicly disclosed its goal to complete the
Reorganization and subsequent Distribution as quickly as possible after all the
necessary conditions are fulfilled, including receipt of an order from the
Securities and Exchange Commission (SEC) granting the required approvals under
the Public Utility Holding Company Act of 1935 (1935 Act) and an extension from
the IRS for a private letter ruling obtained by Reliant Energy regarding
tax-free treatment of the Distribution. Reliant Energy has filed an application
with the SEC requesting the required approvals. The IRS private letter ruling is
predicated on the completion of the Distribution by April 30, 2002. Reliant
Energy is in the process of requesting an extension of this deadline. Reliant
Energy currently expects to complete the Reorganization and Distribution in the
summer of 2002. We cannot assure you that the Distribution will be completed as
described or within the time period outlined above.
5
ORION POWER ACQUISITION
On February 19, 2002, we acquired all of the outstanding shares of common
stock of Orion Power Holdings, Inc. (Orion Power) for $26.80 per share in cash
pursuant to a definitive merger agreement for an aggregate purchase price of
$2.9 billion. At the time of closing, Orion Power had approximately $2.4 billion
of debt obligations ($2.1 billion net of cash acquired, some of which is
restricted pursuant to debt covenants). Orion Power is an independent electric
power generating company that was formed in March 1998 to acquire, develop, own
and operate power-generating facilities in certain deregulated wholesale markets
in North America. Orion Power has a diversified portfolio of generating assets,
both geographically across the states of New York, Pennsylvania, Ohio and West
Virginia, and by fuel type, including gas, oil, coal and hydropower. As of
February 28, 2002, Orion Power owned 81 power plants with an aggregate net
generating capacity of 5,644 MW and had two development projects with an
additional 804 MW of capacity under construction. We consider most of the Orion
Power facilities to be part of our Northeast regional portfolio and the
remainder to be part of our Midwest regional portfolio. For additional
information regarding our acquisition of Orion Power and its operations, please
read "-- Wholesale Energy -- Northeast Region," and "-- Midwest Region," and
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Integration and Other Risks
Associated with Our Orion Power Assets" and "-- Uncertainty Related to the New
York Regulatory Environment" in Item 7 of this Form 10-K, and Note 19 to our
consolidated financial statements.
WHOLESALE ENERGY
Our Wholesale Energy business segment provides energy and energy services
with a focus on the competitive wholesale segment of the United States energy
industry. We acquire, develop and operate electric power generation facilities
that are not subject to traditional cost-based regulation and therefore can
generally sell power at prices determined by the market, subject to regulatory
limitations in certain regions. We also trade and market power, natural gas,
natural gas transportation capacity and other energy-related commodities and
provide related risk management services.
POWER GENERATION OPERATIONS
As of December 31, 2001, our Wholesale Energy business segment owned or
leased electric power generation facilities with an aggregate net generating
capacity of 11,109 MW located in five regions of the United States. We also had
3,587 MW (3,391 MW, net of 196 MW to be retired upon completion of one facility)
of net generating capacity under construction as of that date. In addition, by
acquiring Orion Power in February 2002, we added 81 power plants with an
aggregate net generating capacity of 5,644 MW and two development projects with
an additional 804 MW of capacity under construction to our regional portfolios.
6
The following table describes our Wholesale Energy business segment's
electric power generation facilities by region as of December 31, 2001.
REGIONAL SUMMARY OF OUR GENERATION FACILITIES
(AS OF DECEMBER 31, 2001)
NUMBER OF TOTAL NET
GENERATION GENERATING CAPACITY
REGION FACILITIES(1) (MW) DISPATCH TYPE(2) FUEL TYPE
------ ------------- ------------------- ----------------- ---------
NORTHEAST
Operating(3).............................. 21 4,262 Base, Inter, Peak Gas/Coal/Oil/Hydro
Under Construction(4)(5)(6)............... 1 1,120 Base, Inter, Peak Gas/Oil/Coal
------ ------
Combined.................................. 22 5,382
MIDWEST
Operating................................. 2 1,063 Peak Gas
Under Construction(7)..................... -- 154 Peak Gas
------ ------
Combined.................................. 2 1,217
SOUTHEAST
Operating(8).............................. 3 979 Inter, Peak, Cogen Gas/Oil
Under Construction(5)(9).................. 1 958 Base, Inter, Peak Gas/Oil
------ ------
Combined.................................. 4 1,937
WEST
Operating(7).............................. 7 4,635 Base, Inter, Peak Gas
Under Construction........................ 1 548 Base, Peak Gas
------ ------
Combined.................................. 8 5,183
ERCOT(10)
Operating................................. 1 170 Base, CoGen Gas
Under Construction(4)..................... -- 611 Base, CoGen Gas
------ ------
Combined.................................. 1 781
TOTAL
Operating................................. 34 11,109
Under Construction........................ 3 3,391
------ ------
Combined.................................. 37 14,500
====== ======
- ----------
(1) Unless otherwise indicated, we own a 100% interest in each facility
listed.
(2) We use the designations "Base," "Inter," "Peak" and "CoGen" to indicate
whether the facilities described are base-load, intermediate, peaking or
cogeneration facilities, respectively.
(3) We lease a 100%, 16.67% and 16.45% interest in three Pennsylvania
facilities having 613 MW, 285 MW and 281 MW, respectively, through
facility lease agreements having terms of 26.5 years, 33.75 years and
33.75 years, respectively.
(4) One of our two construction projects in this region will replace one of
our existing facilities upon completion. Therefore, this project is not
included in the facility count for the "Under Construction" group of this
region.
(5) Our two construction projects in the Northeast region and one of our
projects in the Southeast region are owned by off-balance sheet special
purpose entities and are being constructed under construction agency
agreements pursuant to synthetic leasing arrangements. We expect that we
will lease these facilities from their owners upon completion.
(6) The 1,120 MW of net capacity under construction is based on 1,316 MW of
capacity currently under construction less 196 MW of operating capacity
that will be retired upon completion of one of the projects.
(7) Five of the six generating units of one of the facilities in this region
are operational while the sixth unit is under construction. This partially
operational facility is included in the facility count for the "Operating"
group of this region.
(8) We own a 50% interest in one of these facilities. An independent third
party owns the other 50%.
(9) Two of the three generating units of one of the facilities in this region
are operational while the third unit is under construction. This partially
operational facility is included in the facility count for the "Operating"
group of this region.
7
(10) We also have an option, which is exercisable in January 2004, subject to
completion of the Distribution, to acquire Reliant Energy's approximate
80% interest in a company that is currently expected to own approximately
13,900 MW of net generating capacity in the Electric Reliability Council
of Texas (ERCOT) in January 2004. For additional information regarding
this option, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Related-Party
Transactions -- Agreements between Reliant Energy and Reliant Resources --
Genco Option Agreement" in Item 7 of this Form 10-K and Note 4(b) to our
consolidated financial statements.
The following table describes our Orion Power electric power generation
facilities by region as of February 28, 2002.
REGIONAL SUMMARY OF OUR ORION POWER FACILITIES
(AS OF FEBRUARY 28, 2002)
NUMBER OF TOTAL NET
GENERATION GENERATING
REGION FACILITIES CAPACITY (MW) DISPATCH TYPE(1) FUEL TYPE
------ ---------- ------------- ---------------- ---------
NORTHEAST
Operating(2).............................. 78 4,174 Base, Inter, Peak Gas/Oil/Coal/Hydro
Under Construction........................ 2 804 Base, Inter Gas
------ ------
Combined.................................. 80 4,978
MIDWEST
Operating................................. 3 1,470 Base, Inter, Peak Coal/Gas
TOTAL
Operating(2).............................. 81 5,644
Under Construction........................ 2 804
------ ------
Combined(2)............................... 83 6,448
====== ======
- ----------
(1) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking, respectively.
(2) Two hydro plants with a net generating capacity of approximately 5 MW are
not currently operational.
NORTHEAST REGION
Facilities. As of December 31, 2001, we owned or leased 21 electric power
generation facilities with an aggregate net generating capacity of 4,262 MW
located in the control area of PJM Interconnection, L.L.C. (PJM ISO), the
independent system operator in the Pennsylvania-New Jersey-Maryland market (PJM
market). These facilities are owned or leased by subsidiaries of one of our
wholly owned subsidiaries, Reliant Energy Mid-Atlantic Power Holdings, LLC
(REMA). The generating capacity of these facilities consists of approximately
40% of base-load, 40% of intermediate and 20% of peaking capacity, and
represents approximately 7% of the total generation capacity located in the PJM
ISO's control area. For additional information regarding our acquisition of
these facilities, please read Note 5(a) to our consolidated financial
statements.
By acquiring Orion Power in February 2002, we added 78 power generation
facilities, of which 75 are currently operational, with an aggregate net
generating capacity of 4,174 MW to our Northeast regional portfolio. These
facilities include 70 hydroelectric facilities, of which 68 are currently
operational, located in central and northern New York State, three facilities
located in New York City, one facility located in East Syracuse, New York, and
four facilities, three of which are currently fully operational, located in
Pennsylvania. The generating capacity of these facilities consists of
approximately 45% of base-load, 35% of intermediate and 20% of peaking capacity.
For a discussion of factors that may affect the future earnings generated by
these Orion Power facilities, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Our Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations -- Integration and Other Risks Associated With Our Orion Power
Assets" and "-- Uncertainty Related to the New York Regulatory Environment" in
Item 7 of this Form 10-K.
8
We have begun construction on a 795 MW gas-fired base-load and
intermediate facility located in Pennsylvania. We expect this facility will
begin commercial operation in the second quarter of 2003. We have also begun
construction on a 521 MW coal-fired base-load facility, also located in
Pennsylvania, that will replace one of our existing facilities. This facility
will add 325 MW of additional capacity to our Northeast regional portfolio, net
of the 196 MW of capacity of the currently existing facility that will be
retired upon commencement of commercial operations of the new facility. We
expect this facility will begin commercial operation near the end of 2004. These
facilities are owned by off-balance sheet special purpose entities and are being
constructed under the terms of separate construction agency agreements pursuant
to synthetic leasing arrangements. Upon completion of the construction of these
facilities, we expect that we will lease these facilities from their owners,
purchase or remarket each facility. For additional information regarding the
construction agency agreements, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Off-Balance Sheet Transactions -- Construction Agency
Agreements" in Item 7 of this Form 10-K and Note 13(h) to our consolidated
financial statements.
By acquiring Orion Power in February 2002, we added two additional
development projects with an additional 804 MW of capacity under construction.
The first project is the construction of a 550 MW gas-fired base-load facility
located south of Philadelphia, Pennsylvania. We expect this facility will begin
commercial operation in the second quarter of 2002. The second project is the
conversion and upgrade of a peaking facility located near downtown Pittsburgh,
Pennsylvania. We expect this project will be completed by the third quarter of
2002 and will increase the aggregate generating capacity of this facility by 254
MW to a total capacity of 308 MW.
Market Framework. We currently sell the power generated by our Northeast
regional facilities in the PJM market, the wholesale energy market of the State
of New York (New York wholesale market) operated by the New York Independent
System Operator (NYISO) and to buyers in adjacent power markets, such as the
region covered by the East Central Area Reliability Coordinating Counsel (ECAR
market). We also expect to sell power in a newly created extension of the PJM
market in western Pennsylvania (PJM West market). Each of the PJM Market, the
New York wholesale market and the PJM West market operate as centralized power
pools with open-access, non-discriminatory transmission systems administered by
independent system operators approved by the Federal Energy Regulatory
Commission (FERC). Although the transmission infrastructure within these markets
is generally well developed and independently operated, transmission constraints
exist between, and to a certain extent within, these markets. In particular,
transmission of power from eastern Pennsylvania to western Pennsylvania and into
New York City may be constrained from time to time. Depending on the timing and
nature of transmission constraints, market prices may vary from market to
market, or between sub-regions of a particular market. For example, as a result
of transmission constraints into New York City, power prices are generally
higher there than in other parts of the state.
In addition to managing the transmission system for each market, the
respective independent system operator for each of the PJM market, the New York
wholesale market and the PJM West market is responsible for maintaining
competitive wholesale markets, operating the spot wholesale energy market and
determining the market clearing price based on bids submitted by participating
generators in each market. Each independent system operator generally matches
sellers with buyers within a particular market that meet specified minimum
credit standards. We sell capacity, energy and ancillary services into the
markets maintained by the applicable independent system operator for each of
these types of products for both real-time sales and forward-sales for periods
of up to one year. Our customers include the members of each market, consisting
of municipalities, electric cooperatives, integrated utilities, transmission and
distribution utilities, retail electric providers and power marketers. We also
sell capacity, energy and ancillary services to customers in the Northeast
region under negotiated bilateral contracts. Bilateral contracts, in addition to
other physical and financial transactions enable us to hedge a portion of our
generation portfolio. For a more complete description of our hedging strategy
and a summary of the consolidated hedge position of our United States generating
assets, please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future Earnings --
Factors Affecting the Results of Our Wholesale Energy Operations -- Risks
Associated with Our Hedging and Risk Management Activities" in Item 7 of this
Form 10-K.
Our markets in the Northeast region are subject to constant and
significant regulatory oversight and control and the results of our operations
in the region may be adversely affected by any changes or additions to the
current regulatory structure. Our sales into markets administered by the PJM ISO
are governed by the PJM ISO's operating
9
agreements, tariffs and protocols (PJM Protocols). The PJM Protocols provide the
structure, rules and pricing mechanisms for the PJM ISO's energy, capacity and
ancillary services markets, and establish rates, terms and conditions for
transmission service in the PJM ISO's control area and the PJM West market,
including transmission congestion pricing. Wholesale energy prices in the
markets administered by the PJM ISO are currently capped at $1,000 per
megawatt-hour. Lower caps are utilized in other regions and it is possible that
this price cap might be lowered in the future.
Our sales into markets administered by the NYISO are governed by the
NYISO's tariff and protocols (NYISO Protocols). The NYISO Protocols provide the
structure, rules and pricing mechanisms for the NYISO's energy, capacity and
ancillary services markets, and establish rates, terms and conditions for
transmission service in the NYISO's control area. The NYISO Protocols allow
energy demand, commonly referred to as "load," to respond to high prices in
emergency and non-emergency situations. The lack of programs, however, to
implement load response to prices has been cited as one of the primary reasons
for retaining wholesale energy bid caps, which are currently set at $1,000 per
megawatt-hour. Lower price caps are utilized in other regions and it is possible
that this price cap might be lowered in the future.
A capacity market has been established by the NYISO that ensures that
there is enough generation capacity to meet retail energy demand and ancillary
services requirements. All power retailers are required to demonstrate
commitments for capacity sufficient to meet their peak forecasted load plus a
reserve requirement, currently set at 18%. As an extra reliability measure,
power retailers located in New York City are required to procure the majority of
this capacity, currently 80% of their peak forecasted load, from generating
units located in New York City. Because New York City is currently short of this
capacity requirement and the existing capacity is owned by only a few entities,
a price cap has been instituted for in-city generators.
For additional discussion of the impact of current regulations on the
markets in the Northeast region and the related risks of re-regulation, please
read "-- Regulation -- Federal Energy Regulatory Commission" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Certain Factors Affecting Our Future Earnings -- Factors Affecting the Results
of Our Wholesale Energy Operations -- Industry Restructuring, the Risk of
Re-regulation and the Impact of Current Regulations" and "-- Uncertainty Related
to the New York Regulatory Environment" in Item 7 of this Form 10-K.
MIDWEST REGION
Facilities. As of December 31, 2001, we owned two electric power
generation facilities located in the State of Illinois with an aggregate net
generating capacity of 1,063 MW in operation. One of these facilities is a 344
MW gas-fired peaking generation facility located in Shelby County, Illinois. The
first phase of this facility was initially placed in commercial operation in
June 2000 and the second phase was placed in commercial operation in May 2001.
We also have an 873 MW gas-fired peaking generation facility under construction
in Aurora, Illinois. As of December 31, 2001, five of the six generating units
at this facility with an aggregate net generating capacity of 719 MW had been
placed in commercial operation. We expect the remaining unit at this facility
will begin commercial operation in the second quarter of 2002.
By acquiring Orion Power in February 2002, we added three power generation
facilities with an aggregate net generating capacity of 1,470 MW to our Midwest
regional portfolio. Two of these facilities are located in Ohio and one is
located in West Virginia. The generating capacity of these facilities consists
of approximately 50% of base-load, 15% of intermediate and 35% of peaking
capacity. For a discussion of the factors that may affect the future earnings
generated by these Orion Power assets, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Integration and Other Risks Associated With Our Orion Power
Assets" in Item 7 of this Form 10-K.
Market Framework. We sell the power generated by our Midwest regional
facilities into the ECAR market and the region covered by the Mid-America
Interconnected Network Reliability Council (MAIN market). These markets include
all or portions of the states of Illinois, Wisconsin, Missouri, Indiana, Ohio,
Michigan, Virginia, West Virginia, Tennessee, Maryland and Pennsylvania. These
markets are currently in a state of transition and are in the process of
establishing regional transmission organizations (RTO) that would define the
rules and
10
requirements around which competitive wholesale markets in the region would
develop. The FERC has approved proposals by the Midwest Independent System
Operator (Midwest ISO) to administer a substantial portion of the transmission
facilities in the Midwest region. The FERC also has ordered the Alliance RTO,
which had a separate proposal to be the RTO for parts of the Midwest region, to
explore joining the Midwest ISO. As a result, the final market structure for the
Midwest region remains unsettled. The timing of the development of a RTO and the
extent to which the Midwest ISO and the Alliance RTO would combine is currently
unknown. In addition, some states within these markets have restructured their
electric power markets to competitive markets from traditional utility monopoly
markets, while others have not. Currently the transmission infrastructure in
these markets is generally owned by non-independent market participants, some of
which are our competitors, which has the potential to create market anomalies.
Transmission constraints exist in these markets and have been managed by the
owners of the transmission infrastructure, subject to transmission tariffs and
protocols regulated by the FERC.
We currently sell power from our facilities in the Midwest region to
customers under bilateral contracts that are generally non-standard with highly
negotiated terms and conditions. Our customers include municipalities, electric
cooperatives, integrated utilities, transmission and distribution utilities and
power marketers. Direct customer sales, in addition to other physical and
financial transactions enable us to hedge a portion of our generation portfolio.
For a more complete description of our hedging strategy and a summary of the
consolidated hedge position of our United States generating assets, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Risks Associated with Our
Hedging and Risk Management Activities" in Item 7 of this Form 10-K.
FLORIDA AND OTHER SOUTHEASTERN MARKETS
Facilities. As of December 31, 2001, we owned, or owned interests in,
three power generation facilities with an aggregate net generating capacity of
979 MW located in the states of Florida and Texas. These facilities include one
gas and oil-fired generation facility with an aggregate net generating capacity
of 619 MW located near Titusville, Florida. This facility can be operated as
either an intermediate or a peaking facility. We also own a 464 MW gas and
oil-fired peaking generation facility in Osceola County, Florida. Two of the
three generating units of this plant with an aggregate net generating capacity
of 310 MW commenced commercial operation in December 2001. We expect the
remaining generating unit at this facility will begin commercial operation in
the second quarter of 2002. In addition, we own a 50% interest in a 100 MW
gas-fired base-load/cogeneration facility located in Orange, Texas. Air Liquide
owns the other 50% interest in this plant which has been in commercial operation
since December 1999.
We have begun construction on an 804 MW gas-fired intermediate/peaking
facility in Choctaw County, Mississippi. We expect this facility will begin
commercial operation in the second quarter of 2003. This facility is being
constructed under the terms of a construction agency agreement under a synthetic
leasing arrangement. Upon completion of the construction of this facility, we
will have the right to lease, purchase or remarket the facility. For additional
information regarding the construction agency agreement, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Off-Balance Sheet Transactions
- -- Construction Agency Agreements" in Item 7 of this Form 10-K, and Note 13(h)
to our consolidated financial statements.
Market Framework. We currently conduct the majority of our Southeast
regional operations in the state of Florida. The state of Florida, other than a
portion of the western panhandle, constitutes a single reliability council and
contains approximately 5% of the United States population. The
transmission-owning utilities in Florida have proposed establishing an
independent system operator to assume control of the transmission system and
undertake to define the rules and requirements for a competitive wholesale
market. The timing of the development of an independent system operator for the
Florida market is currently unknown. Under its present structure, the Florida
market is dominated by incumbent utilities. There are a number of statutory and
regulatory restrictions that negatively impact the development of additional
power generation facilities in the region.
We currently sell power from our facilities in the Florida market under
bilateral contracts that are non-standard and highly negotiated for terms and
conditions. Until the rules for system operations are established, we expect
limited trading opportunities will exist in the Florida market. The customers
who participate in power transactions
11
in this region include municipalities, electric cooperatives and integrated
utilities. We sell capacity and energy to customers in the Florida market,
however a market for ancillary services has not developed. Forward hedging of a
portion of our Florida portfolio is generally accomplished through
customer-tailored, multi-year sale agreements as no liquid, over-the-counter or
auction markets currently exists in Florida. For a more complete description of
our hedging strategy and a summary of the consolidated hedge position of our
United States generation assets, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Risks Associated with Our Hedging and Risk Management
Activities" in Item 7 of this Form 10-K.
With respect to our facilities in East Texas and Mississippi, several of
the transmission-owning utilities in the Southeast region have formed the
SETrans Grid Company (SETrans RTO) that they are proposing to serve as the
region's RTO. The proposed SETrans RTO would manage, but not own, the
transmission grid in the region and operate forward and spot markets for energy.
The SETrans RTO has filed a status report with the FERC, but has not filed
tariffs or protocols and has not been approved as the region's RTO.
WEST REGION
Facilities. As of December 31, 2001, we owned, or owned interests in,
seven electric power generation facilities with an aggregate net generating
capacity of 4,635 MW located in the states of California, Nevada and Arizona.
These facilities include approximately 20% of base-load, 75% of intermediate and
5% of peaking capacity. Our facilities in the West region include five
facilities with an aggregate net generating capacity of 3,800 MW located in
California. We also 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. In addition, we own a 590 MW gas-fired, base-load,
peaking generation facility in Casa Grande, Arizona. This facility was placed in
commercial operation in the fourth quarter of 2001. We also have a 548 MW
gas-fired, base-load, peaking generation facility under construction in
Nevada. We expect this facility will begin commercial operation in the fourth
quarter of 2003.
Market Framework. Our West regional market includes the states of Arizona,
California, Oregon, Nevada, New Mexico, Utah and Washington. Generally we sell
the power generated by our California and Nevada facilities to customers located
in the Los Angeles basin of southern California. We also sell power generated by
our Nevada facility to customers located in southern Nevada. Our customers in
these states include power marketers, investor-owned utilities, electric
cooperatives, municipal utilities and the California Independent System Operator
(Cal ISO) acting on behalf of load-serving entities. We sell power and ancillary
services to these customers through a combination of bilateral contracts and
sales made in the Cal ISO's day-ahead and hour-ahead ancillary services markets
and its real-time energy market. The Cal ISO does not currently maintain a
market for capacity; however, a capacity market has recently been proposed by
the Cal ISO under its market mitigation plan for the California market.
We have agreed to sell up to 100% of the power generated by our Arizona
facility to the Salt River Project Agricultural Improvement and Power District
of the State of Arizona under a long-term power purchase agreement. Bilateral
contracts, in addition to other physical and financial transactions enable us to
hedge a portion of our generation portfolio. For a more complete description of
our hedging strategy and a summary of the consolidated hedge position of our
United States generating assets, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Risks Associated with Our Hedging and Risk Management
Activities" in Item 7 of this Form 10-K. In addition, although we do not own
generation facilities in the states of Oregon, New Mexico, Utah and Washington,
our trading and marketing operations purchase and deliver energy commodities in
these states.
Our operations in the California market are subject to numerous
environmental and other regulatory restrictions. Permits issued by local air
districts restrict the output of some of our generating facilities. In addition,
certain air districts require us to purchase emission credits to offset Nitrogen
Oxides (NOx) emissions from our facilities.
In response to California's electricity market restructuring initiative,
the FERC issued a series of orders in 1996 and 1997 approving a wholesale market
structure administered by two independent non-profit corporations: the Cal
12
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 California Power Exchange (Cal PX), responsible for conducting
auctions for the purchase or sale of electricity on a day-ahead or day-of basis.
As part of this market restructuring, California's distribution 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
initially frozen at levels in effect on June 10, 1996, with a 10% rate reduction
for residential and smaller commercial customers. When wholesale power costs
began to rise dramatically 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 and decreases in
net imports, some of the California utilities were unable to recover their
purchased power costs through the retail rates they were allowed to charge. As a
result, the utilities accumulated huge debts to wholesale power suppliers,
including us. The Cal ISO currently is conducting a major market redesign
process that, if approved by the FERC, could change the structure of the markets
operated by the Cal ISO, including changes to market monitoring and mitigation,
congestion management and capacity obligations. For a discussion of litigation
and other legal proceedings related to energy sales in California, the impact of
current regulations on our West region and related uncertainty associated with
the California wholesale market, please read "-- Regulation -- Federal Energy
Regulatory Commission," "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Wholesale Energy Operations --
Uncertainty in the California Market" and Notes 13(e) and 13(i) to our
consolidated financial statements.
In Nevada and Arizona, there is presently no RTO in place to manage the
transmission systems or to operate energy markets, although one RTO working
group is evaluating the establishment of an organization that would assume
control, subject to FERC approval, over the transmission systems of the
utilities operating in this region. The FERC has recently expressed its
intention to pursue the establishment of an RTO in the West region.
Additionally, in Nevada and Arizona, state-level regulatory initiatives
may impact competition in the electric sector. In Nevada, the state legislature
has passed legislation prohibiting the state's investor-owned utilities from
divesting generation. Similarly, in Arizona, proceedings are pending before the
Arizona Corporation Commission that would allow the Arizona Public Service
Company to avoid a requirement to seek competitive bids for 50% of the Arizona
Public Service Company's generation needs.
ERCOT REGION
Facilities. We currently own a partially operational 781 MW gas-fired,
combined cycle, cogeneration facility in Channelview, Texas. 170 MW of this
facility's capacity is currently operational and 611 MW are under construction.
We expect the remaining generating units for this facility will begin commercial
operations in the third quarter of 2002.
In addition to our Channelview facility, we have an option exercisable in
January 2004, subject to completion of the Distribution, to acquire Reliant
Energy's ownership interest in a company (Texas Genco) that is currently
expected to own approximately 13,900 MW of aggregate net generation capacity in
Texas in January 2004 (Texas Genco Option). Reliant Energy has agreed to
publicly offer or distribute to its shareholders approximately 20% of the common
stock of Texas Genco before December 31, 2002. The generating capacity of these
facilities consists of approximately 60% of base-load, 35% of intermediate and
5% of peaking capacity, and represents approximately 20% of the total capacity
in ERCOT. As part of Reliant Energy's business separation plan, Reliant Energy's
electric utility will convey its generating assets to Texas Genco. The
conveyance is part of the anticipated restructuring of Reliant Energy's
businesses into a holding company structure. For additional information
regarding the Texas Genco Option, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Related Party
Transactions -- Agreements between Reliant Energy and Reliant Resources -- Genco
Option Agreement" in Item 7 of this Form 10-K, and Note 4(b) to our consolidated
financial statements.
Market Framework. The state of Texas, other than a portion of the
panhandle and a portion of the east bordering on Louisiana, constitutes a single
reliability council (ERCOT market). As part of the transition to deregulation in
Texas, ERCOT changed its operations from 10 control areas, managed by utilities
in the state, to a
13
single control area on July 31, 2001. The ERCOT independent system operator
(ERCOT ISO) is responsible for maintaining reliable operations of the bulk
electric power supply system in the ERCOT market. Its 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. It is
also responsible for ensuring that electricity production and delivery are
accurately accounted for among the generation resources and wholesale buyers and
sellers in the ERCOT market. Unlike independent systems operators in other
regions of the country, ERCOT is not a centrally dispatched pool and the ERCOT
ISO does not procure energy on behalf of its members other than to maintain the
reliable operation of the transmission system. Members are responsible for
contracting their energy requirements bilaterally. ERCOT also serves as agent
for procuring ancillary services for those who elect not to provide their own
ancillary services requirement.
Members of ERCOT include retail customers, investor and municipal owned
electric utilities, rural electric co-operatives, river authorities, independent
generators, power marketers and retail electric providers. The ERCOT market
operates under the reliability standards set by the North American Electric
Reliability Council. The Texas Utility Commission has primary jurisdictional
authority over the ERCOT market to ensure the adequacy and reliability of
electricity across the state's main interconnected power grid. For information
regarding ERCOT systems issues and delays, please read "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Retail
Energy Operations -- Operational Risks" in Item 7 of this Form 10-K.
As part of the change to a single control area, ERCOT initially
established three congestion zones; north, west and south. ERCOT will perform an
annual analysis of the transmission capability in ERCOT to determine if changes
to the congestions zones is required. Any required changes will take effect
January 1 of the following year. Such an analysis was performed in the fall of
2001 and as a result, ERCOT was divided into four congestion zones on January 1,
2002. The current zones are north, south, west and Houston. In addition, ERCOT
conducts annual and monthly auctions of Transmission Congestion Rights (TCR)
which provide the entity owning TCRs the ability to financially hedge price
differences between zones (basis risk). Entities are currently limited to owning
a maximum of 25% of the available TCRs. The retail load obligation of our Retail
Energy segment that was acquired as part of full retail deregulation on January
1, 2002 is predominately in the Houston zone. For additional information
regarding the retail load obligations of our Retail Energy segment, please read
"-- Retail Energy -- Retail Energy Supply."
LONG-TERM PURCHASE AND SALE AGREEMENTS
In the ordinary course of business, and as part of our hedging strategy,
we enter into long-term sales arrangements for power, as well as long-term
purchase arrangements. For information regarding our long-term fuel supply
contracts, purchase power and electric capacity contracts and commitments,
electric energy and electric sale contracts and tolling arrangements, please
read Notes 6, 13(a) and 13(c) to our consolidated financial statements. For
information regarding our hedging strategy relating to such long-term
commitments, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Wholesale Energy Operations --
Risks Associated with Our Hedging and Risk Management Activities" in Item 7 of
this Form 10-K.
DEVELOPMENT ACTIVITIES
As of December 31, 2001, we had 3,587 MW (3,391 MW, net of 196 MW to be
retired upon completion of one facility) of additional net generating capacity
under construction, including 2,120 MW of facilities owned by off-balance sheet
special purpose entities, that are being constructed under construction agency
agreements pursuant to synthetic leasing arrangements. Upon the completion of
the construction of these facilities, we expect that we will lease these
facilities from their owners. For additional information regarding the
construction agency agreements, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Off-Balance Sheet Transactions -- Construction Agency
Agreements" in Item 7 of this Form 10-K, Note 13(h) to our consolidated
financial statements.
In addition, Orion Power had three projects totaling 1,054 MW under
construction as of December 31, 2001. However, at this time, we have decided to
postpone a 250 MW project in Florida because of capital market and
14
economic considerations. With improved capital market conditions and required
approvals from Florida authorities on a newly configured 500 MW design, we would
plan to proceed with construction in the future. Also, Orion Power had two
projects under advanced development as of December 31, 2001, which have been
deferred. A 1,088 MW project in Maryland has been postponed due to capital
market considerations and because we believe that the PJM market will be
sufficiently supplied for the next few years. A repowering project in New York
City with a total capacity of 1,608 MW has been postponed until we see an
improvement in the capital markets.
As a result of several recent events, including the United States economic
recession, the price decline of our industry sector in the equity capital
markets and the downgrading of the credit ratings of several of our significant
competitors, the availability and cost of capital for our business and the
businesses of our competitors has been adversely affected. In response to these
events and the intensified scrutiny of companies in our industry sector by the
rating agencies, we have reduced our planned capital expenditures by $2.7
billion over the 2002 -- 2006 time frame.
DOMESTIC TRADING, MARKETING, POWER ORIGINATION AND RISK MANAGEMENT SERVICES
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. According to Platt's Power Markets Week
and Natural Gas Intelligence Group, we were the third largest power trader and
ninth largest natural gas trader in the United States in 2001. 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 emission 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 power 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 1999.
TRADING VOLUMES
FOR THE YEAR ENDED DECEMBER 31
---------------------------------------------
1999 2000 2001
----------- ----------- -----------
Total Power (MWh(1)) ...... 112,133,103 201,938,485 380,404,604
Total Gas (Bcf(2)) ........ 1,746 2,423 3,695
- ----------
(1) Megawatt hours.
(2) Billion cubic feet.
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. Some of our employees focus on developing and providing
customers with long-term customized products (power origination products). These
products are designed and negotiated on a case-by-case
15
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 and term, variable-load and base-load
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 10.1 Bcf per day of natural gas in 2001, an average of 6.6
Bcf per day in 2000 and an average of 4.8 Bcf per day in 1999, some of which was
sold to the natural gas distribution company subsidiaries of Reliant Energy. We
plan to continue to purchase natural gas to supply to 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 arrange for, schedule and balance the transportation of the natural gas
we market from the supply receipt point to the purchaser's delivery point. We
generally obtain pipeline transportation to serve our customers. Accordingly, we
use a variety of transportation arrangements for our customers, including
short-term and long-term firm and interruptible agreements with intrastate and
interstate pipelines. We also utilize brokered firm transportation agreements
when dealing on the interstate pipeline system. As of December 31, 2001, we held
over two bcf per day of firm transportation in the United States. In the normal
course of business it is common for us to hedge the risk of pipeline
transportation expenses through "basis swaps." To the extent we have
contractually secured pipeline transportation rights in order to fulfill our
obligations to sell gas at specific delivery points, or to acquire gas for our
own requirements at generation facilities as part of our hedging strategy for
power sales, and a pipeline experiences a force majeure event, our ability to
transport gas on a contracted capacity basis could become impaired, which could
affect the integrity of our hedged position.
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. Natural gas
storage capacity allows us to better manage the unpredictable daily or seasonal
imbalances between supply volumes and demand levels. In addition to entering
into contracts of natural gas storage capacity in strategic locations throughout
the country, we are actively pursuing a natural gas storage development plan.
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 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 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 instruments, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations -- Risks Associated with Our Hedging and Risk Management Activities"
in Item 7 of this Form 10-K and "Quantitative and Qualitative Disclosures About
Market Risk" in Item 7A of this Form 10-K.
Intercontinental Exchange. 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 Corporation, made an investment in
Intercontinental-Exchange, a new, web-based, on-line trading platform
(www.intcx.com) for trading various commodities including precious metals, crude
oil and refined products, natural gas and electricity. The other five natural
gas and power companies, along with us, own less than 50% of Intercontinental --
Exchange. In June 2001, Intercontinental-Exchange acquired the International
Petroleum Exchange. With this acquisition, Intercontinental-Exchange became the
first company to offer both an exchange trading over-the-counter commodity
contracts and an
16
exchange trading commodity futures contracts. At the same time,
Intercontinental-Exchange announced plans to integrate the two types of
exchanges into a single electronic trading platform. Our decision to invest, as
one of a group of natural gas and power companies, in Intercontinental-Exchange
was based on a desire to support the development of a neutral, anonymous,
electronic trading platform for bi-lateral energy transactions. We believe the
commercial success of such an exchange model will benefit us by contributing to
improved price transparency and transaction liquidity in the wholesale energy
markets. The principal online competitors of Intercontinental-Exchange are
currently TradeSpark.com and the NYMEX, a traditional futures exchange that has
announced an online initiative.
Risk Management Controls. For information regarding our risk management
structure and accounting policies, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Trading and
Marketing Operations" in Item 7 of this Form 10-K and "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K.
COMPETITION
For a discussion of competitive factors affecting our Wholesale Energy
segment, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Wholesale Energy Operations --
Increasing Competition in Our Industry" in Item 7 of this Form 10-K, which
section is incorporated herein by reference.
EUROPEAN ENERGY
Our European Energy business segment includes 3,476 MW of power generation
assets located in the Netherlands and a related trading and power origination
operations. This segment includes the operations of Reliant Energy Power
Generation Benelux N.V. (formerly UNA N.V.) (REPGB) and Reliant Energy Trading &
Marketing B.V. and its affiliates.
In 2001, we evaluated strategic alternatives for our European Energy
segment, including a possible sale. We completed our evaluation and have
determined that given current market conditions and prices, it is not advisable
to sell our European Energy operations. Consequently, we decided to continue to
own and operate our European Energy segment and expand our trading and
origination activities in Northwest Europe.
EUROPEAN POWER GENERATION OPERATIONS
Facilities. As of December 31, 2001 we owned five electric power
generation facilities in the Netherlands with an aggregate net generating
capacity of 3,476 MW and include approximately 39% of base-load, 36% of
intermediate and 25% of peaking capacity. Our facilities are grouped in three
clusters adjacent to the cities of Amsterdam, Utrecht and Velsen. In 2001, our
generation facilities produced 14 million MWh, an amount which represented
approximately 13% of the electricity production of the Netherlands (excluding
electricity generated by cogeneration or other industrial processes). In
addition to electricity, our generating stations sell heated water produced as a
byproduct of the generation process for use in providing heating (district
heating) to the cities of Amsterdam, Nieuwegein, Utrecht and Purmerend.
In 2001, approximately 51% of our European Energy segment's generation
output was natural gas-fired, 30% was coal-fired, 18% was blast furnace
gas-fired and less than 1% was oil-fired. Our European Energy segment purchases
substantially all of its gas fuel requirements under medium to long-term gas
purchase contracts with N.V. Nederlandse Gasunie, the primary supplier and
transporter of natural gas in the Netherlands. The purchase price and
transportation costs for natural gas under these contracts are calculated on the
basis of regulated tariffs.
Our European Energy segment historically purchased all of its coal
requirements under short-term contracts with a coal trading and supply company
now owned by two of the Dutch generation companies. In December 2001, REPGB and
the other shareholder of the coal trading and supply company agreed to terminate
future coal purchases through this entity effective in mid-2002. Our European
Energy segment intends to obtain its future coal requirements through short to
medium-term forward purchase contracts on the open market through a variety of
suppliers and brokers.
17
One of our European Energy generation stations, which has a production
capacity of 144 MW, uses blast furnace gas, an industrial waste gas generated by
a steel plant adjacent to the generation station, as its fuel. Two of our other
European Energy segment's generation plants have the flexibility to operate
using blast furnace gas. We purchase the blast furnace gas from the adjacent
steel plant under a medium-term and a long-term contract. We purchase our fuel
oil requirements on the open market.
We acquired REPGB in October 1999 for approximately $1.9 billion (based on
the then applicable exchange rate of 2.06 Dutch Guilders (NLG) per U.S. dollar).
For information regarding the acquisition, please read note 5(b) to our
consolidated financial statements.
Market Framework. Our European Energy segment produces, buys and sells
electricity, gas and other energy-related commodities in the Northern European
wholesale market. Its generation production activities are centered in the
Netherlands, where it is one of the four large-scale generation companies. It
operates five generation facilities with an installed capacity of 3,476 MW. Its
energy trading and origination operations concentrate their activities primarily
in the Netherlands, Germany and the Scandinavian regions. In the fourth quarter
of 2001, our European Energy segment expanded its electricity trading operations
to the United Kingdom.
The primary customers of our European Energy segment are electric
distribution companies, large industrial consumers and energy trading companies.
We sell electricity and other energy-related commodities primarily in the form
of forward purchase contracts transacted in the over the counter markets, on
various European energy exchanges and in individually negotiated transactions
with individual counterparties. To a lesser extent, we also engage in
transactions involving financial energy-related derivative products.
The most significant factor affecting the markets in which our European
Energy segment operates has been the recent deregulation of the Dutch and
certain other European wholesale energy markets, including access on a
non-discriminatory basis to high voltage transmission grid systems, the
establishment of new energy exchanges and other events. Notwithstanding these
factors, the scope and pace of the future liberalization of the European energy
markets is uncertain. For example, access to some European markets continues to
be subject to transmission and other constraints. In some cases, fuel suppliers
continue to operate in largely regulated markets not yet open to full
competition.
EUROPEAN TRADING AND POWER ORIGINATION OPERATIONS
Our European Energy segment's trading and power origination operations are
centered in Amsterdam, Netherlands, with additional offices in London and
Frankfurt. Our European Energy segment trades electricity and fuel products in
the Netherlands, Germany, Austria, Switzerland, the United Kingdom and the
Scandinavian countries. Our marketing operations focus on distribution companies
and large industrial and commercial customers in the Benelux and German markets.
As of December 31, 2001, our European Energy segment had entered into forward
purchase and sale contracts, and associated hedging transactions, covering
approximately 18.6 million MWh for delivery in 2002.
Our European Energy segment's trading and power origination operations
seek to utilize a business model, including risk management and related control
policies, similar to that utilized in our Wholesale Energy operations in the
United States. There are, however, significant differences in the United States
and European markets. Among other things, European energy markets involve
increased currency hedging requirements (the Euro and non-Euro currencies), and
more complicated cross-border tax and transmission tariff systems than in the
United States. In addition, European energy markets are significantly less
mature than United States energy markets in terms of liquidity, the scope and
complexity of trading and marketing products, the use of standardized
market-based trading contracts and other aspects.
In addition, there exist greater uncertainties in some European
jurisdictions as to the enforceability of certain contract-based mechanisms to
hedge risks, such as the enforceability of automatic termination rights and
rights of set--off upon bankruptcy, limitations on liquidated damages and the
rules by which European courts construct contracts. In many civil law
jurisdictions, courts reserve the right to interpret contracts based upon
principles of good faith and fairness as opposed to a literal construction of
the contract
18
As of December 31, 2001, we had provided an aggregate of $831 million in
guarantees with respect to contract obligations of the European Energy segment.
COMPETITION
For a discussion of competitive factors affecting our European Energy
segment, please read "Management's Discussion and Analysis of Financial
Condition and Operations -- Certain Factors Affecting Our Future Earnings --
Factors Affecting the Results of Our European Energy Operations -- Competition
in the European Market" in Item 7 of this Form 10-K, which section is
incorporated herein by reference.
RETAIL ENERGY
We provide electricity and related services to retail customers primarily
in Texas through our wholly owned subsidiaries Reliant Energy Retail Services,
LLC (Residential Services), Reliant Energy Solutions, LLC (Solutions) and StarEn
Power, LLC (StarEn Power). As a retail electric provider, generally we procure
or buy electricity from wholesale generators at unregulated rates, sell
electricity at generally unregulated rates to our retail customers and pay the
local transmission and distribution regulated utilities a regulated tariff rate
for delivering the electricity to our customers. We became a provider of retail
electricity in Texas when that market began opening to retail competition in
late 2001 and fully opened to retail competition in January 2002. In January
2002, we began to provide retail electricity services to all of the
approximately 1.7 million customers of Reliant Energy's electric utility located
in its service area who did not take action to select another retail electric
provider. We provide electricity and related products and services to
residential and small commercial (i.e., small and medium-sized business
customers with a peak demand for power at or below one MW) customers through
Residential Services, and offer customized, integrated electric commodity and
energy management services to large commercial, industrial and institutional
(e.g., hospitals, universities, school systems and government agencies)
customers through Solutions for customers with a peak demand for power of
greater than one MW. Residential Services, Solutions and StarEn Power have been
certified as retail electric providers by the Texas Utility Commission. StarEn
Power has been appointed by the Texas Utility Commission to be the provider of
last resort (POLR) in certain areas of the State of Texas. Under the Texas
electric restructuring law, a POLR is required to offer a standard retail
electric service package to requesting customers of a class designated by the
Texas Utility Commission within the POLR's territory at a fixed, nondiscountable
rate.
In preparation for retail electric competition in Texas, we expanded our
infrastructure of information technology systems, business processes and
staffing levels 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, 2001, we had invested $153 million
in retail infrastructure development. For additional information regarding the
Texas retail electric market, please read "-- Market Framework," "-- Regulation
- -- Texas -- Retail Energy" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Retail Energy Operations
- -- Competition in the Texas Market" in Item 7 of this Form 10-K.
RESIDENTIAL SERVICES
Residential Services provides electricity to residential retail and small
commercial customers in Texas. As of January 1, 2002, Residential Services was
the retail electric provider for approximately 1.5 million residential customers
located in the Houston metropolitan area, making us the second largest retail
electric provider in Texas as of that date. Residential Services' marketing
strategy for residential customers emphasizes reliability and trust with our
customers, and focuses on savings, value and customer service. We launched an
advertising campaign to reposition our brand in the Houston and Dallas/Fort
Worth metropolitan areas in the second half of 2001.
As the affiliated retail electric provider, or successor in interest, to
Reliant Energy's electric utility, Residential Services was also the retail
electric provider for approximately 200,000 small commercial customers in the
Houston metropolitan area as of January 1, 2002. Residential Services' marketing
strategy for small commercial customers
19
uses a combination of direct marketing and individual sales calls to establish
our brand and to attract additional customers.
As the affiliated retail electric provider, Residential Services will not
be permitted to sell electricity to residential and small commercial customers
in Reliant Energy's electric utility service territory at a price other than a
fixed, specified price (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 the relevant class of customers in
the service territory is committed to be served by other retail electric
providers. In addition, the Texas electric restructuring law requires us, as the
affiliated retail electric provider, to make the price to beat available to
residential and small commercial customers in Reliant Energy's electric utility
service territory through January 1, 2007, if requested by such customers. For
more information about the price to beat, please read "-- Regulation -- Texas --
Retail Energy."
SOLUTIONS
Solutions provides electricity and energy services to large commercial,
industrial and institutional customers with whom it has signed contracts. In
addition, it provides electricity at previously established default rates to
those large commercial, industrial and institutional customers in the service
territory of Reliant Energy's electric utility who have not entered into a
contract with another retail electric provider. The majority of Solutions'
revenues will come from the sale of electricity to its customers. In order to be
classified as a large commercial customer, an electricity customer may aggregate
the purchase of electricity for its own use at multiple locations such that the
total peak demand exceeds one MW.
In addition to providing electricity, Solutions provides customized,
integrated energy solutions, including risk management and energy services
products, and demand side and energy information services to large commercial,
industrial and institutional customers. Since its formation in April 1996,
Solutions has completed over 220 energy services projects for large commercial,
industrial and institutional clients. The services that Solutions provides its
customers include the replacement or upgrade of energy-intensive capital
equipment, the financing of energy-intensive equipment, infrastructure
optimization, substation development and maintenance and power quality
assurance.
Solutions is recognized as the affiliated retail electric provider, or
successor in interest, to Reliant Energy's electric utility for large
commercial, industrial and institutional customers. Solutions targets
institutional, manufacturing, industrial and other large commercial customers,
including multisite retailers and restaurants, petroleum refineries, chemical
companies, real estate management firms, educational institutions and healthcare
providers. As of December 31, 2001, this customer segment in Texas included
approximately 1,750 buying organizations consuming an aggregate of approximately
16,000 MW of electricity at peak demand. As of December 31, 2001, Solutions had
signed contracts with customers representing a peak demand of approximately
3,700 MW and serving approximately 12,000 meter locations.
STAREN POWER
StarEn Power serves as the POLR in portions of the state of Texas, as
designated by the Texas Utility Commission. For 2002, StarEn Power has been
appointed to serve as the POLR for residential and small commercial customers in
the western portion of the Dallas/Fort Worth metropolitan area formally served
by TXU Electric Company. In addition, StarEn Power has been appointed as the
POLR in the service territory of Reliant Energy's electric utility for large
commercial, industrial and institutional customers. The rates and terms under
which StarEn Power provides service are governed by the terms of a settlement
agreement between StarEn Power and various interested parties approved by the
Texas Utility Commission. For additional information regarding our POLR
obligations, rates and terms of service, please read "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Retail
Energy Operations -- Obligations as a Provider of Last Resort" in Item 7 of this
Form 10-K.
20
MARKET FRAMEWORK
The Texas electric restructuring law substantially amended the regulatory
structure governing electric utilities in Texas in order to allow retail
competition, which fully began in January 2002. In order to prepare for the
opening of the retail market, a retail pilot project for up to 5% of each
utility's load in all customer classes began in August 2001. For information
regarding the retail market framework in Texas, please read "-- Regulation --
Texas -- Retail Energy" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Retail Energy Operations" in
Item 7 of this Form 10-K. Generally, under the Texas electric restructuring law,
the retail electric provider procures or buys electricity from wholesale
generators, sells electricity at retail to its customers and pays the
transmission and distribution utility a regulated tariffed rate for delivering
electricity to its customers. All retail electric providers in an area pay the
same rates and other charges for transmission and distribution, whether or not
they are affiliated with the transmission and distribution utility for that
area. The transmission and distribution rates in effect as of January 1, 2002
for each utility were set through rate cases before the Texas Utility
Commission.
RETAIL ENERGY SUPPLY
In Texas, our Wholesale Energy group and our Retail Energy group work
together in order to determine the price, demand and supply of energy required
to meet the needs of our Retail Energy segment's customers. Our Wholesale Energy
trading and marketing operations are responsible for commodity pricing, risk
assessment and supply procurement for our Retail Energy segment. Our Retail
Energy segment manages retail pricing decisions and forecasts the demand for the
procurement of electricity by the Wholesale Energy segment. The costs of our
trading, marketing and risk management services associated with obtaining the
electricity supply for our retail customers in Texas are borne by our Retail
Energy segment. Our Wholesale Energy group acquires supply for our Retail Energy
segment by several means. We may purchase capacity from non-affiliated parties
in the capacity auctions mandated by the Texas Utility Commission. Please read
"-- Regulation -- Texas -- Retail Energy" for more information about these
auctions. Under the terms of the Master Separation Agreement between Reliant
Resources and Reliant Energy, we may also participate in and purchase up to
approximately 50% of the remaining capacity of the generation facilities to be
owned by Texas Genco sold in auctions substantially similar to, but separate
from, the capacity auctions mandated by the Texas Utility Commission in which
15% of the total capacity of these facilities is required to be auctioned. In
addition, we have the right to purchase 50% (but not less than 50%) of the
remaining capacity of Texas Genco following the state mandated capacity auctions
at prices to be established in the aforementioned Texas Genco auctions. Please
read Notes 3 and 4(b) to our consolidated financial statements for a discussion
of our participation in these auctions. We also enter into bilateral contracts
with third parties for capacity, energy and ancillary services. We continuously
monitor and update these positions based on retail sales forecasts and market
conditions.
COMPETITION
For a discussion of competitive factors affecting our Retail Energy
segment, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Retail Energy Operations --
Competition in the Texas Market" in Item 7 of this Form 10-K, which section is
incorporated herein by reference.
OTHER OPERATIONS
For 2001, our Other Operations business segment included:
- the operations of our venture capital division (New Ventures),
- the operations of our communications business (Communications), and
- unallocated corporate costs.
21
NEW VENTURES
Our New Ventures division manages our existing new technology investments
and identifies and invests in promising new technologies and businesses that
relate to our energy services operations. Focus areas for investment include
distributed generation, clean energy and energy industry software and systems.
Generally, we make our investments either directly or indirectly as
limited partners in venture capital funds. As of December 31, 2001, we have
invested approximately $35 million in five venture capital funds with an energy
and utility focus and have made commitments to invest an additional $11 million
in these funds. As of December 31, 2001, 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 $7 million invested as of December 31, 2001.
In September 2000, we committed to make a $25 million investment in Grande
Communications, Inc., which was completed in August 2001. 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 invested
a further $1 million in Grande Communications in October 2001 as part of a
larger debt and equity financing for the company. 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 build out will
be in addition to the Central Texas cities of Austin, San Marcos, and San
Antonio which are already under development.
COMMUNICATIONS
During the third quarter of 2001, we decided to exit our Communications
business. The business served as a facility-based competitive local exchange
carrier and Internet services provider and owned network operations centers and
managed data centers in Houston and Austin. Our exit plan was substantially
completed in the first quarter of 2002. For more information regarding the
exiting of our Communication business, please read Note 16 to our consolidated
financial statements.
REGULATION
OVERVIEW
We are subject to regulation by various federal, state, local and foreign
governmental agencies, including the regulations described below.
FEDERAL ENERGY REGULATORY COMMISSION
Electricity. Under the Federal Power Act, the FERC has exclusive
rate-making 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 in
interstate commerce. All of our generation subsidiaries sell power at wholesale
and are public utilities under the Federal Power Act with the exception of two
facilities in Texas, which are qualifying facilities and not regulated as public
utilities. 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 such orders, reserve
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.
22
The FERC issued Order No. 2000 in December 1999. Order No. 2000, which
applies to all FERC jurisdictional transmission providers, describes the FERC's
intention to promote the establishment of large RTOs and sets forth the minimum
characteristics and functions of RTOs. Among the basic minimum characteristics
are that the RTOs must be independent of market participants 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 that operate as barriers to inter-regional transactions. The FERC's goal is
to encourage the growth of a robust competitive wholesale market for
electricity. Although jurisdictional transmission providers are not required to
join RTOs, they are encouraged to do so. Under Order No. 2000, RTOs were to be
operational by December 15, 2001. However, because RTO development was in
different stages in different regions of the country, the FERC issued an order
on November 7, 2001 extending the deadline until it resolves issues relating to
geographic scope and governance of qualifying RTOs across the country and issues
relating to business and procedural needs. For organizations to accomplish the
functions of Order No. 2000, the FERC is taking steps to create business
standards and protocols to facilitate RTO formation. However, there can be no
assurance that the FERC's goals will be achieved. Also there is considerable
state-level resistance in some regions, including regions in which we operate,
to the formation of RTOs. At least 14 separate organizations, covering the
substantial majority of all the FERC jurisdictional transmission providers, are
in various stages of organization and have made at least preliminary filings
with the FERC.
Trading and Marketing. Our domestic trading and marketing operations are
also subject to the FERC's jurisdiction under 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 Reliant
Energy's electric utility, 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 us and Reliant Energy's natural gas pipeline
subsidiaries to preclude any preferential treatment. Similar restrictions apply
to transactions between us and Reliant Energy's electric utility under Texas
utility regulatory laws.
Hydroelectric Facilities. The majority of our generating facilities
located in the state of New York are hydroelectric facilities, many of which are
subject to the FERC's exclusive authority under the Federal Power Act to license
non-federal hydroelectric projects located on navigable waterways and federal
lands. These FERC licenses must be renewed periodically and can include
conditions on operation of the project at issue.
TEXAS -- RETAIL ENERGY
In June 1999, Texas adopted the Texas electric restructuring law. The
Texas electric restructuring law substantially amended the regulatory structure
governing electric utilities in Texas. Full retail competition in the service
territories of some investor-owned electric utilities began in January 2002, and
in the territories of any municipally-owned utility and electric cooperative
that opts to open its market to retail competition. Under the Texas electric
restructuring law, the traditional, vertically-integrated utility is required to
separate its generation, transmission and distribution, and retail activities.
Unlike the vertically-integrated utility, which was subject to cost-of-service
rate regulation, the profit earned by retail electric providers will not be
subject to regulation, except for the price to beat requirement described below.
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 through retail electric providers. Wholesale
power generators will continue to sell electric energy to purchasers, including
retail electric providers, at unregulated rates. To facilitate a competitive
market, each power generator affiliated with a transmission and distribution
utility is required to sell at auction 15% of the output of its installed
generating capacity. This auction obligation continues until January 1, 2007,
unless the Texas Utility Commission determines before that date that at least
40% of the quantity of electric power consumed in 2000 by residential and small
commercial customers in the affiliated transmission and distribution utility's
service area is being served by retail electric providers not affiliated with
the incumbent utility. An affiliated retail electric provider may not purchase
capacity sold by its affiliated power generation company in the state mandated
capacity auctions.
23
The Texas electric restructuring law allows most retail electric customers
of Texas investor-owned electric utilities, and those of any municipally-owned
utility or electric cooperative that opts to open its market to retail
competition, to take action to select their retail electric provider for service
as of January 1, 2002. Retail electric providers which 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 traditional
service territory are subject to a fixed, specified price (price to beat) at the
outset of retail competition. The price to beat is subject to potential
adjustments up to two times per year, as described below. In December 2001, the
Texas Utility Commission established the price to beat we are required to charge
our residential and small commercial customers for electricity sales in the
Houston metropolitan area. Our price to beat was set at a level resulting in an
estimated 17% reduction to pre-existing rates for our residential customers and
an estimated 22% reduction to pre-existing rates for our small commercial
customers.
Municipally-owned utilities and electric cooperatives have the option to
open their markets to retail competition any time after January 1, 2002.
However, until a municipally-owned utility or electric cooperative adopts a
resolution opting to open its market to retail competition, it may not offer
electric energy at unregulated prices to retail customers outside its service
area. In November 2001, Nueces Electric Cooperative and San Patricio Electric
Cooperative received Texas Utility Commission approval of required filings
necessary to open their markets to retail competition. Some large Texas cities,
including San Antonio and Austin, are served by municipally-owned utilities that
have not announced when or if they will open their markets to competition.
New, unaffiliated retail electric providers that enter a particular market
may sell electricity to residential and small commercial customers at any price,
including a price below the price to beat. By allowing non-affiliated retail
electric providers to provide retail electric service to customers in an
electric utility's traditional service territory at any price, including a price
below the price to beat, the Texas electric restructuring law is designed to
encourage competition among retail electric providers. Affiliated retail
electric providers will not be permitted to sell electricity to residential and
small commercial customers in the transmission and distribution utility's
traditional service territory 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
the relevant class of customers in the certificated service area of the
affiliated transmission and distribution utility is committed to be served by
other retail electric providers. In addition, the Texas electric restructuring
law requires the affiliated retail electric provider to make the price to beat
available to residential and small commercial customers in the traditional
service area of the related incumbent utility through January 1, 2007. The price
to beat only applies to electric services provided to residential and small
commercial customers (i.e., customers with an aggregate peak demand at or below
one MW). Electric services provided to large commercial, industrial and
institutional customers (i.e., customers with an aggregate peak demand of
greater than one MW), whether by the affiliated retail electric provider or a
non-affiliated retail electric provider, may be provided at any negotiated
price.
The Texas Utility Commission's regulations allow an affiliated retail
electric provider to adjust the wholesale energy supply cost component or "fuel
factor," included in its price to beat based on a percentage change in the price
of natural gas. The fuel factor included in our price to beat was initially set
by the Texas Utility Commission at the then average forward 12 month gas price
strip of approximately $3.11/mmbtu. In addition, the affiliated retail electric
provider may also request an adjustment as a result of changes in its price of
purchased energy. In such a request, the affiliated retail electric provider may
adjust the fuel factor to the extent necessary to restore the amount of headroom
that existed at the time the initial price to beat fuel factor was set by the
Texas Utility Commission. An affiliated retail electric provider may request
that its price to beat be adjusted twice a year. Currently, we cannot estimate
with any certainty the magnitude and timing of the adjustments required, if any,
and the eventual impact of such adjustments on headroom. To the extent that the
adjustments are not received on a timely basis, our results of operations may be
adversely affected. Based on forward gas prices at the end of March 2002, we
estimate that we would be able to increase our price to beat by between
approximately 4% and 5%.
The Texas electric restructuring law 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
24
and distribution utility's traditional service territory is committed to be
served by other non-affiliated retail electric providers. If the 40% test is not
met, the reconciliation and credit will be in the form of a payment to Reliant
Energy, not to exceed $150 per customer. For additional information regarding
this payment, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Liquidity and Capital Resources --
Consolidated Capital Requirements and Uses of Cash -- Payment to Reliant Energy"
in Item 7 of this Form 10-K and Note 13(g) to our consolidated financial
statements.
The Texas electric restructuring law requires the Texas Utility Commission
to designate retail electric providers as POLR in areas of the state in which
retail competition is in effect. A POLR is required to offer a standard retail
electric service package for each class of customers designated by the Texas
Utility Commission at a fixed, nondiscountable 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 POLR. In the
event that another retail electric provider fails to serve any or all of its
customers, the POLR is required to offer that customer the standard retail
service package for that customer class with no interruption of service to the
customer. For additional information regarding our obligation as a POLR, and
regarding the Texas retail market framework in general, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Retail Energy Operations" in Item 7 of this Form 10-K.
SECURITIES AND EXCHANGE COMMISSION -- PUBLIC UTILITY HOLDING COMPANY ACT OF 1935
Under the Energy Policy Act of 1992, a company engaged exclusively in the
business of owning and/or operating facilities used for the generation of
electric energy exclusively for sale at wholesale and selling electric energy at
wholesale may be exempted from regulation under the Public Utility Holding
Company Act of 1935 (1935 Act) as an exempt wholesale generator (EWG).
Qualifying facilities, such as two of our projects in Texas, are similarly
exempt from regulation under the 1935 Act. Our electric generation facilities
have received determinations of EWG status from the FERC. If any of these
subsidiaries lose their EWG or qualifying facility status, we would have to
restructure our organization or risk being subjected to regulation under the
1935 Act.
Reliant Energy is both a holding company and an electric utility as
defined in the 1935 Act. However, Reliant Energy is exempt from regulation as a
holding company under Section 3(a)(2) of the 1935 Act.
REPGB is a foreign utility company exempt from regulation as a "public
utility company" under the 1935 Act. The Texas Utility Commission and the state
regulatory commissions of Arkansas and Minnesota have imposed limitations on the
amount of investments that Reliant Energy or its subsidiaries may invest in
foreign utility companies and, in some cases, foreign electric wholesale
generating companies. These limitations are based upon Reliant Energy's
consolidated net worth, retained earnings, and debt and stockholders' equity,
respectively. Subject to some limited exceptions, the 1935 Act also prohibits
any public utility 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 its business separation plan, Reliant Energy plans to
restructure its remaining businesses and to register as a public utility holding
company under the 1935 Act or to seek an exemption from the registration
requirements of the 1935 Act. If Reliant Energy becomes a registered public
utility holding company prior to the distribution of our common stock to its
shareholders, we will be subject to regulation as a "subsidiary company" under
the 1935 Act. As a result, we would be subject to limitations under the 1935 Act
related to, among other things, our acquisition, ownership and operation of
energy assets outside of our current business plan and payments of dividends by
us and our subsidiaries from unearned surplus. Additionally, we would need to
obtain approval under the 1935 Act prior to acquiring the voting securities of
any public utility or taking any other actions that would result in affiliation
with another public utility. Following the Distribution, we would no longer be
subject to the provisions of the 1935 Act either as a subsidiary or an affiliate
of Reliant Energy.
THE NETHERLANDS
Prior to the deregulation of the Dutch wholesale market in 2001, our
European Energy segment sold its generating output to a national production pool
and, in return, received a standardized remuneration.
25
The remuneration included fuel cost, return of and on capital and operation and
maintenance expenses. Under a transitional agreement which expired in 2000, the
non-fuel portion of this amount was fixed during the period 1997 through 2000.
For additional information, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our European Energy
Operations -- Competition in the European Market" and "-- Deregulation of the
Dutch Market" in Item 7 of this Form 10-K.
In 2001, the wholesale energy market of our European Energy segment's
primary market in the Netherlands was opened to competition. Our European Energy
segment continues to be subject to regulation by a number of national and
European regulatory agencies and regulations relating to the environment, labor,
tax and other matters. For example, our European Energy segment's operations are
subject to the regulation of Dutch and European Community anti-trust
authorities, who have extensive authority to investigate and prosecute
violations by energy companies of anti-monopolistic and price-fixing
regulations. In addition, our European Energy segment must also comply with
various national and regional grid codes and other regulations establishing
access to transmission systems. Many of the significant suppliers and customers
of our European Energy segment are subject to continued regulation by various
energy regulatory bodies that have the authority to establish tariffs for such
entities. The impact of regulations on these entities has an indirect impact on
our European Energy segment.
In some European countries, it is uncertain to what extent companies
trading in energy, fuel and other commodities (physical and financial) might be
deemed subject to regulation as brokers and dealers under local securities laws.
To the extent that its operations are deemed subject to these laws, our European
Energy segment could become subject to minimum capitalization, licensing and
reporting requirements similar to that which exists for securities broker and
dealer firms. Although our European Energy segment believes that its operations
are currently outside the scope of such regulations, no assurance can be given
as to the future positions of these regulatory agencies regarding the
applicability of these regulations to our European Energy segment's operations.
ENVIRONMENTAL MATTERS
GENERAL
We are subject to numerous 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 air, water, and soil, the proper
handling of solid, hazardous, and toxic materials and waste, noise, and safety
and health standards applicable to the workplace. In order to comply with these
requirements, we will spend substantial amounts from time to time to construct,
modify and retrofit equipment, acquire air emission allowances for operation of
our facilities, and to clean up or decommission disposal or fuel storage areas
and other locations as necessary. For the domestic and European operations we
owned as of December 31, 2001, we anticipate spending approximately $135 million
in capital and other special project expenditures between 2002 and 2006 for
environmental compliance. Additionally, environmental capital expenditures for
the recently acquired Orion Power assets were estimated by Orion Power to be
$241 million over the same time period. We are currently reviewing these
estimates.
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 upon us civil fines or
liabilities for property damage, personal injury and possibly other costs.
AIR EMISSIONS
As part of the 1990 amendments to the Federal Clean Air Act (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 the
United States.
26
Our REPGB facilities in the Netherlands were in compliance with applicable
Dutch NOx emission standards through the year 2001. New NOx reduction targets
have recently been adopted in the Netherlands which will require a 50% reduction
in NOx emissions from 2000 levels by 2010. The reductions may be achieved
through the installation of emission control equipment or through the
participation in a planned market-based emission trading system. We currently
believe that REPGB facilities will not be required to install NOx controls or
purchase emission credits until the 2005 through 2006 time period. Projected
emission control costs are estimated to be approximately $30 million, although
this investment may be offset to some extent or delayed if a market-based
trading program develops.
The Environmental Protection Agency (EPA) has announced its determination
to regulate hazardous air pollutants (HAPs), including mercury, 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 and may
adversely impact our results of operations. 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 (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. If the United States 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. We expect REPGB, through use of "green fuels"
and efficiency improvements, will be able 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 United States
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 have
received requests for information related to work activities conducted at those
sites, as have two of our recently acquired Orion Power facilities. The EPA has
not filed an enforcement action or initiated litigation in connection with these
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.
In February 2001, the United States Supreme Court upheld a previously
adopted EPA ambient air quality standards for fine particulate matter and ozone.
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.
Multi-pollutant air emission initiative. On February 14, 2002, the White
House announced its "Clear Skies Initiative." The proposal is aimed at long term
reductions of multiple pollutants produced from fossil fuel-fired power plants.
Reductions averaging 70% are targeted for Sulfur Dioxide (SO2), NOx, and
mercury. In addition, a voluntary program for greenhouse gas emissions is
proposed as an alternative to the Kyoto Protocol discussed above. The
implementation of the initiative, if approved by the United States Congress,
would be a market-based program, modeled after the Acid Rain Program, beginning
in 2008 and phased full compliance by 2018. Fossil fuel-fired power plants in
the United States would be affected by the adoption of this program, or other
legislation currently pending in the United States Congress addressing similar
issues. Such programs would require compliance to be achieved by the
installation of pollution controls, the purchase of emission allowances or
curtailment of operations.
27
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. Certain members of the United States Congress have
expressed concern to the EPA about the TMDL program and the EPA, in October
2001, extended the effective date of the regulation until April 2003.
In November 2001, the EPA promulgated rules that impose additional
technology based requirements on new cooling water intake structures. Draft
rules for existing intake structures have also been issued. It is not known at
this time what requirements the final rules for existing intake structures will
impose and whether our existing intake structures will require modification as a
result of such requirements. The process by which the intake structure rules
were written was a contentious one and litigation is expected. Court action in
response to this expected litigation could result in unforeseen changes in the
requirements.
A number of efforts are under way within the EPA to evaluate water quality
criteria for parameters associated with the by-products of 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.
LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATIONS
Under the purchase agreements between Sithe Energies and Reliant Energy
Power Generation, Inc. (REPG) relating to some of our Northeast regional
facilities, and in the transaction with Orion Power, we, with a few exceptions,
assumed liability for preexisting conditions, including some ongoing
remediations at the electric generating stations. Funds for carrying out any
identified actions have been included in our planning for future requirements,
and we are not currently aware of any environmental condition at any of our
facilities that we expect to have a material adverse effect on our financial
position, results of operation or cash flows.
A prior owner of one of our Northeast facilities entered into a Consent
Order Agreement with the Pennsylvania Department of Environmental Protection
(PaDEP) to remediate a coal refuse pile on the property of the facility. We
expect the remediation will cost between $10 million and $15 million. Under the
acquisition agreements between Sithe Energies and GPU, Inc. relating to some of
our Northeast regional facilities, GPU has agreed to retain responsibility for
up to $6 million of environmental liabilities associated with the coal refuse
site at this facility. We will be responsible for any amounts in excess of that
$6 million. In August 2000 we signed a modified consent order that committed us
to complete the remediation work no later than November 2004. In addition to the
coal refuse site at this facility, we had liabilities associated with six future
ash disposal site closures and six current site investigations and environmental
remediations. We expect to pay approximately $16 million over the next five
years to monitor and remediate these sites.
Under the New Jersey Industrial Site Recovery Act (ISRA), owners and
operators of industrial properties are responsible for performing all necessary
remediation at the facility prior to the closing of a facility and the
termination of operations, or undertaking actions that ensure that the property
will be remediated after the closing of a facility and the termination of
operations. In connection with the acquisition of our facilities from Sithe
Energies, we have agreed to take responsibility for any costs under ISRA
relating to the four New Jersey properties we purchased. We estimate that the
costs to fulfill our obligations under ISRA will be approximately $10 million.
However, these remedial activities are still in the early stage. Following
further investigation the scope of the necessary remedial work could increase,
and we could, as a result, incur greater costs.
One of our Florida generation facilities discharges wastewater to
percolation ponds which in turn, percolate into the groundwater. Elevated levels
of vanadium and sodium have been detected in groundwater monitoring wells. A
noncompliance letter has been received from the Florida Department of
Environmental Protection. A study to
28
evaluate the cause of the elevated constituents has been undertaken. At this
time, if remediation is required, the cost, if any, is not anticipated to be
material.
As a result of their age, many of our facilities contain significant
amounts of asbestos insulation, other asbestos containing materials, as well as
lead-based paint. Existing state and federal rules require the proper management
and disposal of these potentially toxic materials. We have developed a
management plan that includes proper maintenance of existing non-friable
asbestos installations, and removal and abatement of asbestos containing
materials where necessary because of maintenance, repairs, replacement or damage
to the asbestos itself. We have planned for the proper management, abatement and
disposal of asbestos and lead-based paint at our facilities in our financial
planning.
Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (CERCLA) owners and operators of facilities from which
there has been a release or threatened release of hazardous substances, together
with those who have transported or arranged for the disposal of those
substances, are liable for the costs of responding to that release or threatened
release, and the restoration of natural resources damaged by any such release.
We are not aware of any liabilities under CERCLA that would have a material
adverse effect on us, our financial position, results of operations or cash
flows.
EUROPEAN ENERGY
European and Dutch environmental laws are among the most stringent in the
industrial world. Under Dutch environmental laws, an environmental permit is
required to be maintained for each generation facility. As is customary in Dutch
practice, our European Energy segment has, together with other industry
participants entered into various contractual agreements with the national
government on specific environmental matters, including the reduction of the use
of coal and other fossil fuel. The environmental laws also address public
safety. We believe our European Energy segment holds all necessary
authorizations and approvals for its current operations.
The European Union, of which the Netherlands is a member, adopted the
Kyoto Protocol as the goal for greenhouse gas emission targets. For further
discussion of the protocol, please read "-- Air Emissions." We believe our
European Energy segment will meet its current portion of target reductions
because of its use of "green fuels" and efficiency improvements to its
facilities.
NOx reduction targets will require a 50 percent reduction in NOx emissions
from 2000 levels by 2010. The reductions may be achieved through the
installation of emission control equipment or through the participation in a
planned market-based emission trading system. Our European facilities are in
compliance with current and applicable Dutch NOx emission standards. Based on
current factors, we believe that our European facilities will not be required to
install NOx controls or purchase emission credits until the 2005-2006 time
period.
We estimate that we will spend approximately $30 million in emission
control and other environmental costs associated with our European Energy
segment for the period 2002 through 2006. In addition, we expect to spend
approximately $18 million in asbestos and other environmental remediation
programs during this period.
EMPLOYEES
As of December 31, 2001, we had 5,052 full-time employees. Of these
employees, 1,555 are covered by collective bargaining agreements. The collective
bargaining agreements expire on various dates until May 15, 2007. The following
table sets forth the number of our employees by business segment as of December
31, 2001.
SEGMENT NUMBER
- ------- ------
Wholesale Energy ............. 2,395
European Energy .............. 916
Retail Energy ................ 1,202
Other Operations ............. 539
-----
Total .............. 5,052
=====
29
EXECUTIVE OFFICERS
(AS OF MARCH 1, 2002)
NAME AGE PRESENT POSITION
- ---- --- ----------------
R. Steve Letbetter.............. 53 Chairman, President and Chief Executive Officer
Robert W. Harvey................ 46 Executive Vice President and Group President, Retail Businesses
Stephen W. Naeve................ 54 Executive Vice President and Chief Financial Officer
Joe Bob Perkins................. 41 Executive Vice President and Group President, Wholesale Businesses
Hugh Rice Kelly................. 59 Senior Vice President, General Counsel and Corporate Secretary
Mary P. Ricciardello............ 46 Senior Vice President and Chief Accounting Officer
R. STEVE LETBETTER is our Chairman, President and Chief Executive Officer.
Mr. Letbetter also serves as Chairman, President and Chief Executive Officer of
Reliant Energy. He has been Chairman of Reliant Energy since January 2000 and
President and Chief Executive Officer since June 1999. Since 1978, he has served
in various positions as an executive officer of Reliant Energy and its corporate
predecessors. Mr. Letbetter has been a director of Reliant Energy since 1995.
Mr. Letbetter will resign as President and Chief Executive Officer of Reliant
Energy at the time of the Distribution, but will continue to serve as
non-executive Chairman until 2004, subject to his re-election in 2001 as a
director by shareholders to a new three-year term and annually as Chairman by
the board of directors.
ROBERT W. HARVEY is our Executive Vice President and Group President,
Retail Businesses. Mr. Harvey has also served as Vice Chairman of Reliant Energy
since June 1999. From 1982 to 1999, Mr. Harvey was employed with the Houston
office of McKinsey & Co., Inc. He was a director (senior partner) and was the
leader of the firm's North American electric power and natural gas practice. Mr.
Harvey will resign as Vice Chairman of Reliant Energy at the time of the
Distribution.
STEPHEN W. NAEVE is our Executive Vice President and Chief Financial
Officer. He has also served as Vice Chairman of Reliant Energy since June 1999
and as Chief Financial Officer of Reliant Energy since 1997. From 1997 to 1999,
Mr. Naeve held the position of Executive Vice President and Chief Financial
Officer of Reliant Energy. Since 1988, he served in various executive officer
capacities with Reliant Energy, including Vice President -- Strategic Planning
and Administration between 1993 and 1996. Mr. Naeve will resign as Vice Chairman
and Chief Financial Officer of Reliant Energy at the time of the Distribution.
JOE BOB PERKINS is our Executive Vice President and Group President,
Wholesale Businesses. He served as President and Chief Operating Officer,
Reliant Energy Wholesale Group and as President and Chief Operating Officer of
Reliant Energy Power Generation, Inc. since 1998. In 1998, Mr. Perkins served as
President and Chief Operating Officer of the Reliant Energy Power Generation
Group. Between 1996 and 1998, he served as Vice President -- Corporate Planning
and Development.
HUGH RICE KELLY is our Senior Vice President, General Counsel and
Corporate Secretary. He has also 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. Mr. Kelly will resign as an officer of Reliant
Energy at the time of the Distribution.
MARY P. RICCIARDELLO is our Senior Vice President and Chief Accounting
Officer. She has also served as Chief Accounting Officer of Reliant Energy since
June 2000 and as Senior Vice President since 1999. She previously served as Vice
President and Comptroller of Reliant Energy from 1996 through 1999, and in
various executive officer capacities with Reliant Energy since 1993. Ms.
Ricciardello will resign as an officer of Reliant Energy at the time of the
Distribution.
30
ITEM 2. PROPERTIES.
CHARACTER OF OWNERSHIP
Our corporate offices currently occupy approximately 500,000 square feet
of leased office space in Houston, Texas, which lease expires in 2003, subject
to renewal options.
In addition to our corporate office space, we lease or own various real
property and facilities relating to our generation assets and development
activities. Our principal generation facilities are generally described under
"Our Business -- Wholesale Energy" and "Our Business -- European Energy --
European Power Generation Operations" in Item 1 of this Form 10-K. We believe we
have satisfactory title to our facilities in accordance with standards generally
accepted in the electric power industry, subject to exceptions which, in our
opinion, would not have a material adverse effect on the use or value of the
facilities.
WHOLESALE ENERGY
For information regarding the properties of our Wholesale Energy segment,
please read "Our Business -- Wholesale Energy" 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 segment,
please read "Our Business -- European Energy -- European Power Generation
Operations" in Item 1 of this Form 10-K, which information is incorporated
herein by reference.
RETAIL ENERGY
For information regarding the properties of our Retail Energy segment,
please read "Our Business -- Retail Energy" 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 segment,
please read "Our Business -- Other Operations" in Item 1 of this Form 10-K,
which information is incorporated herein by reference.
ITEM 3. LEGAL PROCEEDINGS.
For a description of certain legal and regulatory proceedings affecting
us, please read Notes 13(e), 13(i) and 17 to our consolidated financial
statements, which notes are incorporated herein by reference.
RESTATEMENT OF SECOND AND THIRD QUARTER 2001 RESULTS OF OPERATIONS
On February 5, 2002, we announced that we were restating our earnings for
the second and third quarters of 2001. As more fully described in our March 15,
2002 Current Report on Form 8-K, the restatement related to a correction in
accounting treatment for a series of four structured transactions that were
inappropriately accounted for as cash flow hedges for the period of May 2001
through September 2001, rather than as derivatives with changes in fair value
recognized through the income statement. Each structured transaction involved a
series of forward contracts to buy and sell an energy commodity in 2001 and to
buy and sell an energy commodity in 2002 or 2003.
At the time of the public announcement of our intention to restate our
reporting of the structured transactions, the Audit Committee of our Board of
Directors instructed us to conduct an internal audit review to determine whether
there were any other transactions included in the asset books as cash flow
hedges that failed to meet the cash flow hedge requirements under SFAS No. 133.
This targeted internal audit review found no other similar transactions.
31
The Audit Committee also directed an internal investigation by outside
legal counsel of the facts and circumstances leading to the restatement, which
investigation has been completed. In connection with the restatement and related
investigations, the Audit Committee has met eight times to hear and assess
reports from the investigative counsel regarding its investigation and contacts
with the Staff of the SEC. To address the issues identified in the investigation
process, the Audit Committee and management have begun analyzing and
implementing remedial actions, including, among other things, changes in
organizational structure and enhancement of internal controls and procedures.
On April 5, 2002, we were advised that the Staff of the Division of
Enforcement of the SEC is conducting an informal inquiry into the facts and
circumstances surrounding the restatement. We are cooperating with this inquiry.
Before releasing our 2001 earnings, we received concurrence from the SEC's
accounting staff on the accounting treatment of the restatement, which increased
our earnings for the two quarters by a total of $134 million. At this time, we
cannot predict the outcome of the SEC's inquiry. In addition, we cannot predict
what effect the inquiry may have on Reliant Energy's pending application to the
SEC under the 1935 Act, which is required for Reliant Energy's restructuring.
For more information about Reliant Energy's restructuring, please read "--
Formation, Initial Public Offering and Anticipated Distribution."
ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.
No matters were submitted to a vote of Reliant Resources' security holders
during the fourth quarter of the fiscal year ended December 31, 2001.
32
PART II
ITEM 5. MARKET FOR OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.
As of April 1, 2002, our common stock was held of record by approximately
41 stockholders of record and approximately 15,000 beneficial owners. Our common
stock is listed on the New York Stock Exchange and is traded under the symbol
"RRI."
We completed the initial public offering of our common stock in May 2001.
Our common stock began trading on the New York Stock Exchange on May 1, 2001.
The following table sets forth the high and low sales prices of our common stock
on the New York Stock Exchange composite tape during the periods indicated, as
reported by Bloomberg.
MARKET PRICE
----------------------
HIGH LOW
------ ------
2001
Second Quarter (from May 1 through June 30)
May 21 ..................................... $36.75
June 26 .................................... $24.48
Third Quarter
July 10 ..................................... $27.96
September 27 ................................ $15.75
Fourth Quarter
October 16 .................................. $19.65
December 17 ................................. $13.55
The closing market price of our common stock on December 31, 2001 was
$16.51 per share.
We have not paid or declared any dividends since our formation and
currently intend to retain earnings for use in our business. Any 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.
33
ITEM 6. SELECTED FINANCIAL DATA.
The following tables present our selected consolidated financial data. The
financial data set forth below for 1997, 1998, 1999 and 2000 are derived from
the consolidated historical financial statements of Reliant Energy. The data set
forth below should be read together with "Management's Discussion and Analysis
of Financial Condition and Results of Operations," our historical consolidated
financial statements and the notes to those statements included in this Form
10-K. The historical financial information may not be indicative of our future
performance and does not reflect what our financial position and results of
operations would have been had we operated as a separate, stand-alone entity
during the periods presented.
YEAR ENDED DECEMBER 31,
-----------------------------------------------------------------
1997(1) 1998(1) 1999(1) 2000(1) 2001(2)
------- ------- ------- -------- --------
(IN MILLIONS, EXCEPT PER SHARE INFORMATION)
INCOME STATEMENT DATA:
Revenues ..................................................... $ 1,321 $ 4,371 $ 7,956 $ 19,792 $ 36,546
Expenses:
Fuel and cost of gas sold ................................. 978 2,352 3,948 10,582 15,805
Purchased power ........................................... 313 1,824 3,729 7,852 18,734
Operation and maintenance ................................. 17 65 136 435 511
General, administrative and development ................... 20 78 100 291 487
Depreciation and amortization ............................. 2 15 29 194 247
------- ------- ------- -------- --------
Total ................................................... 1,330 4,334 7,942 19,354 35,784
------- ------- ------- -------- --------
Operating (Loss) Income ...................................... (9) 37 14 438 762
Other (Expense) Income:
Interest expense .......................................... (1) (2) (9) (42) (63)
Interest income ........................................... -- 1 -- 18 27
Interest income (expense) -- affiliated
companies, net ......................................... 2 2 (10) (172) 12
Gains (losses) from investments ........................... -- -- 16 (17) 22
(Loss) income of equity investments of
unconsolidated subsidiaries ............................ -- (1) 21 43 57
Gain on sale of development project ....................... -- -- -- 18 --
Other, net ................................................ -- 1 (6) 5 9
------- ------- ------- -------- --------
Total Other Income (Expense) ............................ 1 1 12 (147) 64
------- ------- ------- -------- --------
(Loss) Income Before Income Taxes, Extraordinary Item
and Cumulative Effect of Accounting Change ................ (8) 38 26 291 826
Income Tax Benefit (Expense) ................................. 2 (17) (2) (88) (272)
------- ------- ------- -------- --------
(Loss) Income Before Extraordinary Item and Cumulative
Effect of Accounting Change ............................... (6) 21 24 203 554
Extraordinary Item, net of tax ............................... -- -- -- 7 --
Cumulative effect of accounting change, net of tax ........... -- -- -- -- 3
------- ------- ------- -------- --------
Net (Loss) Income ............................................ $ (6) $ 21 $ 24 $ 210 $ 557
======= ======= ======= ======== ========
BASIC AND DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change ...... $ 2.00
Cumulative effect of accounting change, net of tax ........ 0.01
--------
Net income ................................................... $ 2.01
========
34
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------
1997(1) 1998(1) 1999(1) 2000(1) 2001(2)
------- ------- ------- ------- -------
(IN MILLIONS, EXCEPT OPERATING DATA)
STATEMENT OF CASH FLOW DATA:
Cash Flows From Operating Activities ............. $ (22) $ (2) $ 35 $ 328 $ (127)
Cash Flows From Investing Activities ............. (4) (365) (1,406) (3,013) (838)
Cash Flows From Financing Activities ............. 26 379 1,408 2,721 1,000
OTHER OPERATING DATA:
Net Power Generation Capacity (MW) ............... -- 3,800 7,945 12,707 14,585
Domestic Wholesale Power Sales (MMWh)(3) ......... 12 65 112 202 380
Domestic Natural Gas Sales (Bcf)(4) .............. 366 1,115 1,746 2,423 3,695
European Power Sales (MMWh) ...................... -- -- 3 13 42
DECEMBER 31,
-------------------------------------------------------------
1997 1998 1999 2000 2001
------- ------- ------- ------- -------
(IN MILLIONS)
BALANCE SHEET DATA:
Property, Plant and Equipment, net ............... $ 5 $ 270 $ 2,407 $ 4,049 $ 4,602
Total Assets ..................................... 822 1,409 5,624 13,214 12,254
Short-term Borrowings ............................ -- -- 170 126 297
Long-term Debt to Third Parties, including
current maturities ............................ -- -- 460 892 892
Accounts and Notes Receivable (Payable) --
Affiliated Companies, net ..................... 45 (17) (1,333) (1,969) 445
Stockholders' Equity ............................. 291 652 741 2,332 6,104
- ----------
(1) Our results of operations include the results of the following
acquisitions, all of which were accounted for using the purchase method of
accounting, from their respective acquisition dates: Reliant Energy
Services, Inc. and Arkla Finance Corporation acquired in August 1997, the
five generating facilities in California substantially acquired in April
1998, a generating facility in Florida and REPGB both acquired in October
1999 and the REMA acquisition that occurred in May 2000. Please read Note
5 to our consolidated financial statements for further information about
these acquisitions.
(2) Effective January 1, 2001, we adopted Statement of Financial Accounting
Standards (SFAS) No. 133, "Accounting for Derivative Instruments and
Hedging Activities" as amended (SFAS No. 133), which established
accounting and reporting standards for derivative instruments. Please read
Note 6 to our consolidated financial statements for further information
regarding the impact of the adoption of SFAS No. 133.
(3) Million megawatt hours.
(4) Billion cubic feet.
35
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 and notes to those statements included in
Item 8 of this Form 10-K.
OVERVIEW
We provide electricity and energy services with a focus on the competitive
wholesale and retail segments of the electric power industry in the United
States. We acquire, develop and operate electric power generating facilities
that are not subject to traditional cost-based regulation and therefore can
generally 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.
In this section we discuss our results of operations on a consolidated
basis and on a segment basis for each of our financial reporting segments. Our
segments include Wholesale Energy, European Energy, Retail Energy and Other
Operations. For segment reporting information, please read Note 18 to our
consolidated financial statements.
OUR SEPARATION FROM RELIANT ENERGY, INCORPORATED
In connection with our anticipated separation from Reliant Energy,
Incorporated (Reliant Energy), Reliant Energy contributed to us effective
December 31, 2000, our wholesale, retail and other operations. Through December
31, 2000, these operations were conducted by Reliant Energy and its direct and
indirect subsidiaries. These operations consist of the following:
- non-rate regulated power generation assets and related energy
trading, marketing, power origination and risk management operations
in North America and Northwest Europe,
- retail electric operations, and
- other operations, including venture capital and Communications
businesses.
For additional information regarding agreements with Reliant Energy
entered into as a part of Reliant Energy's business separation plan, please read
Note 4 to our consolidated financial statements.
The financial information for the years ended December 31, 1999 and 2000
discussed in this section is derived from the consolidated historical financial
statements of Reliant Energy, which include the results of operations for all of
Reliant Energy's businesses, including those businesses which we do not own. In
order to prepare our financial statements for 1999 and 2000, contained in this
Form 10-K and discussed in this section, we carved-out the results of operations
of the businesses that we own from Reliant Energy's consolidated historical
financial statements. Accordingly, the results of operations discussed in this
section for such years include only revenues and costs directly attributable to
the businesses we own and operate. Some of these costs are for facilities and
services provided by Reliant Energy and for which our operations have
historically been charged based on usage or other allocation factors. We believe
these allocations are reasonable, but they are not necessarily indicative of the
expenses that would have resulted if we had actually operated independently of
Reliant Energy. We may experience changes in our cost structure, funding and
operations as a result of our anticipated separation from Reliant Energy,
including increased costs associated with reduced economies of scale, and
increased costs associated with being a publicly traded, independent company. We
cannot currently predict with any certainty the actual amount of increased costs
we may incur, if any.
In May 2001, we offered 59.8 million shares of our common stock to the
public at an initial public offering (IPO) price of $30 per share and received
net proceeds of $1.7 billion. Pursuant to the master separation agreement with
Reliant Energy (Master Separation Agreement), we used $147 million of the net
proceeds to repay certain indebtedness owed to Reliant Energy. Reliant Energy
has publicly disclosed that it expects to distribute (Distribution) the
remaining Reliant Resources common stock that it owns to its or its successor's
shareholders in the summer of 2002. The Distribution is subject to the
declaration of the Distribution by the Board of Directors of
36
Reliant Energy, market and other conditions and government actions and
approvals. We cannot assure you that the Distribution will be completed as
described or within the time period outlined above.
CONSOLIDATED RESULTS OF OPERATIONS
The following table provides summary data regarding our consolidated
results of operations for 1999, 2000 and 2001.
YEAR ENDED DECEMBER 31,
-----------------------------------
1999 2000 2001
-------- -------- -------
(IN MILLIONS)
Revenues ................................................. $7,956 $ 19,792 $36,546
Operating Expenses ....................................... 7,942 19,354 35,784
------ -------- -------
Operating Income ......................................... 14 438 762
Other Income (Expense), net .............................. 12 (147) 64
Income Tax Expense ....................................... 2 88 272
------ -------- -------
Income Before Extraordinary Gain and Cumulative
Effect of Accounting Change ........................... 24 203 554
Extraordinary Gain ....................................... -- 7 --
Cumulative Effect of Accounting Change, net of tax ....... -- -- 3
------ -------- -------
Net Income ............................................... $ 24 $ 210 $ 557
====== ======== =======
2001 COMPARED TO 2000
Net Income. We reported consolidated net income of $557 million, or $2.01
earnings per share, for 2001 compared to $210 million for 2000. The 2001 results
included a cumulative effect of accounting change of $3 million, net of tax,
related to the adoption of Statement of Financial Accounting Standards (SFAS)
No. 133 "Accounting for Derivative Instruments and Hedging Activities," as
amended. For additional discussion of the adoption of SFAS No. 133, please read
Note 6 to our consolidated financial statements. The 2000 results included an
extraordinary gain of $7 million related to the early extinguishment of $272
million of long-term debt. For additional discussion of the extraordinary gain,
please read Note 8(b) to our consolidated financial statements. Our consolidated
net income, before cumulative effect of accounting change, was $554 million for
2001 compared to consolidated net income, before extraordinary gain, of $203
million for 2000. The increase of $351 million was primarily due to the
following:
- a $674 million increase in gross margins (revenues less fuel and
cost of gas sold and purchased power) from our Wholesale Energy
segment, excluding the impact of a $68 million provision related to
energy sales to Enron Corp. and its affiliates (Enron) which filed a
voluntary petition for bankruptcy during the fourth quarter of 2001;
- a $57 million decrease in operating losses from our Retail Energy
segment;
- a $37 million net gain resulting from the settlement of an indemnity
agreement related to certain energy obligations entered into in
connection with our acquisition of Reliant Energy Power Generation
Benelux N.V. (REPGB), formerly N.V. UNA;
- a $51 million gain recorded in equity income in 2001 related to a
preacquisition contingency for the value of NEA B.V. (NEA), the
coordinating body for the Dutch electricity generating sector, which
is an equity investment in which REPGB holds a 22.5% economic
interest;
- a $184 million decrease in net interest expense related to debt with
affiliated companies; and
- a $27 million pre-tax impairment loss on marketable equity
securities classified as "available-for-sale" in 2000.
37
The above items were partially offset by:
- a $66 million decrease in European Energy's gross margins, primarily
attributable to the Dutch wholesale electric market opening to
competition on January 1, 2001, excluding the impact of a $17
million provision related to energy sales to Enron recorded in the
fourth quarter of 2001;
- a $100 million pre-tax, non-cash charge relating to the redesign of
some of Reliant Energy's benefit plans in anticipation of our
separation from Reliant Energy;
- an $85 million pre-tax provision related to energy sales to Enron
which was recorded in the fourth quarter of 2001;
- $54 million in pre-tax disposal charges and impairments of goodwill
and fixed assets related to the exiting of our Communications
business;
- a $37 million decrease in our Wholesale Energy segment's equity
earnings of unconsolidated subsidiaries in 2001 as compared to 2000;
and
- an $18 million pre-tax gain in 2000 on the sale of our interest in
one of our development-stage electric generation projects.
Operating Income. For an explanation of changes in our operating income
and margins, please read the discussion below of operating income (loss) by
segment.
Other Income/Expense. We incurred net other income of $64 million during
2001 compared to net other expense of $147 million in 2000. The increase in
other income of $211 million in 2001 as compared to 2000 resulted primarily from
the following:
- a $184 million decrease in interest expense on debt owed to
affiliated companies;
- a $51 million gain recorded in equity income with respect to our
equity investment in NEA;
- a $27 million pre-tax impairment loss on marketable equity
securities classified as "available-for-sale" in 2000;
- a $12 million net increase in holding gains from investments in
2001, including an $18 million increase in realized holding gains
from equity and debt securities and a $1 million increase in
unrealized holding gains from equity and debt securities partially
offset by (a) a decrease of $1 million in realized gains by our
Other Operations segment resulting from reduced cash distributions
from venture capital investments, (b) a $2 million impairment of
investments and (c) a $4 million decrease in foreign exchange gains
on financial instruments; and
- a $9 million increase in interest income in 2001 earned by our
European Energy segment related to interest receivable on our claims
pursuant to an indemnity for certain energy obligations and the
related settlement and by our Wholesale Energy segment on restricted
deposits related to our energy trading activities and on collateral
related to electric generation equipment.
The $184 million decrease in interest expense on debt owed to affiliated
companies, net of interest expense capitalized on projects, in 2001 as compared
to 2000 is primarily due to the following:
- the conversion into equity of $1.7 billion of debt owed to Reliant
Energy and its subsidiaries in connection with the completion of the
IPO in May 2001;
38
- the repayment in August 2000 of $1.0 billion of debt owed to Reliant
Energy related to our Mid-Atlantic acquisition, which is included in
our Northeast region operations, from proceeds received from the
generating facilities' sale-leaseback transactions; and
- the advancing of excess cash primarily resulting from the IPO to a
subsidiary of Reliant Energy.
The increase in other income noted above was partially offset by:
- a $21 million increase in interest expense to third parties, net of
interest expense capitalized on projects, primarily as a result of
higher levels of borrowings related to construction of power
generation facilities and credit facility fees;
- an $18 million pre-tax gain in 2000 on the sale of our interest in
one of our development-stage electric generation projects; and
- a $37 million decrease in our Wholesale Energy segment's equity
earnings of unconsolidated subsidiaries in 2001 as compared to 2000.
Our Wholesale Energy segment reported income from equity investments in
2001 of $6 million compared to $43 million in 2000. The equity income in both
years primarily resulted from an investment in an electric generation plant in
Boulder City, Nevada. The plant became operational in May 2000. The equity
income related to our investment in the plant declined in 2001 from 2000
primarily due to higher plant outages in 2001 and reduced power prices realized
by the project company.
During the second quarter of 2001, we recorded a $51 million gain as
equity income for the preacquisition gain contingency related to the acquisition
of REPGB for the value of its equity investment in NEA. This gain was based on
our evaluation of NEA's financial position and fair value. Pursuant to the
purchase agreement of REPGB, as amended, REPGB was entitled to a $51 million
(NLG 125 million) dividend from NEA with any remainder owed to the former
shareholders of REPGB. In December 2001, REPGB entered into a settlement
agreement resolving its former shareholders' stranded cost indemnity
obligations. Under the settlement agreement, the former shareholders waived all
rights to claim distributions from NEA. For further information regarding the
settlement agreement, please read the European Energy segment's operating income
analysis below and Note 13(f) 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 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 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.
During 2001, we recognized a pre-tax gain of $14 million from the sale of a
portion of this investment. For additional discussion of this investment, please
read Note 2(m) to our consolidated financial statements.
Income Tax Expense. We calculate our income tax provision on a separate
return basis under a tax sharing agreement with Reliant Energy. Our deferred
income taxes are calculated using the liability method of accounting, which
measures deferred income taxes for all significant income tax temporary
differences. Our current federal and some state income taxes are payable to or
receivable from Reliant Energy. Our federal statutory tax rate is 35%. During
2001 and 2000, our effective tax rate was 32.9% and 30.4%, respectively. Our
reconciling items from the federal statutory tax rate to the effective tax rate
totaled $18 million and $13 million for 2001 and 2000, respectively. These items
primarily related to a tax holiday for income earned by REPGB and were partially
offset by nondeductible goodwill, state income taxes and valuation allowances.
In 2001 and prior years, under Dutch corporate income tax laws, the earnings of
REPGB were subject to a zero percent Dutch corporate income tax rate as a result
of the Dutch tax holiday applicable to its 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 34.5%.
39
Subsequent to the Distribution, we will cease to be a member of the
Reliant Energy consolidated tax group. This separation could have future income
tax implications for us. Our separation from the Reliant Energy consolidated tax
group will change our overall future income tax posture. As a result, we could
be limited in our future ability to effectively use future tax attributes. We
have agreed with Reliant Energy that we may carry back net operating losses we
generate in our tax years after deconsolidation to tax years when we were part
of the Reliant Energy consolidated tax group subject to Reliant Energy's consent
and any existing statutory carryback limitations. Reliant Energy has agreed not
to unreasonably withhold such consent.
As discussed in Note 13(f) to our consolidated financial statements, the
Dutch parliament has adopted legislation allocating to the Dutch generation
sector, including REPGB, financial responsibility for certain stranded costs and
other liabilities incurred by NEA prior to the deregulation of the Dutch
wholesale market. These obligations include NEA's obligations under an
out-of-market gas supply contract and three out-of-market electricity contracts.
REPGB's allocated share of these liabilities is 22.5%. As a result, we recorded
a net stranded cost liability of $369 million and a related deferred tax asset
of $127 million at December 31, 2001 for our statutorily allocated share of
these gas supply and electricity contracts. We believe that the costs incurred
by REPGB subsequent to the tax holiday ending in 2001 related to these contracts
will be deductible for Dutch tax purposes. However, due to uncertainties related
to the deductibility of these costs, we have recorded an offsetting liability in
other liabilities in our consolidated financial statements of $127 million as of
December 31, 2001.
2000 COMPARED TO 1999
Net Income. We reported consolidated net income of $210 million for 2000
compared to consolidated net income of $24 million for 1999. The 2000 results
included an extraordinary gain of $7 million related to the early extinguishment
of $272 million of long-term debt, which gain is further described in Note 8(b)
to our consolidated financial statements.
Our consolidated net income, before the extraordinary gain, was $203
million for 2000 compared to consolidated net income of $24 million for 1999.
The $179 million increase in 2000 compared to 1999 was primarily due to
increased earnings from our Wholesale Energy segment, the inclusion of earnings
from the Mid-Atlantic generating assets, which our Wholesale Energy segment
acquired in May 2000, and the inclusion of earnings from our European Energy
segment, which was established in the fourth quarter of 1999 with the
acquisition of REPGB. The Mid-Atlantic generating assets and European Energy
segment contributed $212 million and $84 million, respectively, to operating
income for 2000. For additional information on the acquisition of the
Mid-Atlantic generating assets and REPGB, please read Notes 5(a) and 5(b) to our
consolidated financial statements. The increases in 2000 earnings compared to
1999 earnings from our Wholesale Energy and European Energy segments were
partially offset by increased losses from our Retail Energy and Other Operations
segments over the same period.
Operating Income. For an explanation of changes in our operating income,
please read the discussion below of operating income (loss) by segment.
Other Income/Expense. We incurred net other expense of $147 million for
2000 compared to net other income of $12 million for 1999. The increase in
expense of $159 million in 2000 as compared to 1999 resulted primarily from a
pre-tax impairment loss of $27 million on marketable equity securities
classified as "available-for-sale" incurred in 2000 by Other Operations,
increased net interest expense on obligations to Reliant Energy and its
subsidiaries of $162 million and increased interest expense on obligations to
third parties of $33 million, each net of interest capitalized on construction
projects. Increased interest expense resulted primarily from higher levels of
debt during 2000 compared to 1999. Increased debt levels were primarily
associated with borrowings for the funding of the acquisition of REPGB in the
fourth quarter of 1999 and the first quarter of 2000, the acquisition of our
Mid-Atlantic generating facilities in the second quarter of 2000, capital
expenditures and increased margin deposits on energy trading and hedging
activities. In 2000, we had a decrease of $12 million in unrealized holding
gains from debt and equity securities classified as "trading," a $3 million
increase in foreign exchange gains on financial instruments and a $3 million
increase in realized gains by our Other Operations segment primarily as a result
of increased cash distributions from venture capital investments.
40
The increased net other expense noted above was partially offset by:
- an $18 million pre-tax gain in 2000 on the sale of our interest in
one of our development-stage electric generation projects,
- a $18 million increase in interest income in 2000 earned on
increased deposits primarily related to our Wholesale Energy
segment,
- a $22 million increase in equity earnings in unconsolidated
subsidiaries in 2000, and
- a $7 million option premium expense recorded in 1999 to economically
hedge foreign currency risks for our REPGB purchase obligation.
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. In
1999, we recorded $22 million in equity income related to REPGB for the period
from October 1, 1999 through November 30, 1999. For additional information about
the REPGB acquisition, including our accounting treatment, please read Note 5(b)
to our consolidated financial statements.
Income Tax Expense. During 2000 and 1999, our effective tax rate was 30.4%
and 9.6%, respectively. Our reconciling items from the federal statutory tax
rate to the effective tax rate totaled $13 million for 2000. These items
primarily related to a tax holiday for income earned by REPGB and were partially
offset by nondeductible goodwill, state income taxes and valuation allowances.
Our reconciling items from the federal statutory tax rate to the effective tax
rate totaled $7 million for 1999. These items primarily related to income earned
by REPGB and were partially offset by nondeductible goodwill and valuation
allowances.
RESULTS OF OPERATIONS BY BUSINESS SEGMENT
The following table presents operating income (loss) for each of our
business segments for 1999, 2000 and 2001.
OPERATING INCOME (LOSS) BY BUSINESS SEGMENT
----------------------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------------------
1999 2000 2001
---- ----- -----
(IN MILLIONS)
Wholesale Energy ............... $ 19 $ 485 $ 899
European Energy ................ 12 84 56
Retail Energy .................. (13) (70) (13)
Other Operations ............... (4) (61) (180)
---- ----- -----
Total Consolidated ........ $ 14 $ 438 $ 762
==== ===== =====
WHOLESALE ENERGY
Our Wholesale Energy segment includes our non-rate regulated power
generation operations in the United States and our wholesale energy trading,
marketing, origination and risk management operations in North America.
As of December 31, 2001, we owned or leased electric power generation
facilities with an aggregate net generating capacity of 11,109 megawatts (MW) in
the United States. We acquired our first power generation facility in April
1998, and have increased our aggregate net generating capacity since that time
principally through acquisitions, as well as contractual agreements and the
development of new generating projects. As of December 31, 2001, we had 3,587 MW
of additional net generating capacity under construction, including facilities
having 2,120 MW that are being constructed under a construction agency agreement
by off-balance sheet special purpose entities. We consider a project to be
"under construction" once we have acquired the necessary permits to begin
construction, broken ground on the project site and contracted to purchase
machinery for the project, including the combustion turbines. 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
41
of approximately 4,262 MW. For additional information regarding this acquisition
of our Mid-Atlantic generating assets completed in May 2000 by Wholesale Energy,
including the accounting treatment of this acquisition, please read Note 5(a) to
our consolidated financial statements.
On February 19, 2002, we acquired all of the outstanding shares of common
stock of Orion Power Holdings, Inc. (Orion Power) for $26.80 per share in cash
for an aggregate purchase price of $2.9 billion. As of February 19, 2002, Orion
Power's debt obligations were $2.4 billion ($2.1 billion net of cash acquired,
some of which is restricted pursuant to debt covenants). Orion Power is an
independent electric power generating company that was formed in March 1998 to
acquire, develop, own and operate power-generating facilities in certain
deregulated wholesale markets in North America. As of February 28, 2002, Orion
Power had 81 power plants in operation with a total generating capacity of 5,644
MW and an additional 804 MW under construction or in various stages of
development.
For a discussion of the factors that may affect the future results of
operations of Wholesale Energy, please read "-- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations."
The following table provides summary data regarding the results of
operations of Wholesale Energy for 1999, 2000 and 2001.
WHOLESALE ENERGY
--------------------------------------
YEAR ENDED DECEMBER 31,
--------------------------------------
1999 2000 2001
------ ------- -------
(IN MILLIONS, EXCEPT OPERATING DATA)
Operating Revenues .................................... $7,866 $19,142 $35,158
Operating Expenses:
Fuel and cost of gas sold .......................... 3,924 10,322 15,405
Purchased power .................................... 3,729 7,818 18,145
Operation and maintenance .......................... 92 237 349
General, administrative and development ............ 81 172 242
Depreciation and amortization ...................... 21 108 118
------ ------- -------
Total Operating Expenses ...................... $7,847 $18,657 $34,259
------ ------- -------
Operating Income ...................................... $ 19 $ 485 $ 899
====== ======= =======
Operating Data:
Net Generation Capacity (MW) ....................... 4,469 9,231 11,109
Electricity Wholesale Power Sales (MMWh)(1) ........ 112 202 380
Natural Gas Sales (Bcf)(2) ......................... 1,746 2,423 3,695
- ----------
(1) Million megawatt hours.
(2) Billion cubic feet.
2001 Compared to 2000. Wholesale Energy's operating income increased by
$414 million in 2001 compared to 2000. The results for 2001 include a $68
million provision against net receivables, trading and marketing assets and
non-trading derivative balances related to Enron, and a $29 million provision
and a $12 million net write-off against receivable balances related to energy
sales in California. A $39 million provision against receivable balances related
to energy sales in California was recorded in 2000.
The increase in operating income was primarily due to increased gross
margins. Gross margins for Wholesale Energy increased by $606 million primarily
due to increased volumes on power sales from our generation facilities,
increased volumes from our trading and marketing activities and the addition of
our Mid-Atlantic assets and strong commercial and operational performance in
other regions. Margins on power sales from our generation facilities, excluding
a $63 million provision related to Enron, increased by $429 million in the West
region (Arizona, California and portions of New Mexico and Nevada), $85 million
in the Mid-Atlantic region, and $32 million in other regions in 2001 compared to
2000. Favorable market conditions in the first six months of 2001 in the West
region resulting from a combination of factors, including reduction in available
hydroelectric generation resources, increased demand and decreased electric
imports, positively impacted Wholesale Energy's operating margins.
42
These favorable market conditions did not exist in the second half of 2001, and
we do not expect them to return in 2002. Trading and marketing gross margins,
excluding a $5 million provision related to Enron, increased $113 million from
$197 million in 2000 to $310 million in 2001 primarily as a result of increased
natural gas trading volumes. These results were partially offset by the $68
million provision related to Enron as discussed above, higher operation and
maintenance expenses from facilities in the Mid-Atlantic region acquired in
2000, higher general and administrative expenses and increased depreciation
expense.
The following table provides further summary data regarding gross margin
by commodity of Wholesale Energy for 2000 and 2001.
YEAR ENDED DECEMBER 31,
------------------------
2000 2001
------- --------
(IN MILLIONS)
Gas revenues ................................ $ 9,353 $ 14,370
Power revenues .............................. 9,709 20,776
Other commodity revenues .................... 80 80
Credit provision related to Enron ........... -- (68)
------- --------
Total revenues ........................... 19,142 35,158
------- --------
Cost of gas sold ............................ 9,240 14,142
Fuel and purchased power .................... 8,813 19,344
Other commodity costs ....................... 87 64
------- --------
Total cost of sales ....................... 18,140 33,550
------- --------
Gross margin ............................. $ 1,002 $ 1,608
======= ========
Wholesale Energy's revenues increased by $16.0 billion (84%) in 2001
compared to 2000. The increased revenues were primarily due to increased volumes
for natural gas (approximately $5.4 billion) and power sales (approximately $8.6
billion) and to a lesser extent increased prices for power sales compared to
2000, which increased approximately $2.5 billion. Wholesale Energy's fuel and
cost of gas sold and purchased power increased by $15.4 billion in 2001 compared
to 2000, largely due to increased volumes for natural gas and power sales and to
a lesser extent increases in power generation plant output, which increased
approximately 33% compared to 2000, and increased prices for power purchases.
Operation and maintenance expenses for Wholesale Energy increased $112
million in 2001 compared to the same period in 2000, primarily due to costs
associated with the operation and maintenance of generating plants acquired in
the Mid-Atlantic region of $53 million and higher lease expense of $38 million
associated with the Mid-Atlantic generation facilities' sale-leaseback
transactions that were entered into in August 2000. The higher lease expense
associated with the Mid-Atlantic generating facilities was offset by lower
interest expense in the consolidated results of operations in 2001 compared to
2000. General, administrative and development expenses increased $70 million in
2001 compared to 2000, primarily due to higher administrative costs to support
growing wholesale commercial activities of $69 million and higher legal and
regulatory expenses related to the West region of $25 million, partially offset
by decreased development expenses of $12 million. Depreciation and amortization
expense increased by $10 million in 2001 compared to 2000 primarily as a result
of higher expense related to the depreciation of our Mid-Atlantic plants, which
were acquired in May 2000, and other generating plants placed into service
during 2001, partially offset by a decrease in amortization of our air emissions
regulatory allowances of $8 million.
2000 Compared to 1999. Wholesale Energy's operating income increased $466
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 generation operations into regions other than the Western
United States, including the Mid-Atlantic United States, Florida and Texas.
Wholesale Energy'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 compared to 1999. Wholesale
Energy's 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
43
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
and general, administrative and development expenses increased $145 million and
$91 million, respectively, in 2000 compared to 1999. These increases were
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 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 $87 million as compared to 1999, primarily as a
result of our acquisition of the Mid-Atlantic generating facilities and other
generating facilities in 2000.
EUROPEAN ENERGY
Our European Energy segment includes the operations of REPGB and its
subsidiaries and our European trading and power origination operations. We
created European Energy in the fourth quarter of 1999 with the acquisition of
REPGB and the formation of our European trading and power origination
operations. European Energy generates and sells power from its generation
facilities in the Netherlands and participates in the emerging wholesale energy
trading markets in Northwest Europe.
Effective October 7, 1999, we acquired REPGB, a Dutch generation company,
for a net purchase price of $1.9 billion. Our 1999 consolidated financial
statements reflect REPGB's results of operations for the period from October 1,
1999 through November 30, 1999 under the equity method of accounting rather than
under the consolidation method. Subsequent to December 1, 1999, we have
consolidated 100% of REPGB's operating results. For additional information
regarding the acquisition of REPGB and the related accounting treatment, please
read Note 5(b) to our consolidated financial statements.
In connection with our evaluation of the acquisition of REPGB, 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 REPGB 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. During 2001, we utilized
$8 million of the reserve. As of December 31, 2001, the remaining severance
liability is $11 million.
REPGB and the other major Dutch generators historically operated under a
protocol agreement, pursuant to which the generators provided capacity and
energy to distributors in exchange for regulated production payments, plus
compensation for actual fuel expended in the production of electricity 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 opened to competition. Consistent with our expectations at
the time that we made the acquisition, REPGB experienced a significant decline
in electric margins in 2001 attributable to the deregulation of the wholesale
electric market.
In 2001, we evaluated strategic alternatives for our European Energy
segment, including a possible sale. We completed our evaluation, and determined
that given current market conditions and prices, it is not advisable to sell our
European Energy operations. Consequently, we decided to continue to own and
operate our European Energy segment and to expand our trading and origination
activities in Northwest Europe. During December 2001, we evaluated our European
Energy segment's long-lived assets and goodwill for impairment. 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. As of December 31, 2001, pursuant to SFAS No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of," no impairment has been indicated. For assessing of impairment
in 2002 under SFAS No. 142 "Goodwill and Other Intangible Assets," please read
"-- New Accounting Pronouncements and Critical Accounting Policies" below.
For additional information regarding these and other factors that may
affect the future results of operations of European Energy, please read "--
Certain Factors Affecting Our Future Earnings -- Factors Affecting the Results
of Our European Energy Operations."
44
For information regarding foreign currency matters, please read Note 6(b)
to our consolidated financial statements and "Quantitative and Qualitative
Disclosures about Market Risk" in Item 7A of this Form 10-K.
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
years ended December 31, 2000 and 2001.
EUROPEAN ENERGY
-----------------------------------------
THREE MONTHS ENDED YEAR ENDED
DECEMBER 31, DECEMBER 31,
------------------ ---------------------
1999 2000 2001
------ ------ ------
(IN MILLIONS, EXCEPT OPERATING DATA)
Operating Revenues ..................... $ 56 $ 580 $1,192
Operating Expenses:
Fuel ................................ 24 260 400
Purchased power ..................... -- 34 589
Operation and maintenance ........... 8 87 30
General and administrative .......... 6 39 41
Depreciation and amortization ....... 6 76 76
------ ------ ------
Total Operating Expenses .......... $ 44 $ 496 $1,136
------ ------ ------
Operating Income ....................... $ 12 $ 84 $ 56
====== ====== ======
Operating Data:
Net Generation Capacity (MW) ........... 3,476 3,476 3,476
Electric Sales (MMWh) .................. 3 13 42
2001 Compared to 2000. European Energy's operating income decreased by $28
million for 2001 compared to 2000. This decrease was primarily due to the
anticipated decline in electric power generation gross margins (revenues less
fuel and purchased power), as the Dutch electric market was completely opened to
wholesale competition on January 1, 2001. Further contributing to the decline in
operating margins were a number of unscheduled outages at our electric
generating facilities. We estimate that these unplanned outages resulted in
losses of $11 million. Increased margins from ancillary services of $33 million
and district heating sales of $9 million in 2001 compared to 2000 and efficiency
and energy payments from NEA totaling $30 million in 2001 partially offset this
decline. Trading gross margins decreased $12 million from a $3 million gross
margin in 2000 to a $9 million gross margin loss in 2001 primarily as a result
of a $17 million provision against receivable and trading and marketing asset
balances related to Enron. Excluding this provision, trading gross margins
increased primarily due to a significant increase in power trading volumes,
trading origination transactions and increased volatility in the Dutch and
German markets. In addition, the decrease in operating income was partially
offset by a $37 million net gain related to the settlement of an indemnity
agreement with the former shareholders of REPGB in the fourth quarter of 2001,
as discussed below.
European Energy's operating revenues increased by $612 million for 2001
compared to 2000. The increase was primarily due to increased trading revenues
in the Dutch, German and Austrian power markets of $544 million and, to a lesser
extent, increased volumes of electric generation sales, which increased 41%,
partially offset by a 29% decrease in prices for power sales. Fuel and purchased
power costs increased $695 million for 2001 compared to 2000 primarily due to
increased purchased power for trading activities, and to a lesser extent
increased cost of natural gas due to higher gas prices, increased output from
our generating facilities and increased transmission and grid charges as a
result of a change in the tariff structure.
Operation and maintenance and general and administrative expenses
decreased by $55 million for 2001 compared to 2000. These expenses declined
primarily due to (a) the net gain of $37 million recorded in operation expenses
related to the settlement of the former shareholders' indemnity obligation, as
discussed below, (b) provisions in 2000 against environmental tax subsidies
receivable from Dutch distribution companies, REPGB's former shareholders and
the Dutch government, coupled with the reversal of such accrual in 2001 due to
the indemnity obligation settlement with REPGB's former shareholders and (c)
decreases in provisions for environmental liabilities, employee benefits and
other accruals totaling $6 million. This decrease was partially offset by an
increase in personnel and operating expenses related to our trading operations,
facilities costs and systems upgrades.
45
In December 2001, REPGB and its former shareholders entered into a
settlement agreement resolving the former shareholders' stranded cost indemnity
obligations under the purchase agreement of REPGB. During the fourth quarter of
2001, we recognized a net settlement gain of $37 million in operation expenses
for the difference between the sum of (a) the cash settlement consideration of
$202 million, and REPGB's rights to claim future distributions of our NEA
investment of an estimated $248 million and (b) the amount recorded as "stranded
cost indemnity receivable" related to the stranded cost gas and electric
commitments of $369 million and claims receivable related to stranded costs
incurred in 2001 of $44 million both previously recorded in our consolidated
balance sheet. Future changes in the valuation of the stranded cost import
contracts that remain an obligation of REPGB will be recorded as adjustments to
our consolidated statement of income, thus introducing potential earnings
volatility. For additional information regarding the settlement, please read
Note 13(f) to our consolidated financial statements.
2000 Compared to 1999. For the year ended December 31, 2000, European
Energy reported operating income of $84 million. European Energy reported
operating income of $12 million for the three months ended December 31, 1999. In
1999, we recorded $22 million in equity income related to REPGB for the period
from October 1, 1999 through November 30, 1999.
RETAIL ENERGY
Our Retail Energy segment provides energy products and services to end-use
customers, ranging from residential and small commercial customers to large
commercial, institutional and industrial customers. In addition, Retail Energy
provided billing, customer service, credit and collection and remittance
services to Reliant Energy's regulated electric utility and two of its natural
gas distribution divisions. The service agreement governing these services
terminated on December 31, 2001. Retail Energy charged the regulated electric
and natural gas utilities for these services at cost. We acquired approximately
1.7 million electric retail customers in the Houston metropolitan area when the
Texas market opened to competition in January 2002. During the first half of
2002, the Texas electric retail market will be largely focused on the extensive
efforts necessary to transition customers from the utilities to the affiliated
retail electric providers. We expect to expand our marketing efforts for small
residential and commercial customers (i.e., customers with an aggregate peak
demand at or below one MW) to other areas in Texas outside of the Houston
territory during the second quarter of 2002. We signed 246 contracts with large
commercial, industrial and institutional (e.g., hospitals, universities, school
systems and government agencies) customers (i.e., customers with an aggregate
peak demand of more than one MW) during 2001, with an aggregate peak electric
energy demand of approximately 3,700 MW and serving approximately 12,000 meter
locations. These customers are both in the Houston metropolitan area as well as
outside of the Houston territory. Our marketing efforts for large commercial,
industrial and institutional customers are continuing throughout the competitive
region of the Electric Reliability Council of Texas (ERCOT).
For a discussion of the factors that may affect the future results of
operations of Retail Energy, please read "-- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Operations of Our Retail
Energy Operations."
The following table provides summary data regarding the results of
operations of Retail Energy for 1999, 2000 and 2001.
RETAIL ENERGY
----------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------
1999 2000 2001
---- ----- -----
(IN MILLIONS)
Operating Revenues ..................... $ 34 $ 64 $ 211
Operating Expenses:
Purchased power ..................... -- -- 27
Operation and maintenance ........... 35 101 110
General and administrative .......... 12 29 76
Depreciation and amortization ....... -- 4 11
---- ----- -----
Total Operating Expenses .......... $ 47 $ 134 $ 224
---- ----- -----
Operating Loss ......................... $(13) $ (70) $ (13)
==== ===== =====
46
2001 Compared to 2000. Our Retail Energy segment's operating loss
decreased by $57 million for 2001 compared to 2000. The operating loss reduction
was primarily due to increased sales of energy and energy services to
commercial, industrial and institutional customers, partially offset by (a)
increased personnel costs and employee related costs and (b) increased costs
associated with developing an infrastructure necessary to prepare for
competition in the retail electric market in Texas. Contracted energy sales to
large commercial, industrial and institutional customers are accounted for under
the mark-to-market method of accounting. These energy contracts are recorded at
fair value in revenue upon contract execution. The net changes in their market
values are recognized in the income statement in revenue in the period of the
change. During 2001, our Retail Energy segment recognized $74 million of
mark-to-market revenues related to commercial, industrial and institutional
energy contracts of which $73 million relates to energy that will be supplied in
future periods ranging from one to three years.
Operating revenues increased by $147 million for 2001 compared to 2000
largely due to increased revenues from sales of energy and energy services to
large commercial, industrial and institutional customers, as well as increased
revenues for the billing and remittance services provided to Reliant Energy.
Purchased power expenses increased by $27 million in 2001 primarily due to a $22
million increase in wholesale electricity purchases and a $5 million increase in
the cost of transmission service both related to the Texas retail pilot program
during the last half of 2001. Our Wholesale Energy segment purchases and manages
Retail Energy's wholesale purchased power requirements needed to fulfill its
retail energy commitments. The Wholesale Energy segment charges Retail Energy
for the purchased power at its actual cost and charges an administrative fee for
such service.
Operations and maintenance costs increased by $9 million and general and
administrative expenses increased $47 million in 2001 as compared to 2000,
primarily due to increased personnel and employee-related costs and costs
related to building an infrastructure necessary to prepare for competition in
the retail electric market in Texas totaling $35 million and increased costs
incurred in performing billing, customer service, credit and collections and
remittance service for Reliant Energy of $31 million.
2000 Compared to 1999. Retail Energy's operating loss increased $57
million for 2000 compared to 1999. Operating revenues increased $30 million
(88%) for 2000 as compared to 1999. This increase was primarily the result of
the inclusion of revenues generated by the operations acquired during November
1999, additional revenue generated by an increase in the number of new energy
service contracts and additional revenues for the billing and remittance
services provided to Reliant Energy. For 2000 as compared to 1999, operations
and maintenance costs increased $66 million and general and administrative costs
increased $17 million. Increased operation and maintenance costs resulted
primarily from costs associated with servicing contracts acquired during 1999 as
well as new contracts entered into in 2000, costs incurred in performing
billing, customer service, credit and collection and remittance services for
Reliant Energy, and costs related to building an infrastructure necessary to
prepare for competition in the retail electric market in Texas. General and
administrative costs increased as a result of building the infrastructure
necessary to prepare for competition in the retail electric market in Texas. In
addition, during the fourth quarter of 2000, we incurred an obligation to pay
$12 million in order to secure the naming rights to a Houston sports complex and
for the initial advertising of which $10 million was expensed in 2000. Starting
in 2002, when the new stadium in the sports complex is operational, we will pay
$10 million each year through 2032 for annual advertising associated with the
sports complex.
OTHER OPERATIONS
Our Other Operations segment includes the operations of our venture
capital and Communications businesses, and unallocated corporate costs.
During the third quarter of 2001, we decided to exit our Communications
business. The business served as a facility-based competitive local exchange
carrier and Internet services provider and owns network operations centers and
managed data centers in Houston and Austin. Our exit plan was substantially
completed in the first quarter of 2002.
47
The following table provides summary data for the results of operations
for Other Operations for 1999, 2000 and 2001.
OTHER OPERATIONS
----------------------------------
YEAR ENDED DECEMBER 31,
----------------------------------
1999 2000 2001
----- ----- -----
(IN MILLIONS)
Operating Revenues ..................... $ -- $ 6 $ 11
Operating Expenses:
Operation and maintenance ............ -- 9 21
General and administrative ........... 2 52 128
Depreciation and amortization ........ 2 6 42
----- ----- -----
Total Operating Expenses ...... $ 4 $ 67 $ 191
----- ----- -----
Operating Loss ......................... $ (4) $ (61) $(180)
===== ===== =====
2001 Compared to 2000. Other Operation's operating loss increased by $119
million for 2001 compared to 2000. During 2001, we recognized $54 million of
restructuring charges related to exiting our Communications business as
discussed above. In addition, we incurred a non-cash charge of $100 million
during 2001 relating to the redesign of some of Reliant Energy's benefit plans
in anticipation of our separation from Reliant Energy. These items were
partially offset by decreased corporate operating expenses of $12 million and
decreased charitable contributions of $15 million of equity securities
classified as "trading" to a charitable foundation. For additional information
about the benefit charge noted above, please read Notes 11(b) and 11(d) to our
consolidated financial statements.
In connection with our decision to exit the Communication business, we
determined that the goodwill associated with the Communications business was
impaired. We recorded $54 million of pre-tax disposal charges in 2001, including
the impairment of goodwill of $19 million and fixed assets of $22 million, and
severance accruals, lease cancellation costs and other incremental costs
associated with exiting the Communications business, totaling $13 million. The
goodwill and fixed asset impairments are included in depreciation and
amortization expense.
In connection with our anticipated separation from Reliant Energy, we
expect to record in the quarter in which the Distribution is completed, a
pre-tax net loss of approximately $36 million related to the settlement of
pension and post retirement obligations for former employees of Reliant Energy,
who transferred to us.
2000 Compared to 1999. During 2000, Other Operations had operating
revenues of $6 million primarily from its Communications business, which was
formed in June 1999. General and administrative and operation and maintenance
costs in 2000 of $61 million, compared to $2 million for 1999, resulted
primarily from costs related to our Communications business and a $15 million
non-cash contribution of equity securities, as discussed above. The increase in
depreciation and amortization of $4 million is primarily related to increased
capital expenditures in 2000 as compared to the same period in 1999.
TRADING AND MARKETING OPERATIONS
We trade and market power, natural gas and other energy-related
commodities and provide related risk management services to our customers. We
apply mark-to-market accounting for all of our non-asset based energy trading,
marketing, power origination and risk management services activities. For
information regarding mark-to-market accounting, please read Notes 2(d) and 6 to
our consolidated financial statements. These trading and marketing activities
consist of:
- the domestic energy trading, marketing, power origination and risk
management services operations of our Wholesale Energy segment;
- the European energy trading and power origination operations of our
European Energy segment; and
- the large contracted commercial, industrial and institutional retail
electricity business of our Retail Energy segment.
48
Our domestic and European energy trading and marketing operations enter
into derivative transactions as a means of optimization of our current power
generation asset position and to take a market position. For additional
information regarding the types of contracts and activities of our trading and
marketing operations, please read "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of this Form 10-K and Note 6 to our consolidated
financial statements.
Below is a detail of our net trading and marketing assets (liabilities) by
segment:
AS OF DECEMBER 31,
--------------------
2000 2001
------ -----
(IN MILLIONS)
Wholesale Energy .......................................... $ 31 $ 154
European Energy ........................................... 1 (9)
Retail Energy ............................................. -- 73
------ -----
Net trading and marketing assets and liabilities ....... $ 32 $ 218
====== =====
Our trading and marketing and risk management services margins realized
and unrealized are as follows:
FOR THE YEAR ENDED DECEMBER 31,
-------------------------------
2000 2001
----- ----
(IN MILLIONS)
Realized ................ $ 202 $184
Unrealized .............. (2) 186
----- ----
Total ................... $ 200 $370
===== ====
Below is an analysis of our net trading and marketing assets and
liabilities for 2001 (in millions):
Fair value of contracts outstanding at December 31, 2000 ............. $ 32
Fair value of new contracts when entered into during the year ........ 119
Contracts realized or settled during the year ........................ (184)
Changes in fair values attributable to changes in valuation
techniques and assumptions ........................................ (23)
Changes in fair values attributable to market price and other
market changes .................................................... 274
-----
Fair value of contracts outstanding at December 31, 2001 .......... $ 218
=====
During 2001, our Retail Energy segment entered into contracts with large
commercial, industrial and institutional customers, with a peak demand of
approximately 3,700 MW, ranging from one to three years. These contracts had an
aggregated fair value of $97 million at the contract inception dates. Subsequent
to the inception dates, the fair values of these contracts were adjusted to $74
million due to changes in assumptions used in the valuation models, as described
below. The fair value of these Retail Energy electric supply contracts was
determined by comparing the contractual pricing to the estimated market price
for the retail energy delivery and applying the estimated volumes under the
provisions of these contracts. This calculation involves estimating the
customer's anticipated load volume, and using the forward ERCOT over-the-counter
(OTC) commodity prices, adjusted for the customer's anticipated load pattern.
Load characteristics in the valuation model include: the customer's expected
hourly electricity usage profile, the potential variability in the electricity
usage profile (due to weather or operational uncertainties), and the electricity
usage limits included in the customer's contract. In addition, some estimates
include anticipated delivery costs, such as regulatory and transmission charges,
electric line losses, ERCOT system operator administrative fees and other market
interaction charges, estimated credit risk and administrative costs to serve.
The weighted-average duration of these transactions is approximately one year.
The remaining fair value of new contracts recorded at inception of $22
million primarily relates to Wholesale Energy fixed and variable-priced power
purchases and sales. The fair values of these Wholesale Energy contracts at
inception are estimated using OTC forward price and volatility curves and
correlation among power and fuel prices, net of estimated credit risk. A
significant portion of the value of these contracts required utilization of
internal models. For the contracts extending beyond December 31, 2001, the
weighted-average duration of these transactions is less than two years.
49
Below are the maturities of our contracts related to our trading and
marketing assets and liabilities as of December 31, 2001 (in millions):
FAIR VALUE OF CONTRACTS AT DECEMBER 31, 2001
-------------------------------------------------------------------------------------------
2007 AND TOTAL FAIR
SOURCE OF FAIR VALUE 2002 2003 2004 2005 2006 THEREAFTER VALUE
- -------------------- ----- ----- ----- ----- ----- ---------- -----------
Prices actively quoted ............... $ (43) $ 4 $ 1 $ -- $ -- $ -- $ (38)
Prices provided by other external
sources ........................... 142 58 (5) (3) 6 (1) 197
Prices based on models and other
valuation methods ................. 34 (1) 3 3 (1) 21 59
----- ----- ----- ----- ----- ----- -----
Total ................................ $ 133 $ 61 $ (1) $ -- $ 5 $ 20 $ 218
===== ===== ===== ===== ===== ===== =====
The "prices actively quoted" category represents our New York Mercantile
Exchange (NYMEX) futures positions in natural gas and crude oil. As of December
31, 2001, the NYMEX had quoted prices for natural gas and crude oil for the next
36 and 30 months, respectively.
The "prices provided by other external sources" category represents our
forward positions in natural gas and power at points for which OTC broker quotes
are available. On average, OTC quotes for natural gas and power extend 60 and 36
months into the future, respectively. We value these positions against
internally developed forward market price curves that are continuously compared
to and recalibrated against OTC broker quotes. This category also includes some
transactions whose prices are obtained from external sources and then modeled to
hourly, daily or monthly prices, as appropriate.
The "prices based on models and other valuation methods" category contains
(a) the value of our valuation adjustments for liquidity, credit and
administrative costs, (b) the value of options not quoted by an exchange or OTC
broker, (c) the value of transactions for which an internally developed price
curve was constructed as a result of the long-dated nature of the transaction or
the illiquidity of the market point, and (d) the value of structured
transactions. In certain instances structured transactions can be composed and
modeled by us as simple forwards and options based on prices actively quoted.
Options are typically valued using Black-Scholes option valuation models.
Although the valuation of the simple structures might not be different than the
valuation of contracts in other categories, the effective model price for any
given period is a combination of prices from two or more different instruments
and therefore have been included in this category due to the complex nature of
these transactions.
The fair values in the above table are subject to significant changes
based on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, marketing, power origination and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant parameters impacting the value of our portfolio of contracts include
natural gas and power forward market prices, volatility and credit risk. For the
Retail Energy sales discussed above, significant variables affecting contract
values also include the variability in electricity consumption patterns due to
weather and operational uncertainties (within contract parameters). Market
prices assume a normal functioning market with an adequate number of buyers and
sellers providing market liquidity. Insufficient market liquidity could
significantly affect the values that could be obtained for these contracts, as
well as the costs at which these contracts could be hedged. Please read
"Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this
Form 10-K for further discussion and measurement of the market exposure in the
trading and marketing businesses and discussion of credit risk management.
For additional information about price volatility and our hedging
strategy, please read "-- Certain Factors Affecting Our Future Earnings --
Factors Affecting the Results of Our Wholesale Energy Operations -- Price
Volatility," and "-- Risks Associated with Our Hedging and Risk Management
Activities."
For information regarding our counterparty credit risk, including credit
ratings, exposure and collateral held by us, please read, "Quantitative and
Qualitative Disclosures About Market Risk -- Credit Risk" in Item 7A of this
Form 10-K.
50
For a description of accounting policies for our trading and marketing
activities, please read Notes 2(d) and 6 to our consolidated financial
statements.
We seek to monitor and control our trading risk exposures through a
variety of processes and committees. For additional information, please read
"Quantitative and Qualitative Disclosures About Market Risk -- Risk Management
Structure" in Item 7A of this Form 10-K.
RELATED-PARTY TRANSACTIONS
In the normal course of operations and in anticipation of our separation
from Reliant Energy, we have entered into transactions and agreements with
related parties, including Reliant Energy. For a discussion of historical
related party transactions, please read Note 3 to our consolidated financial
statements. Below are details of significant current related party transactions,
arrangements and agreements.
AGREEMENTS BETWEEN RELIANT ENERGY AND RELIANT RESOURCES
Master Separation Agreement. Shortly before the IPO, we entered into the
Master Separation Agreement with Reliant Energy. The Master Separation Agreement
provides for the separation of our assets and businesses from those of Reliant
Energy. It also contains agreements governing the relationship between us and
Reliant Energy after the IPO, and in some cases after the Distribution, and
specifies the related ancillary agreements that we have signed with Reliant
Energy, some of which are described in further detail below.
The Master Separation Agreement provides for cross-indemnities intended to
place sole financial responsibility on us and our subsidiaries for all
liabilities associated with the current and historical businesses and operations
we conduct after giving effect to the separation, regardless of the time those
liabilities arise, and to place sole financial responsibility for liabilities
associated with Reliant Energy's other businesses with Reliant Energy and its
other subsidiaries. Each party has also agreed to assume and be responsible for
some specified liabilities associated with activities and operations of the
other party and its subsidiaries to the extent performed for or on behalf of the
other party's current or historical business.
Genco Option Agreement. In connection with the separation of our
businesses from those of Reliant Energy, Reliant Energy has granted us an option
to purchase, subject to the completion of the Distribution, all of the shares of
capital stock owned by Reliant Energy in January 2004 of an entity (Texas Genco)
that will hold the Texas generating assets of Reliant Energy's electric utility
division. For additional information regarding the Texas Genco option and
various agreements between Reliant Energy and us related to the Texas Genco
option, please read Note 4(b) to our consolidated financial statements.
Service Agreements. We have entered into agreements with Reliant Energy
under which Reliant Energy will provide us, on an interim basis, various
corporate support services, 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. The charges we 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 addition,
pursuant to lease agreements, Reliant Energy will lease us office space in its
headquarters building and various other locations in Houston, Texas for various
terms. For additional information regarding these agreements, please read Note
4(a) to our consolidated financial statements.
Payment to Reliant Energy. To the extent that our price for providing
retail electric service to residential and small commercial customers in Reliant
Energy's Houston service territory during 2002 and 2003, which price is mandated
by the Texas electric restructuring law, exceeds the market price of
electricity, we may be required to make a payment to Reliant Energy in early
2004 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 Reliant
Energy's electric utility's Houston service territory as of January 1, 2002 is
committed to be served by retail electric providers other than us. For
additional information regarding this payment, please read Note 13(g) to our
consolidated financial statements.
51
Guarantee of Certain Benefit Payments. We have guaranteed, in the event
Reliant Energy becomes insolvent, certain non-qualified benefits of Reliant
Energy's and its subsidiaries' existing retirees at the Distribution totaling
approximately $55 million.
Transportation Agreement. Prior to the IPO, Reliant Energy Services
entered into an agreement whereby a subsidiary of Reliant Energy agreed to
reimburse Reliant Energy Services for any transportation payments made under a
transportation agreement with ANR Pipeline Company and for the refund of $41
million due to ANR Pipeline Company, an unaffiliated company. For additional
information regarding this transportation agreement, please read Note 13(b) to
our consolidated financial statements.
Commodity Risk Hedges Entered Into by Us on Behalf of Subsidiaries of
Reliant Energy. Reliant Energy Services enters into derivative instruments on
behalf of affiliated entities within the Reliant Energy consolidated group in
accordance with Reliant Energy's risk management policies. Historically, Reliant
Energy Services was subject to the related counterparty credit risk. During
2001, related to the Enron bankruptcy, we recognized a $6 million loss related
to such transactions.
Various Other Agreements. In connection with the separation of our
businesses from those of Reliant Energy, we have entered into other agreements
providing for, among other things, mutual indemnities and releases with respect
to our respective businesses and operations, matters relating to corporate
governance, matters relating to responsibility for employee compensation and
benefits, and the allocation of tax liabilities. In addition, we and Reliant
Energy have entered into various agreements relating to ongoing commercial
arrangements including, among other things, the leasing of optical fiber and
related maintenance activities, gas purchasing and agency matters, and
subcontracting energy services under existing contracts. For additional
information regarding these agreements, please read Note 4(c) to our
consolidated financial statements.
COMMON DIRECTORS ON RELIANT RESOURCES' AND RELIANT ENERGY'S BOARD OF DIRECTORS
Three of our directors are also directors of Reliant Energy. One of these
directors is our chairman, president and chief executive officer. These
directors owe fiduciary duties to the stockholders of each company. As a result,
in connection with any transaction or other relationship involving both
companies, these directors may need to recuse themselves and not participate in
any board action relating to these transactions or relationships. It is
anticipated that at the time of the Distribution, two of these directors will
resign as director of Reliant Energy.
CONSTRUCTION AGENCY AGREEMENTS
In 2001, we, through several of our subsidiaries, entered into operative
documents with special purpose entities to facilitate the development,
construction, financing and leasing of several power generation projects. Upon
completion of an individual project and exercise of the lease option, our
subsidiaries will be required to make lease payments in an amount sufficient to
provide a return to the investors. If we do not exercise our option to lease any
project upon its completion, we must purchase the project or remarket the
project on behalf of the special purpose entities. We have guaranteed the
performance and payment of our subsidiaries' obligations during the construction
periods and, if the lease option is exercised, each lessee's obligations during
the lease period. For additional information regarding the construction agency
agreements and our generating equipment agreements, please read Note 13(h) to
our consolidated financial statements.
CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS
Our past earnings are not necessarily indicative of our future earnings
and results of operations. The magnitude of our future earnings and results of
our operations will depend on numerous factors including:
- state, federal and international legislative and regulatory
developments, including deregulation, re-regulation and
restructuring of the electric utility industry, changes in or
application of environmental and other laws and regulations to which
we are subject, and changes in or application of laws or regulations
applicable to other aspects of our business, such as commodities
trading and hedging activities,
- the timing of our separation from Reliant Energy,
52
- the effects of competition, including the extent and timing of the
entry of additional competitors in our markets,
- liquidity concerns in our markets,
- the degree to which we successfully integrate the operations and
assets of Orion Power into our Wholesale Energy segment,
- the successful and timely completion of our construction programs,
as well as the successful start-up of completed projects,
- our pursuit of potential business strategies, including acquisitions
or dispositions of assets or the development of additional power
generation facilities,
- the timing and extent of changes in commodity prices and interest
rates,
- the availability of adequate supplies of fuel, water, and associated
transportation necessary to operate our generation portfolio,
- weather variations and other natural phenomena, which can effect the
demand for power from or our ability to produce power at our
generating facilities,
- financial market conditions, our access to capital and the results
of our financing and refinancing efforts, including availability of
funds in the debt/capital markets for merchant generation companies,
- the credit worthiness or bankruptcy or other financial distress of
our trading, marketing and risk management services counterparties,
- actions by rating agencies with respect to us or our competitors,
- acts of terrorism or war,
- the availability and price of insurance,
- the reliability of the systems, procedures and other infrastructure
necessary to operate our retail electric business, including the
systems owned and operated by ERCOT,
- political, legal, regulatory 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,
- the successful operation of deregulating power markets, and
- the resolution of the refusal by California market participants to
pay our receivables balances due to the recent energy crisis in the
West region.
In order to adapt to the increasingly competitive environment in our
industry, 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.
FACTORS AFFECTING THE RESULTS OF OUR WHOLESALE ENERGY OPERATIONS
Price Volatility. We sell electricity from our facilities into spot
markets under short and long-term contractual arrangements. We are not
guaranteed any rate of return on our capital investments through cost of service
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. In addition to our power generation operations, we trade and market
power. Market prices may fluctuate substantially over relatively short periods
of time. Demand for electricity can
53
fluctuate dramatically, creating periods of substantial under- or over-supply.
During periods of over-supply, prices are depressed. During periods of
under-supply, there is frequently regulatory or political pressure to regulate
prices to compensate for product scarcity.
In addition, the FERC, which has jurisdiction over wholesale power rates,
as well as independent system operators that oversee some of these markets, have
imposed price limitations, bidding rules and other mechanisms to attempt to
address some of the volatility in these markets and mitigate market prices. For
a discussion of the implementation of price limitations and other rules in the
California market, please read Note 13(i) to our consolidated financial
statements.
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. In addition, we trade and
market natural gas and other energy-related commodities. These factors could
have an adverse impact on our revenues, margins and results of operations.
Volatility in market prices for fuel and electricity may result from:
- weather conditions,
- seasonality,
- forced or unscheduled plant outages,
- addition of generating capacity,
- changes in market liquidity,
- disruption of electricity or gas transmission or transportation,
infrastructure or other constraints or inefficiencies,
- availability of competitively priced alternative energy sources,
- demand for energy commodities and general economic conditions,
- availability and levels of storage and inventory for fuel stocks,
- natural gas, crude oil and refined products, and coal production
levels,
- natural disasters, wars, embargoes and other catastrophic events,
and
- federal, state and foreign governmental regulation and legislation.
Risks Associated with Our Hedging and Risk Management Activities. To lower
our financial exposure related to commodity price fluctuations, our trading,
marketing and risk management services operations routinely enter into contracts
to hedge a portion of our purchase and sale commitments, exposure to weather
fluctuations, fuel requirements and inventories of natural gas, coal, crude oil
and refined products, and other commodities. As part of this strategy, we
routinely utilize fixed-price forward physical purchase and sales contracts,
futures, financial swaps and option contracts traded in the over-the-counter
markets and on exchanges. However, we do not expect to cover the entire exposure
of our assets or our positions to market price volatility, and the coverage will
vary over time. This hedging activity fluctuates according to strategic
objectives, taking into account the desire for cash flow or earnings certainty
and our view on market prices. To the extent we have unhedged positions,
fluctuating commodity prices could negatively impact our financial results and
financial position. For additional information regarding the accounting
treatment for our hedging, trading and marketing and risk management activities,
please read Notes 2(d) and 6 to our consolidated financial statements. For
additional information regarding the types of contracts and activities of our
trading and marketing operations, please read "-- Trading and Marketing
Operations" and "Qualitative and Quantitative Disclosures about Market Risk" in
Item 7A of this Form 10-K.
54
We manage our power generation hedge objectives in the context of market
conditions while targeting certain hedge percentages of future earnings through
hedge actions in the current year. As of December 31, 2001, we had hedged 39%
and 29% of our planned Wholesale Energy margins for 2002 and 2003, respectively,
excluding margins related to Orion Power. Margins for 2002 and 2003 are expected
to be positively impacted by the acquisition of Orion Power and negatively
affected by lower forward electric power prices as they relate to unhedged
positions and an estimated decline in our trading and marketing operations due
to projected decreases in volatility in energy commodity markets.
At times, we have open trading positions in the market, within established
corporate risk management guidelines, resulting from the management of our
trading portfolio. To the extent open trading positions exist, changes in
commodity prices could negatively impact our financial results and financial
position.
The risk management procedures we have in place may not always be followed
or may not always work as planned. As a result of these and other factors, we
cannot predict with precision the impact that our risk management decisions may
have on our businesses, operating results or financial position. For information
regarding our risk management policies, please read "Quantitative and
Qualitative Disclosures about Market Risk -- Risk Management Structure" in Item
7A to this Form 10-K.
Our trading, marketing and risk management services operations (as well as
some of our operations conducted on behalf of Reliant Energy) are also exposed
to the risk that counterparties who owe us money or physical commodities, such
as power, natural gas or coal, will not perform their obligations. Should the
counterparties to these arrangements fail to perform, we might be forced to
acquire alternative hedging arrangements or replace the underlying commitment at
then-current market prices. In this event, we might incur additional losses to
the extent of amounts, if any, already paid to the counterparties. For
information regarding our credit risk, including exposure to Enron and utilities
in California, please read "Quantitative and Qualitative Disclosure About Market
Risk -- Credit Risk" in Item 7A of this Form 10-K and Notes 6(d), 13(i) and 17
to our consolidated financial statements.
In the ordinary course of business, and as part of our hedging strategy,
we enter into long-term sales arrangements for power, as well as long-term
purchase arrangements. For information regarding our long-term fuel supply
contracts, purchase power and electric capacity contracts and commitments,
electric energy and electric sale contracts and tolling arrangements, please
read Notes 6, 13(a) and 13(c) to our consolidated financial statements.
Uncertainty in the California Market. During portions of 2000 and 2001,
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, decreased net electric imports and limitations on
supply as a result of maintenance and other outages. Because of the high prices
that prevailed during this period, Reliant Energy, and several of our
subsidiaries, including Reliant Energy Services and REPG, as well as some of the
officers of some of these companies, 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.
In response to the filing of a number of complaints challenging the level
of these wholesale prices, the FERC initiated a staff investigation and issued a
number of orders implementing a series of wholesale market reforms and
modifications to those reforms. On February 13, 2002, the FERC issued an order
initiating a staff investigation into potential manipulation of electric and
natural gas prices in the West region for the period January 1, 2000 forward.
Some of our long-term bilateral contracts already have been challenged by one of
our many counterparties based on the alleged market dysfunction in Western power
markets in 2000 and 2001. If these challenges are successful, the precedent set
by the challenge could have larger ramifications to our business and operations
beyond the challenged contracts at issue. Furthermore, in addition to FERC
investigations, several state and other federal regulatory investigations 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.
Finally, there have been proposals in the California state legislature to
regulate the operations of our California generating subsidiaries, beyond the
existing state regulation regarding siting, environmental and other health and
55
safety matters. For additional information regarding the litigation and market
uncertainty in California, please read Notes 13(e) and 13(i) to our consolidated
financial statements.
Industry Restructuring, the Risk of Re-regulation and the Impact of
Current Regulations. The regulatory environment applicable to the United States
electric power industry is undergoing significant changes as a result of varying
restructuring initiatives at both the state and federal levels and the
reassessment of existing regulatory mechanisms stemming from the California
power market situation and the bankruptcy of Enron. These initiatives have had a
significant impact on the nature of the industry and the manner in which its
participants conduct their business. These changes are ongoing and we cannot
predict the future development of restructuring 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, our facilities or our
commercial activities, and future changes in laws and regulations may have a
detrimental effect on our business. Some restructured markets, particularly
California, have 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, proposals have been made by governmental
agencies and/or other interested parties to delay or discontinue proposed
restructuring or to re-regulate areas of these markets, especially with respect
to residential retail customers, that have previously been deregulated. In this
connection, state officials, the California Independent System Operator (Cal
ISO) and the investor-owned utilities in California have argued to the FERC that
our California generating subsidiaries should not continue to have market-based
rate authority. While the FERC to date has consistently refused petitions to
force entities with market-based rates to return to cost-based rates, some of
these proceedings are ongoing and we cannot predict what action the FERC may
take on such petitions in the future. If we were forced to adopt cost-based
rates, future earnings would be affected. Furthermore, the Cal ISO is
undertaking a market redesign process to fundamentally change the structure of
wholesale electricity markets and transmission service in California. These
changes, if approved by the FERC, could include a revised market monitoring and
mitigation structure, a revised congestion management mechanism and an
obligation for load-serving entities in California to maintain capacity
reserves. The Cal ISO's stated goal is to complete the first phase of this
redesign by September 30, 2002, when the existing FERC market mitigation scheme
for California will expire.
On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including the Company. For information regarding
this FERC proceeding and other FERC actions relating to the California market,
please read Note 13(i) to our consolidated financial statements. If the FERC
does not modify or reject its proposed approach for dealing with
anti-competitive behavior, our future earnings may be affected by the open-ended
refund obligation.
Additionally, federal legislative initiatives have been introduced and
discussed to address the problems being experienced in some of these markets,
including legislation seeking to impose price caps on sales. We cannot predict
whether other proposals to re-regulate will be made or whether legislative or
other attention to the restructuring of the electric power industry will cause
the restructuring to be delayed or reversed. If the trend towards competitive
restructuring of the wholesale power markets is reversed, discontinued or
delayed, the business growth prospects and financial results of our Wholesale
Energy and Retail Energy segments could be adversely affected.
If Regional Transmission Organizations (RTOs) are established as
envisioned by Order No. 2000, "rate pancaking," or multiple transmission charges
that apply to a single point-to-point delivery of energy will be eliminated
within a region, and wholesale transactions within the region, and between
regions will be facilitated. The end result could be a more competitive,
transparent market for the sale of energy and a more economic and efficient use
and allocation of resources; however, considerable opposition exists in some
arenas to the development of RTOs.
The FERC also has initiated a rulemaking proceeding to establish
standardized transmission service throughout the United States, a standard
wholesale electric market design, including forward and spot markets for energy
and an ancillary services market, and specifications regarding the entities that
administer these markets and for market
56
monitoring and mitigation, that could be used in all RTOs. We cannot predict at
this time what effect FERC's standard market design will have on our business
growth prospects and financial results.
Partly in response to the bankruptcy of Enron, there have been proposals
in the United States Congress to make online platforms that trade energy and
metals derivatives subject to oversight by the Commodities Futures Trading
Commission (CFTC), to prohibit market price manipulation and fraud. Under some
of these proposals, dealers in energy derivatives would be required to file
reports with the CFTC and maintain amounts of capital, as determined by the
CFTC, to support the risks of their transactions. Other proposals would require
the CFTC to review these markets for potential regulatory recommendations. We do
not know what impact, if any, these proposals would have on our business if
enacted. Additionally, there may be other broader proposals introduced to submit
energy trading to comprehensive regulation by the FERC or by the CFTC.
The acquisition, ownership and operation of power generation facilities
require numerous permits, approvals and certificates from federal, state and
local governmental agencies. The operation of our generation facilities must
also comply with environmental protection and other legislation and regulations.
At present, we have operations in Arizona, California, Florida, Illinois,
Maryland, Nevada, New Jersey, New York, Ohio, Pennsylvania, Texas and West
Virginia. Most of our existing domestic generation facilities are exempt
wholesale generators that sell electricity exclusively into the wholesale
market. These facilities are subject to regulation by the FERC regarding rate
matters and by state public utility commissions regarding siting, environmental
and other health and safety matters. The FERC has authorized us to sell our
generation from these facilities at market prices. The FERC retains the
authority to modify or withdraw our market-based rate authority and to impose
"cost of service" rates if it determines that market pricing is not in the
public interest.
Uncertainty Related to the New York Regulatory Environment. The New York
market is subject to significant regulatory oversight and control. Our operating
results are as dependent on the continuance of the regulatory structure as they
are on fluctuations in the market price for electricity. The rules governing the
current regulatory structure are subject to change. We cannot assure you that we
will be able to adapt our business in a timely manner in response to any changes
in the regulatory structure, which could have a material adverse effect on our
revenues and costs. The primary regulatory risk in this market is associated
with the oversight activity of the New York Public Service Commission, the New
York Independent System Operator (NYISO) and the FERC.
Our assets located in New York are subject to "lightened regulation" by
the New York Public Service Commission, including provisions of the New York
Public Service Law that relate to enforcement, investigation, safety,
reliability, system improvements, construction, excavation, and the issuance of
securities. Because "lightened regulation" was accomplished administratively, it
could be revoked.
The NYISO has the ability to revise wholesale prices, which could lead to
delayed or disputed collection of amounts due to us for sales of energy and
ancillary services. The NYISO also has the ability, in some cases subject to
FERC approval, to impose cost-based pricing and/or price caps. The NYISO has
implemented a measure known as the "Automated Mitigation Procedure" (AMP) under
which day-ahead energy bids will be automatically reviewed and, if necessary,
mitigated if economic or physical withholding is determined. Proposed
modifications to the AMP provide a level of uncertainty over the impacts of that
procedure in the summer of 2002. FERC has also directed the NYISO to adopt
mitigation measures for all limits in New York City consistent with its overall
market-monitoring plan. NYISO has filed in-city mitigation measures with the
FERC, which it is proposing to be implemented beginning in late spring of 2002.
The full impact of these revisions may not be known until the summer of 2002.
Integration and Other Risks Associated with Our Orion Power Assets. We
have made a substantial investment in our recent acquisition of Orion Power. If
we are unable to profitably integrate, operate, maintain and manage our newly
acquired power generation facilities, our results of operations will be
adversely affected.
Duquesne Light Company is obligated to supply electricity at predetermined
tariff rates to all retail customers in its existing service territory who do
not select another electricity supplier. Orion Power has committed to provide
100% of the energy that Duquesne Light Company needs to meet this obligation
under a contract that was recently extended through December 2004. If our
obligation under this contract exceeds the available output from the combination
of Orion Power's generation facilities and our additional generation facilities
in the region, we would
57
be forced to buy additional energy at prevailing market prices and, in certain
cases where we failed to deliver the required amount, we could incur penalties
during periods of peak demand of up to $1,000 per megawatt hour. If this
situation were to occur during periods of peak energy prices, we could suffer
substantial losses that could materially adversely affect our results of
operations. In addition, our revenues generated under this contract may be
adversely impacted if a substantial number of Duquesne Light Company's retail
customers select other retail electric providers.
Operating Risks. Our Wholesale Energy operations and our European Energy
operations are exposed to risks relating to the breakdown or failure of
equipment or processes, fuel supply interruptions, shortages of equipment,
material and labor, and operating performance below expected levels of output or
efficiency. A significant portion of our facilities were constructed many years
ago. Older generating equipment, even if maintained in accordance with good
engineering practices, may require significant capital expenditures to add or
upgrade equipment to keep it operating at peak efficiency, to comply with
changing environmental requirements, or to provide reliable operations. Such
changes could affect operating costs. Any unexpected failure to produce power,
including failure caused by breakdown or forced outage, could result in reduced
earnings.
We depend on transmission and distribution facilities owned and operated
by utilities and other power companies to deliver the electricity we sell from
our power generation facilities to our customers, who in turn deliver these
products to the ultimate consumers of the power. If transmission is disrupted,
or transmission capacity is inadequate, our ability to sell and deliver our
products may be hindered.
Factors Affecting Our Acquisition and Project Development Activities. Our
plans indicate a shift in emphasis from identifying and pursuing acquisition and
development candidates to construction and integration of generation facilities.
We believe this is a temporary shift based on the requirements of integrating
the Orion Power assets and the maturation of both our and Orion Power's
development projects and by the current state of the wholesale electricity
capital markets.
There are numerous risks relating to the acquisition and development of
power generation plants and construction and integration of these facilities. We
may not be able to identify attractive acquisitions or development
opportunities, complete acquisitions or development projects we undertake, or we
may not be able to integrate these plants, especially larger acquisitions, into
our portfolios and achieve the synergies, including cost savings, we originally
envisioned.
Currently, we have a select number of power generation facilities under
development and many under construction (either owned or leased). Our completion
of these facilities is subject to the following:
- market prices,
- shortages and inconsistent quality of equipment, material and labor,
- financial market conditions and the results of our financing
efforts,
- actions by rating agencies with respect to us or our competitors,
- work stoppages, due to plant bankruptcies and contract labor
disputes,
- permitting and other regulatory matters,
- unforeseen weather conditions,
- unforeseen equipment problems,
- environmental and geological conditions, and
- unanticipated capital cost increases.
58
Any of these factors could give rise to delays, cost overruns or the
termination of the plant expansion, construction or development. Many of these
risks cannot be adequately covered by insurance. While we maintain insurance,
obtain warranties from vendors and obligate contractors to meet specified
performance standards, the proceeds of such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues, increased expenses or
liquidated damages payments we may owe.
If we were unable to complete the development of a facility, we would
generally not be able to recover our investment in the project. The process for
obtaining initial environmental, siting and other governmental permits and
approvals is complicated, expensive, lengthy and subject to significant
uncertainties. Transmission interconnection, fuel supply and cooling water
represent some cost uncertainties during project development that may also
result in termination of the project. In addition, construction delays and
contractor performance shortfalls can result in the loss of revenues and may, in
turn, adversely affect our results of operations. The failure to complete
construction according to specifications can result in liabilities, reduced
plant efficiency, higher operating costs and reduced earnings. We may not be
successful in the development or construction of power generation facilities in
the future.
As a result of several recent events, including the United States economic
recession, the price decline of our industry sector in the equity capital
markets and the downgrading of the credit ratings of several of our significant
competitors, the availability and cost of capital for our business and the
businesses of our competitors has been adversely affected. In response to these
events and the intensified scrutiny of companies in our industry sector by the
rating agencies, we have reduced our planned capital expenditures by $2.7
billion over the 2002 -- 2006 time frame.
Successful integration of plants, especially acquisitions, is subject to a
number of risks, including the following:
- unforeseen liabilities or other exposures,
- inaccurate due diligence of acquired facilities, such as
underestimates of outage rates and operating costs,
- inability to achieve adequate cost savings in both overhead and
operations,
- inability to achieve various commercial synergies with existing
operations, and
- market prices for power and fuels.
Any of these factors could significantly affect the economic impact of an
acquisition on our results of operations.
As part of this integration process and our temporary shift in emphasis,
the Orion Power plants will be part of an operations improvement process that
strives to achieve both reduced operating and maintenance costs and increase
gross margins through improved availability and reliability of plants. This
process is currently underway at our other plants and will be introduced at the
Orion Power facilities beginning in the third quarter of 2002.
Increasing Competition in Our Industry. Our Wholesale Energy business
segment competes with other energy merchants. In order to successfully compete,
we must have the ability to aggregate supplies at competitive prices from
different sources and locations and must be able to efficiently utilize
transportation services from third-party pipelines and transmission services
from electric utilities. We also compete against other energy merchants on the
basis of our relative skills, financial position and access to credit sources.
Energy customers, wholesale energy suppliers and transporters often 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, we anticipate that our operations will
experience greater competition and downward pressure on per-unit profit margins.
Furthermore, demands for liquidity to support trading and merchant asset
businesses are increasing at the same time that the credit rating agencies are
reviewing the liquidity and other credit criteria for trading, marketing and
merchant generation firms. Other companies we compete with may not have similar
credit ratings pressure or may have higher credit ratings. The growth of
electronic trading platforms has increased the number of transactions, potential
counterparties and level of price transparency in the energy commodity market.
As a result, we are likely
59
to transact with a wide range of customers potentially increasing our risk due
to their changing credit circumstances, while at the same time potentially
diversifying our reliance on a smaller number of customers.
Developments with respect to our competitors frequently have a collateral
and tangible impact on us. Credit and liquidity concerns impact our ability to
do business with counterparties. Adverse regulatory and political ramifications
can result from activities and investigations directed at our competitors.
Hydroelectric Facilities Licensing. The Federal Power Act gives the FERC
exclusive authority to license non-federal hydroelectric projects on navigable
waterways and federal lands. The FERC hydroelectric licenses are issued for
terms of 30 to 50 years. Some of our hydroelectric facilities, representing
approximately 90 MW of capacity, have licenses that expire within the next ten
years. Facilities that we own representing approximately 160 MW of capacity have
new or initial license applications pending before the FERC. Upon expiration of
a FERC license, the federal government can take over the project and compensate
the licensee, or the FERC can issue a new license to either the existing
licensee or a new licensee. In addition, upon license expiration, the FERC can
decommission an operating project and even order that it be removed from the
river at the owner's expense. In deciding whether to issue a license, the FERC
gives equal consideration to a full range of licensing purposes related to the
potential value of a stream or river. It is not uncommon for the relicensing
process to take between four and ten years to complete. Generally, the
relicensing process begins at least five years before the license expiration
date and the FERC issues annual licenses to permit a hydroelectric facility to
continue operations pending conclusion of the relicensing process. We expect
that the FERC will issue to us new or initial hydroelectric licenses for all the
facilities with pending applications. Presently, there are no applications for
competing licenses and there is no indication that the FERC will decommission or
order any of the projects to be removed.
FACTORS AFFECTING THE RESULTS OF OUR EUROPEAN ENERGY OPERATIONS
General. Our European Energy segment intends to focus its activities in
existing trading markets in the Netherlands, the United Kingdom, Germany, the
Scandinavian countries, Austria and Switzerland. Historical results of
operations may not be indicative of future results of operations. In particular,
results of operations for our European Energy segment prior to 2001 reflect the
impact of a regulated generation price system that has been discontinued. In
addition, in 2001 and prior years, under Dutch corporate income tax laws, the
earnings of REPGB were subject to a zero percent Dutch corporate income tax rate
as a result of the Dutch tax holiday applicable to its 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 34.5%.
Furthermore, European Energy's results of operations for 2001 include the effect
of a number of non-recurring items, including the $37 million net gain resulting
from the settlement of a stranded cost indemnity agreement.
Future results of operations of our European Energy segment could be
affected by, among other things, the following:
- increasing competition in the Dutch wholesale energy market,
resulting in declining electric power margins,
- the timing and pace of the deregulation of other sectors of the
European energy markets,
- the continuing negative impact of the bankruptcy of Enron
on market liquidity and credit requirements in European
trading markets,
- the mark-to-market price risk exposure associated with certain
stranded cost electricity and natural gas supply contracts,
- the impact of any renegotiation of European Energy's stranded cost
contracts,
- the impact and changes of natural gas tariffs pursuant to changes in
the regulatory structure,
- the ability to negotiate new contracts or renew contracts with
customers on favorable terms, and
60
- the impact of slowing economic growth on power generation demand in
the markets in which our European Energy segment operates.
Competition in the European Market. Competition for energy customers in
the markets in which our European Energy segment operates is high. The primary
factors affecting our European Energy segment's competitive position are price,
regulation, the economic resources of its competitors, and its market reputation
and perceived creditworthiness.
Our European Energy segment competes in the Dutch wholesale market against
a variety of other companies, including other Dutch generation companies,
co-generators, various producers of alternate sources of power and non-Dutch
generators of electric power, primarily from France and Germany. As of December
31, 2001, the Dutch electricity system had 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 primarily used to import electricity from France, but a
larger portion of Dutch electricity imports comes from Germany. It is
anticipated that over time, transmission constraints between the Netherlands and
other European markets will be reduced, thereby exposing our European Energy
segment to even greater competitive pressures.
Our European Energy segment's trading and marketing operations are also
subject to increasing levels of competition. Competition among power generators
for customers is intense and is expected to increase as more participants enter
increasingly deregulated markets. Many of our European Energy segment's existing
competitors have geographic market positions far more extensive than that of our
European Energy segment. In addition, many of these competitors possess
significantly greater financial, personnel and other resources than our European
Energy segment.
Deregulation of the Dutch Market. The Dutch wholesale electric market was
completely opened to competition on January 1, 2001. Consistent with our
expectations at the time we acquired our operations in the Netherlands, the
gross margin of our European Energy segment declined in 2001 as a result of the
deregulation of the market and the termination of an agreement with the other
Dutch generators and the Dutch distributors. Commercial markets were generally
opened to retail competition in January 2002. We expect the remainder of the
market, consisting of mainly residential customers, will be open to competition
by January 1, 2003. The timing of opening of the residential segment of the
market is subject to change, however, at the discretion of the Dutch Minister of
Economic Affairs. Since our European Energy segment's operations focus on the
wholesale market, we do not expect that the opening of the Dutch commercial or
residential electric market will have a significant impact on the segment's
results of operations.
Plant Outages. During 2001, our margins were negatively impacted by
unplanned outages at some of our Dutch generation facilities. The unplanned
outages were primarily due to malfunctions of the generation turbines and
related equipment and complications encountered in the maintenance of one of our
facilities. We estimate that these unplanned outages resulted in losses of
approximately $11 million, a significant portion of which is covered by property
damage and business interruption insurance. For additional information regarding
operational risks applicable to our European Energy segment, including unplanned
plant outages, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Operating Risks."
Other Factors. In December 2001, REPGB and its former shareholders entered
into a settlement agreement resolving the former shareholders' stranded cost
indemnity obligations under the purchase agreement of REPGB. For additional
information regarding the stranded cost indemnity settlement and the potential
impact on earnings from changes in the valuation in the future of the related
stranded cost contracts, please read Notes 6(b) and 13(f) to our consolidated
financial statements. We have begun discussions with the other parties to these
contracts to modify the terms of certain of the out-of-market contracts. The
structure of these settlements, if consummated, likely would entail an upfront
cash payment to the counterparty in exchange for amendments to price and other
terms intended to make the contracts more market conforming. REPGB would seek to
fund these payments, if made, to the extent possible through the proceeds from
the settlement of its stranded cost indemnity agreement and, possibly,
anticipated distributions from NEA. We cannot currently predict the outcome of
these negotiations. However, to the extent that these discussions result in
amendments to the contracts, we could realize a gain.
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We are in the process of reviewing our European Energy segment's goodwill
and certain intangibles for impairment pursuant to SFAS No. 142. For information
regarding assessing the impairment in 2002 under SFAS No. 142, please read "--
New Accounting Pronouncements and Critical Accounting Policies."
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 2001 negatively
affected U.S. dollar net income by approximately $2 million.
FACTORS AFFECTING THE RESULTS OF OUR RETAIL ENERGY OPERATIONS
General. The Texas retail electricity market fully opened to competition
in January 2002. Therefore, we do not expect the earnings from our Retail Energy
segment for past years to be indicative of our future earnings and results. The
level of future earnings generated by our Retail Energy segment will depend on
numerous factors including:
- legislative and regulatory developments related to the newly-opened
retail electricity market in Texas and changes in the application of
such laws and regulations,
- the effects of competition, including the extent and timing of the
entry or exit of competitors in our markets and the impact of
competition on retail prices and margins,
- customer attrition rates and cost associated with acquiring and
retaining new customers,
- our ability to negotiate new contracts or renew contracts with
customers on favorable terms,
- the timing and extent of changes in wholesale commodity prices and
transmission and distribution rates,
- our ability to procure adequate electricity supply upon economic
terms,
- our ability to effectively hedge commodity prices,
- our ability to pass increased supply costs on to customers in a
timely manner,
- our ability to timely perform our obligations under our customer
contracts,
- market liquidity for wholesale power,
- the financial condition and payment patterns of our customers,
- weather variations and other natural phenomena,
- the timely and accurate implementation of the new internal and
external information technology systems and processes necessary to
provide customer information and to implement customer switching in
the retail electricity market in Texas which was established in late
2001,
- the costs associated with operating our internal customer service
and other operating functions, and
- the timing and accuracy of ERCOT settlements, and the exchange of
information between ERCOT, the transmission and distribution utility
and our retail electric provider, which facilitates our Retail
Energy segment's billing, collection and supply management
processes.
Competition in the Texas Market. In June 1999, the Texas legislature
adopted the Texas electric restructuring law, which substantially amended the
regulatory structure governing electric utilities in Texas in order to allow
full retail competition. Beginning in 2002, all classes of Texas customers of
most investor-owned utilities, and those of any municipal utility and electric
cooperative that opted to participate in the competitive marketplace, were able
to choose their retail electric provider. In January 2002, we began to provide
retail electric services to all customers of
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Reliant Energy's electric utility who did not take action to select another
retail electric provider. Under the market framework established by the Texas
electric restructuring law, we are recognized as the affiliated retail electric
provider of Reliant Energy's electric utility. The Distribution will not change
this treatment, even though we will cease to be a subsidiary of Reliant Energy
after the Distribution. As an affiliated retail electric provider, we are
initially required to sell electricity to these Houston area residential and
small commercial customers at a specified price, which is referred to in the law
as the "price to beat," whereas other retail electric providers are allowed to
sell electricity to these customers at any price. Our price to beat was set at a
level resulting in an estimated average 17% reduction from December 31, 2001
rates for our residential customers and an estimated average 22% reduction from
December 31, 2001 rates for our pre-existing small commercial customers. The
wholesale energy supply cost component, or "fuel factor," included in our price
to beat was initially set by the Texas Utility Commission at the then average
forward 12 month gas price strip of approximately $3.11/mmbtu.
We are not 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 the relevant class of customers in the
Houston metropolitan area is committed to be served by retail electric providers
other than us. Because we will not be able to compete for residential and small
commercial customers on the basis of price in the Houston area, we may lose a
significant number of these customers to other retail electric providers.
Customers were given the opportunity to switch beginning in August 2001 through
the retail pilot project. Due to system related problems which restricted the
timely switching of customers during the pilot project and in early 2002, we
cannot be sure of the number of customers that have attempted to switch to other
retail electric providers. For additional information regarding retail market
systems problems, please read "-- Operational Risks." Between the beginning of
the pilot project in August 2001 and February 28, 2002, we estimate that
approximately 67,000 customers (or approximately 4% of our residential and small
commercial customers) have switched to other retail electric providers. Due to
the switching systems problems, the actual numbers of customers that switched or
attempted to switch by this date may actually be higher.
As discussed above, as the affiliated retail electric provider, we may
only sell electricity to residential and small commercial customers in Reliant
Energy's electric utility service territory at the price to beat for a period of
up to three years. In addition, as the affiliated retail electric provider, we
are obligated to offer the price to beat to requesting residential and small
commercial customers in Reliant Energy's electric utility service territory
through January 1, 2007.
We are providing commodity service to the large commercial, industrial and
institutional customers previously served by Reliant Energy's electric utility
who did not take action to select another retail electric provider. In addition,
we have signed contracts to provide electricity and services to large
commercial, industrial and institutional customers, both in the Houston area as
well as outside of the Houston market. We or any other retail electric provider
can provide services to these customers at any negotiated price. The market for
these customers is very competitive, and any of these customers that select us
as their provider may subsequently decide to switch to another provider at the
conclusion of the term of their contract with us.
In most retail electric markets outside the Houston area, our principal
competitor may be the local incumbent utility company's retail affiliate. These
retail affiliates have the advantage of long-standing relationships with their
customers. In addition to competition from the incumbent utilities' affiliates,
we may face competition from a number of other retail providers, including
affiliates of other non-incumbent utilities, independent retail electric
providers and, with respect to sales to large economical and industrial
customers, independent power producers acting as retail electric providers. Some
of these competitors or potential competitors may be larger and better
capitalized than we are.
Generally, retail electric providers will purchase electricity from the
wholesale generators at unregulated rates, sell electricity to their retail
customers and pay the transmission and distribution utility a regulated tariffed
rate for delivering the electricity to their customers. Retail electric
providers will then bill and collect payments from the customers. Because we are
required to sell electricity to residential and small commercial customers in
the Houston area at the price to beat, we may lose a significant number of these
customers to non-affiliated retail electric providers if their cost to provide
electricity to these customers is lower than the price to beat. In addition, the
results of our Retail Energy operations for sales to residential and small
commercial customers over the next several years in Texas will be largely
dependent upon the amount of gross margin, or "headroom," available in our price
to beat.
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Until 2004, when we will have the option to acquire Reliant Energy's ownership
interest in Texas Genco, our results will be largely based on the ability of our
Wholesale Energy segment to buy power at prices that yield acceptable gross
margins at revenue levels determined by the price to beat set by the Texas
Utility Commission. The available headroom in the price to beat is equal to the
difference between the price to beat and the sum of the charges, fees and
transmission and distribution utility rates approved by the Texas Utility
Commission and the price we pay for power to serve our price to beat customers.
The larger the amount of headroom, the more incentive new market entrants should
have to provide retail electric services in that particular market. The Texas
Utility Commission's regulations allow affiliated retail electric providers to
adjust their price to beat fuel factor based on the percentage change in the
price of natural gas. In addition, they may also request an adjustment as a
result of changes in their price of purchased energy. In such a request, they
may adjust the fuel factor to the extent necessary to restore the amount of
headroom that existed at the time the initial price to beat fuel factor was set
by the Texas Utility Commission. Affiliated retail electric providers may not
request that their price to beat be adjusted more than twice a year. We cannot
estimate with any certainty the magnitude and frequency of the adjustments we
may seek, if any, and the eventual impact of such adjustments on the amount of
headroom. Based on forward gas prices at the end of March 2002, we would be able
to increase our price to beat rates by approximately 4-5%. Available headroom in
the Houston market, as well as in other Texas markets where we intend to
compete, will be affected by any changes in transmission and distribution rates
that may be requested by the transmission and distribution provider in the
respective service territory and in taxes, fees and other charges assessed or
levied by third parties. Any changes in transmission and distribution rates must
be approved by the Texas Utility Commission. The Texas Utility Commission has
initiated a proceeding to determine what taxes a municipality or other local
taxing authority can charge retail electric providers relating to the provision
of electricity.
In Texas, our Wholesale Energy group and our Retail Energy group work
together in order to determine the price, demand and supply of energy required
to meet the needs of our Retail Energy segment's customers. We may purchase
capacity from non-affiliated parties in the capacity auctions mandated by the
Texas Utility Commission and from Texas Genco in auctions substantially similar
to, but separate from, the mandated auctions. These positions are continuously
monitored and updated based on retail sales forecasts and market conditions.
However, we do not expect to cover the entire exposure of these positions to
market price volatility, and the coverage will vary over time. For a discussion
of risks similar to those associated with our Retail Energy segment's hedging
activities, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Price Volatility," and "-- Risks Associated with Our
Hedging and Risk Management Activities." In addition to the factors noted in
these sections, our ability to adequately hedge our retail electricity
requirements is also dependent on the accurate forecast of the number of our
customers in each customer class and uncertainties associated with the recently
established ERCOT settlement procedures.
Obligations as a Provider of Last Resort. The Texas electric restructuring
law requires the Texas Utility Commission to designate certain retail electric
providers 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, nondiscountable 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. In the event that another retail electric provider fails to serve any or
all of its customers, the 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. The Texas Utility Commission designated
our subsidiary, StarEn Power, to serve as the provider of last resort for
residential and small commercial customers in the western portion of the
Dallas/Fort Worth metropolitan area formally served by Texas Utilities, Inc., a
subsidiary of TXU, Inc. In addition, StarEn Power has been appointed as the
provider of last resort for large commercial, industrial and institutional
customers in Reliant Energy's electric utility service territory. StarEn Power
will serve two consecutive six month terms as the provider of last resort. The
first term began on January 1, 2002. The second six-month term, beginning July
1, 2002, will include a potential adjustment to the energy component of our
provider of last resort rate based on a NYMEX Henry Hub natural gas index. The
terms and rates for provider of last resort service are governed by a settlement
between us and various interested parties, which settlement was approved by the
Texas Utility Commission. In this role, StarEn Power retains the rights to
require customer deposits and disconnect service in accordance with Texas
Utility Commission rules, and to petition the Texas Utility Commission for a
price change in the event it is determined that StarEn power will experience a
net financial loss over the term of its provider of last resort obligations. In
the first quarter of 2002, the Texas Utility Commission
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initiated a proceeding to review and possibly amend both the governing rules and
structure of provider of last resort service and obligations. This proceeding is
in its initial stages and we cannot be sure whether the structure of provider of
last resort service and obligations will change, how they will change or what
effect, if any, any changes would have on the financial condition, results of
operations or cash flows of StarEn Power or our Retail Energy segment.
"Clawback" Payment to Reliant Energy. To the extent the price to beat
exceeds the market price of electricity, we will be required to make a payment
to Reliant Energy in 2004 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 (at or below
one MW), as applicable, within Reliant Energy's electric utility service
territory is committed to be served by retail electric providers other than us.
If the 40% test is not met and the reconciliation and a retail payment is
required, the amount of this retail payment will be equal to (a) the amount that
the price to beat, less non-bypassable delivery charges, is in excess of the
market price of electricity per customer, but not to exceed $150 per customer,
multiplied by (b) the number of residential or small commercial customers, as
the case may be, that we serve on January 1, 2004 in Reliant Energy's electric
utility service territory, less the number of new retail electric customers we
serve in other areas of Texas.
Operational Risks. The price of purchased power could have an adverse
effect on the costs incurred by our Retail Energy segment in acquiring power to
serve the demand of its retail customers. For additional information regarding
commodity price volatility, please read "-- Factors Affecting the Results of Our
Wholesale Energy Operations -- Price Volatility."
We are dependent on local transmission and distribution utilities for
maintenance of the infrastructure through which we deliver electricity to our
retail customers. Any infrastructure failure that interrupts or impairs delivery
of electricity to our customers could negatively impact the satisfaction of our
customers with our service. Additionally, we are dependent on the local
transmission and distribution utilities for the reading of our customers' energy
meters. We are required to rely on the local utility or, in some cases, the
independent transmission system operator, to provide us with our customers'
information regarding energy usage, and we may be limited in our ability to
confirm the accuracy of the information. The provision of inaccurate information
or delayed provision of such information by the local utilities or system
operators could have a material negative impact on our business and results of
operations and cash flows.
The ERCOT ISO is the independent system operator responsible for
maintaining reliable operations of the bulk electric power supply system in the
ERCOT market. Its 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. Problems in the flow of information between
the ERCOT ISO, the transmission and distribution utility and the retail electric
providers have resulted in delays in switching customers. While the flow of
information is improving, operational problems in the new system and processes
are still being worked out. In some instances, large commercial, industrial and
institutional customers who have not yet been switched to be customers of
Solutions due to system delays are paying for electricity at the default rate
which is higher than their contracted price of electricity. Until the customer
is switched to us, Solutions cannot provide it electricity. This delay in
switching has also caused us, at times, to sell in the spot market or through
bilateral contracts at prices below the contracted prices the electricity that
we had intended to provide to such customers.
The ERCOT ISO is also responsible for handling scheduling and settlement
for all electricity supply volumes in the Texas deregulated electricity market.
In addition, the ERCOT ISO plays a vital role in the collection and
dissemination of metering data from the transmission and distribution utilities
to the retail electric providers. We and other retail electric providers
schedule volumes based on forecasts. As part of settlement, the ERCOT ISO
communicates the actual volumes delivered compared to the forecast volumes
scheduled. The ERCOT ISO calculates an additional charge or credit based on the
difference between the actual and forecast volumes, based on a market clearing
price for the difference. Settlement charges also include allocated costs such
as unaccounted-for energy. Currently, there is a three to four month delay in
receiving final settlement information. As a result, we must estimate our supply
costs. Timing delays in receiving final settlement information creates supply
cost estimation risk.
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FACTORS RELATED TO OUR SEPARATION FROM RELIANT ENERGY
Distribution. Although Reliant Energy has advised us that it currently
intends to complete the distribution of our common stock to its shareholders
promptly upon the receipt of certain regulatory approvals related to its
restructuring, which it currently expects to obtain in the next few months, we
cannot assure you whether or when the Distribution will occur. Reliant Energy is
not obligated to complete the Distribution, and it may decide not to do so.
Upon completion of the Distribution, substantially all of the 240,000,000
shares of our common stock that Reliant Energy owns would be eligible for
immediate resale in the public market. We are unable to predict whether
significant amounts of our common stock will be sold in the open market in
anticipation of, or following, the Distribution. We are also unable to predict
whether a sufficient number of buyers would be in the market at that time, such
that an imbalance of sellers and buyers could eventually affect the price of our
stock.
A portion of Reliant Energy's common stock is held by index funds tied to
the Standard & Poor's 500 Index, the Standard & Poor's Electric Utilities Index
and the Dow Jones Utilities Index or other stock indices. If our stock is not
included in these indices at the time of the Distribution, these index funds
will be required to sell our stock. Similarly, other institutional stockholders
are not allowed by their charters to hold the stock of companies that do not pay
dividends. Since we currently do not intend to pay dividends, we expect that
these stockholders will sell the shares of our common stock distributed to them.
Any sales of substantial amounts of our common stock in the public market, or
the expectation that such sales might occur, whether as a result of the
Distribution or otherwise, could adversely affect the market price of our common
stock.
Reliant Energy as a 80+% Stockholder. Reliant Energy owns over 80% of our
outstanding common stock. As long as Reliant Energy owns a majority of our
outstanding common stock, Reliant Energy will continue to be able to elect our
entire board of directors without calling a special meeting. As a result,
Reliant Energy, subject to any fiduciary duty owed to our minority stockholders
under Delaware law, will be able to control all matters affecting us.
In addition, Reliant Energy may enter into credit agreements, indentures
or other contracts that limit the activities of its subsidiaries. While we would
not likely be contractually bound by these limitations, Reliant Energy would
likely cause its representatives on our board of directors to direct our
business so as not to breach any of these agreements. Moreover, the Texas
Utility Commission and the state regulatory commissions of Arkansas and
Minnesota have imposed limitations on the amount Reliant Energy or its
subsidiaries may invest in foreign utility companies and, in some cases, foreign
electric wholesale generating companies. These limitations are based upon
Reliant Energy's consolidated net worth, retained earnings, and debt and
stockholders' equity.
Possible Conflicts of Interest. We may have potential business conflicts
of interest with Reliant Energy with respect to our past and ongoing
relationships, and because of Reliant Energy's controlling ownership prior to
the Distribution, we may not be able to resolve these conflicts on terms
commensurate with those possible in arms' length transactions. In anticipation
of our separation from Reliant Energy, we have entered into many agreements with
Reliant Energy. These agreements may be amended upon agreement of the parties.
While we are controlled by Reliant Energy, Reliant Energy may be able to require
us to agree to amendments to these agreements. We may not be able to resolve any
potential conflicts with Reliant Energy, and even if we do, the resolution may
be less favorable than if we were dealing with an unaffiliated party.
Our executive officers and some of our directors own a substantial amount
of Reliant Energy common stock and options to purchase Reliant Energy common
stock. Ownership of Reliant Energy common stock by our directors and officers
after the Distribution could create, or appear to create, potential conflicts of
interest when directors and officers are faced with decisions that could have
different implications for Reliant Energy than they do for us.
We expect that even after the Distribution, two of our directors will also
be directors of Reliant Energy. One of these directors will be our chairman,
president and chief executive officer. These directors will owe fiduciary duties
to the stockholders of each company. As a result, in connection with any
transaction or other relationship involving both companies, these directors may
need to recuse themselves and to not participate in any board action relating to
these transactions or relationships.
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Adverse Tax Consequences. If we take actions which cause the Distribution
to fail to qualify as a tax-free transaction, we will be required to indemnify
Reliant Energy for any resulting taxes. Under an agreement with Reliant Energy,
if we breach any representation in the agreement relating to the IRS ruling that
Reliant Energy receives in connection with the Distribution, take any action
that causes our representations in the agreement relating to the ruling to be
untrue or engage in a transaction after the Distribution that causes the
Distribution to be taxable to Reliant Energy, we will be required to indemnify
Reliant Energy for any resulting taxes. The amount of any indemnification
payments could be substantial.
Current tax law provides that, depending on the facts and circumstances,
the Distribution may be taxable to Reliant Energy if we undergo a 50% or greater
change in stock ownership within two years after the Distribution. Under
agreements with Reliant Energy, Reliant Energy is entitled to require us to
reimburse any tax costs incurred by Reliant Energy as a result of a transaction
resulting in a change in control of our company. These costs may be so great
that they delay or prevent a strategic acquisition or change in control of our
company.
Deconsolidation from the Reliant Energy Consolidated Tax Group. Subsequent
to the Distribution, we will cease to be a member of the Reliant Energy
consolidated tax group. This separation will have both current and future income
tax implications to us. The event of deconsolidation itself will result in the
triggering of deferred intercompany gains. We will recognize taxable income
related to these gains, which will not have a material impact on our net income
and cash flow. In addition to the current income tax consequences triggered by
the act of deconsolidation discussed above, our separation from the Reliant
Energy consolidated tax group will change our overall future income tax posture.
As a result, we could be limited in our ability to effectively use future tax
attributes. We have agreed with Reliant Energy that we may carry back net
operating losses we generate in our tax years after deconsolidation to tax years
when we were part of the Reliant Energy consolidated group subject to Reliant
Energy's consent. Reliant Energy has agreed not to unreasonably withhold such
consent. Additionally, we may also be able to utilize such net operating losses
in our tax years after deconsolidation (subject to the applicable carryforward
limitation periods) but only to the extent of our income in such tax years.
OTHER FACTORS
Terrorist Attacks and Acts of War. We are currently unable to measure the
ultimate impact of the terrorist attacks of September 11, 2001 on our industry
and the United States economy as a whole. The uncertainty associated with the
retaliatory military response of the United States and other nations and the
risk of future terrorist activity may impact our results of operations and
financial condition in unpredictable ways. These actions could result in adverse
changes in the insurance markets and disruptions of power and fuel markets. In
addition, our generation facilities or the power transmission and distribution
facilities on which we rely could be directly or indirectly harmed by future
terrorist activity. The occurrence or risk of occurrence of future terrorist
attacks or related acts of war could also adversely affect the United States
economy. A lower level of economic activity could result in a decline in energy
consumption which could adversely affect our revenues, margins and limit our
future growth prospects. The occurrence or risk of occurrence could also
increase pressure to regulate or otherwise limit the prices charged for
electricity or gas. Also, these risks could cause instability in the financial
markets and adversely affect our ability to access capital.
Environmental Regulation. Our wholesale business is subject to extensive
environmental regulation by federal, state and local authorities. We are
required to comply with numerous environmental laws and regulations, and to
obtain numerous governmental permits, in operating our facilities. We may incur
significant additional costs to comply with these requirements. If we fail to
comply with these requirements, we could be subject to civil or criminal
liability and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to
us or our facilities, and future changes in environmental laws and regulations
could occur, including potential regulatory and enforcement developments related
to air emissions. If any of these events occur, our business, operations and
financial condition could be adversely affected.
We may not be able to obtain or maintain from time to time all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if we fail to obtain and comply
with them, the operation of our facilities could be prevented or become subject
to additional costs.
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We are generally responsible for all on-site liabilities associated with
the environmental condition of our power generation facilities which we have
acquired and developed, regardless of when the liabilities arose and whether
they are known or unknown. These liabilities may be substantial.
Holding Company Organizational Structure. All of our operations are
conducted by our subsidiaries. Our cash flow and our ability to service
parent-level indebtedness when due is dependent upon our receipt of cash
dividends, distributions or other transfers from our subsidiaries. The terms of
some of our subsidiaries' indebtedness restrict their ability to pay dividends
or make restricted payments to us in some circumstances. As of December 31,
2001, all of the specified conditions in these agreements were satisfied. Under
the credit agreements of certain of Orion Power's subsidiaries, these
subsidiaries are restricted from distributing cash to Orion Power.
In addition, the ability of REMA, our subsidiary that owns some of the
power generation facilities in our Northeast regional portfolio, to pay
dividends or make restricted payments to us is restricted under the terms of
three lease agreements under which we lease all or an undivided interest in
these generating facilities. These agreements allow our Mid-Atlantic subsidiary
to pay dividends or make restricted payments only if specified conditions are
satisfied, including maintaining specified fixed charge coverage ratios.
Liquidity Concerns. As of February 19, 2002, we have $2.9 billion of
credit facilities which will expire in 2002. To the extent that we continue to
need access to this amount of committed credit, we expect to extend or replace
these facilities. The current credit environment currently impacting our
industry may require our future facilities to include terms that are more
restrictive or burdensome or at higher borrowing rates than those of our current
facilities. In addition, the terms of any new credit facilities may be adversely
affected by any delay in the date of the Distribution. For a discussion of other
factors affecting our sources of cash and liquidity, please read "Liquidity and
Capital Resources."
LIQUIDITY AND CAPITAL RESOURCES
HISTORICAL CASH FLOWS
The net cash provided by or used in operating, investing and financing
activities for 1999, 2000 and 2001 is as follows (in millions).
YEAR ENDED DECEMBER 31,
-------------------------------------------
1999 2000 2001
------- ------- -------
Cash provided by (used in):
Operating activities ............ $ 35 $ 328 $ (127)
Investing activities ............ (1,406) (3,013) (838)
Financing activities ............ 1,408 2,721 1,000
Cash Provided by Operating Activities
Net cash provided by operating activities during 2001 decreased by $455
million compared to 2000. This decrease was primarily due to changes in working
capital and other changes in assets and liabilities. Changes in working capital
and other assets and liabilities in 2001 resulted in net cash outflows of
approximately $720 million primarily due to the following:
- a $409 million net cash outflow due to a reduction in accounts
payable partially offset by a reduction in accounts receivable and
net intercompany accounts receivable during 2001 due to the timing
of cash receipts and cash payments at our European Energy segment
and the payment of a significant gas payable by Wholesale Energy in
2001 which was accrued in 2000;
- a lease prepayment of $181 million related to the REMA
sale-leaseback agreements (please see Note 13(c) to our consolidated
financial statements);
- increased restricted cash of $117 million related to our REMA
operations (please see Note 2(j) to our consolidated financial
statements); and
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- increased deposits of $145 million in a collateral account related
to an equipment financing structure (please see Note 13(h) to our
consolidated financial statements);
- the foregoing items were partially offset by $167 million of reduced
net margin deposits on energy trading and hedging activities as a
result of reduced commodity volatility and relative price levels of
natural gas and power compared to the fourth quarter of 2000.
Changes in working capital and other assets and liabilities in 2000
resulted in net cash outflows of approximately $27 million primarily due to the
following:
- increased restricted cash of $50 million related to our REMA
operations;
- increased deposits of $85 million in a collateral account related to
an equipment financing structure;
- increased net margin deposits of $206 million on energy trading and
hedging activities as a result of increased commodity volatility and
relative price levels of natural gas and power in the fourth quarter
of 2000; and
- other changes in working capital;
- the foregoing items were partially offset by a $142 million net cash
inflow due to an increase in accounts payable partially offset by an
increase in accounts receivable and net intercompany accounts
receivable due to the timing of cash receipts and cash payments
related to a significant gas payable which was accrued in 2000 and
$123 million of proceeds from the sale of an investment in
marketable debt securities during 2000.
Cash flows from operations, excluding changes in working capital and other
changes in assets and liabilities, were approximately $593 million in 2001
compared to approximately $355 million in 2000. This increase was primarily due
to a $498 million increase in operating margins from Wholesale Energy's power
generation operations in 2001 compared to 2000. This increase was partially
offset by increased costs related to Retail Energy's increased staffing levels
and preparation for competition in the retail electric market in Texas and
reduced cash flows from our European Energy segment primarily resulting from a
decline in electric power generation gross margins as the Dutch electric market
was completely opened to wholesale competition on January 1, 2001.
Net cash provided by operating activities during 2000 increased by $293
million compared to 1999. This increase primarily resulted from proceeds from
the sale of an investment in marketable debt securities, improved operating
results of Wholesale Energy's California generating facilities, incremental cash
flows provided by REPGB, acquired in the fourth quarter of 1999, and cash flows
from the Mid-Atlantic generating facilities, acquired in the second quarter of
2000.
Cash Used in Investing Activities
Net cash used in investing activities decreased by $2.2 billion during
2001 compared to 2000. This decrease was primarily due to the funding of the
remaining purchase obligation for REPGB for $982 million on March 1, 2000, and
the acquisition of REMA for $2.1 billion on May 12, 2000, partially offset by
proceeds from the REMA sale-leaseback transactions of $1.0 billion, each as more
fully described below, partially offset by reduced capital expenditures of $93
million primarily by our Wholesale Energy segment partially offset by increased
capital expenditures by our Retail Energy segment related to acquiring and
developing information technology systems.
Net cash used in investing activities increased by $1.6 billion during
2000 compared to 1999. This increase was primarily due to the funding of the
remaining purchase obligation for REPGB for $982 million on March 1, 2000 and
the purchase of REMA for $2.1 billion on May 12, 2000, as well as increased
capital expenditures related to the construction of domestic power generation
projects. Proceeds of $1.0 billion from the REMA sale-leaseback partially offset
these increases, as well as 1999 payments related to the acquisition of REPGB
and a generating facility located in Florida.
Acquisition of REMA and REMA Sale-Leaseback. On May 12, 2000, we completed
the acquisition of REMA from Sithe Energies, Inc. for an aggregate purchase
price of $2.1 billion. The acquisition was originally financed
69
through bridge loans from Reliant Energy, of which $1.0 billion was converted to
equity. 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 REMA acquisition. As
consideration for the sale of our interest in the facilities, we received a
total of $1.0 billion in cash that we used to repay indebtedness owed by us to
Reliant Energy. For additional information about the acquisition and these
transactions, please read Notes 5(a) and 13(c) to our consolidated financial
statements.
Acquisition of REPGB. In the fourth quarter of 1999, we funded $833
million of the REPGB purchase obligation. On March 1, 2000, we funded the $982
million remaining REPGB 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 that matures in March 2003. For more
information about the acquisition, please read Notes 5(b) to our consolidated
financial statements.
Cash Used in/Provided by Financing Activities
Cash flows provided by financing activities decreased by $1.7 billion in
2001 compared to 2000, primarily due to a decrease in borrowings from Reliant
Energy coupled with advancing excess cash on a short-term basis to a subsidiary
of Reliant Energy which provides a cash management function for Reliant Energy,
reduced contributions from Reliant Energy, a decrease in long-term borrowings
and purchase of treasury stock during the second half of 2001. These items were
partially offset by an increase in short-term borrowings from third parties,
primarily used to fund Wholesale Energy's capital expenditures and for general
corporate purposes, and by $1.7 billion in net proceeds from the IPO.
Cash flows provided by financing activities increased by $1.3 billion in
2000 compared to 1999. The increase resulted primarily from an increase in
contributions from Reliant Energy and net proceeds from long-term debt from
third parties. We utilized the net borrowings incurred during 2000 to fund the
remaining REPGB purchase obligation, to fund the acquisition of REMA, to support
increased capital expenditures by Wholesale Energy and for general corporate
purposes.
Our Initial Public Offering. In May 2001, we offered 59.8 million shares
of our common stock to the public at an IPO price of $30 per share and received
net proceeds from the IPO of $1.7 billion. Pursuant to the terms of the Master
Separation Agreement with Reliant Energy, we used $147 million of the net
proceeds to repay certain indebtedness owed to Reliant Energy. We used the
remainder of the net proceeds of the IPO for repayment of third party
borrowings, capital expenditures, repurchase of common stock and to increase our
working capital. Proceeds not initially utilized from the IPO during 2001 were
advanced on a short-term basis to a subsidiary of Reliant Energy which provides
a cash management function for Reliant Energy. As of December 31, 2001, we have
$390 million of outstanding advances to this subsidiary of Reliant Energy. In
May 2001, prior to the closing of the IPO, Reliant Energy converted to equity or
contributed to us an aggregate of $1.7 billion of indebtedness owed by us to
Reliant Energy and it subsidiaries of which $35 million was related to accrued
intercompany interest expense. Following the IPO, Reliant Energy no longer
provided us financing or credit support, except for specified transactions or
for a limited period of time. For additional information, please read Note 4 to
our consolidated financial statements.
Treasury Stock Purchase. During 2001, we purchased 11 million shares of
our common stock at an average price of $17.22 per share, for an aggregate
purchase price of $189 million.
CONSOLIDATED CAPITAL REQUIREMENTS AND USES OF CASH
Our liquidity and capital requirements are affected primarily by the
results of operations, capital expenditures, debt service requirements and
working capital needs. We expect to grow through the construction of new
generation facilities and the acquisition of generation facilities, the
expansion of our energy trading and marketing activities and the expansion of
our energy retail business. We expect any resulting capital requirements to be
met with cash flows from operations, and proceeds from debt and equity
offerings, project financings, securitization of assets, other borrowings and
off-balance sheet financings. Additional capital expenditures, some of which may
be substantial, depend to a large extent upon the nature and extent of future
project commitments which are discretionary. In the
70
discussion below, we have provided several tables outlining our expected future
capital requirements by category of expenditure followed by more detailed
descriptions of the most significant of our currently known future capital
requirements and descriptions of known uncertainties that could impact these
items.
The following table sets forth our consolidated capital requirements for
2001, and estimates of our consolidated capital requirements for 2002 through
2006 (in millions).
2001 2002 2003 2004 2005 2006
------ ------ ------ ------ ------ ------
Wholesale Energy(1)(2)(3) .......... $ 658 $3,579 $ 322 $ 147 $ 215 $ 146
European Energy .................... 21 22 -- -- -- --
Retail Energy ...................... 117 40 19 18 14 16
Other Operations ................... 44 75 46 31 32 33
Major maintenance cash outlays ..... 88 94 87 106 86 85
------ ------ ------ ------ ------ ------
Total ......................... $ 928 $3,810 $ 474 $ 302 $ 347 $ 280
====== ====== ====== ====== ====== ======
- ----------
(1) Capital requirements for 2002 includes $2.9 billion for the acquisition of
Orion Power.
(2) In connection with our separation from Reliant Energy, Reliant Energy has
granted us an option, subject to completion of the Distribution, to
purchase all of the shares of capital stock owned by Reliant Energy in
January 2004 of an entity (Texas Genco) that will hold the Texas
generating assets of Reliant Energy's electric utility division. This
option may be exercised between January 10, 2004 and January 24, 2004. The
purchase of Texas Genco has been excluded from the above table. For
additional information regarding this option to purchase Texas Genco,
please read Note 4(b) to our consolidated financial statements.
(3) We currently estimate the capital expenditures by off-balance sheet
special purpose entities to be $704 million, $343 million, $163 million
and $48 million in 2002, 2003, 2004 and 2005, respectively. Capital
expenditures for these projects have been excluded from the table above.
Please read "-- Off-Balance Sheet Transactions -- Construction Agency
Agreements" and "-- Equipment Financing Structure" for additional
information regarding these transactions.
Acquisition of Orion Power. On February 19, 2002, we acquired all of the
outstanding shares of common stock of Orion Power for $26.80 per share in cash
for an aggregate purchase price of $2.9 billion. As of February 19, 2002, Orion
Power's debt obligations were $2.4 billion ($2.1 billion net of cash acquired,
some of which is restricted pursuant to debt covenants). We funded the purchase
of Orion Power with a $2.9 billion credit facility (Orion Bridge Facility) and
$41 million of cash on hand. Please read "-- Consolidated Sources of Cash --
Orion Bridge Facility" for further information.
Generating Projects. As of December 31, 2001, we had three generating
facilities under construction. Total estimated costs of constructing these
facilities are $1.1 billion, including $304 million in commitments for the
purchase of combustion turbines. As of December 31, 2001, we had incurred $690
million of the total projected costs of these projects, which were funded
primarily from equity and debt facilities. In addition, we have options to
purchase additional combustion turbines for a total estimated cost of $42
million. We are actively attempting to market these turbines, having determined
that they are in excess of our current needs. In addition to these facilities,
we are constructing facilities as construction agents under construction agency
agreements under synthetic leasing arrangements, which permit us to lease or buy
each of these facilities at the conclusion of their construction. For more
information regarding the construction agency agreements, please read "--
Off-Balance Sheet Transactions -- Construction Agency Agreements."
Environmental Expenditures. We anticipate investing up to $135 million in
capital and other special project expenditures between 2002 and 2006 for
environmental compliance, totaling approximately $53 million, $20 million, $9
million, $29 million and $24 million in 2002, 2003, 2004, 2005 and 2006,
respectively, which is included in the above table. Additionally, environmental
capital expenditures for the recently acquired Orion Power assets were estimated
by Orion Power to be approximately $241 million over the same time period. We
are currently reviewing Orion Power's estimates.
71
The following table sets forth estimates of our consolidated contractual
obligations as of December 31, 2001 to make future payments for 2002 through
2006 and thereafter (in millions):
2007 AND
CONTRACTUAL OBLIGATIONS TOTAL 2002 2003 2004 2005 2006 THEREAFTER
- ----------------------- ------ ------ ------ ------ ------ ------ ----------
Long-term debt ........................................ $ 892 $ 24 $ 539 $ 42 $ 12 $ 12 $ 263
Short-term borrowing, including credit facilities ..... 297 297 -- -- -- -- --
Mid-Atlantic generating assets operating lease
payments ........................................... 1,560 136 77 84 75 64 1,124
Other operating lease payments ........................ 859 52 72 87 89 90 469
Trading and marketing liabilities ..................... 1,840 1,478 216 85 33 13 15
Non-trading derivative liabilities .................... 853 323 115 80 61 35 239
Other commodity commitments ........................... 3,134 465 242 207 207 207 1,806
Other long-term obligations ........................... 300 10 10 10 10 10 250
------ ------ ------ ------ ------ ------ ------
Total contractual cash obligations ................. $9,735 $2,785 $1,271 $ 595 $ 487 $ 431 $4,166
====== ====== ====== ====== ====== ====== ======
Long-term debt obligations as of December 31, 2001, include $829 million
of borrowings under credit facilities that have been classified as long-term
debt, based upon the availability of committed credit facilities and
management's intention to maintain these borrowings in excess of one year.
As of December 31, 2001, we have issued $396 million of letters of credit
of which $345 million were issued under two credit facilities expiring in 2003
and $51 million were issued under a credit facility expiring in 2004.
Mid-Atlantic Assets Lease Obligation. 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
REMA acquisition. As lessee, we lease 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 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, including having a
credit rating on its long-term unsecured senior debt of at least BBB from
Standard & Poor's and Baa2 from Moody's, guarantees the lease obligations. For
additional discussion of these lease transactions, please read Notes 5(a) and
13(c) to our consolidated financial statements. We expect to make lease payments
through 2029 under these leases, with total cash payments of $1.6 billion. The
lease terms expire in 2034. During 2000 and 2001, we made cash lease payments
totaling $1 million and $259 million, respectively.
Other Operating Lease Commitments. For a discussion of other operating
leases, please read Note 13(c) to our consolidated financial statements.
Other Commodity Commitments. For a discussion of other commodity
commitments, please read Note 13(a) to our consolidated financial statements.
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 thirty-second franchise. The agreement extends for 31 years.
The aggregate undiscounted cost of the naming rights under this agreement is
expected to be $300 million. Starting in 2002, when the new stadium is
operational, we will pay $10 million each year through 2032 for annual
advertising under this agreement. For additional information on the naming
rights agreement, please read Note 13(a) to our consolidated financial
statements.
Payment to Reliant Energy. To the extent that our price for providing
retail electric service to residential and small commercial customers in Reliant
Energy's Houston service territory during 2002 and 2003, which price is mandated
by the Texas electric restructuring law, exceeds the market price of
electricity, we will be required to make a payment to Reliant Energy in early
2004. For discussion of possible payment, please read Note 13 (g) to our
72
consolidated financial statements. Due to the nature of this possible payment,
we currently cannot reasonably estimate this payment, accordingly it is excluded
from the above table.
Treasury Stock Purchases. On December 6, 2001, our Board of Directors
authorized us to purchase up to 10 million additional shares of common stock
through June 2003. Purchases will be made on a discretionary basis in the open
market or otherwise at times and in amounts as determined by management subject
to market conditions, legal requirements and other factors. Since the date of
such authorization through April 1, 2002, we have not purchased any of these
shares of our common stock under this program.
In addition to the capital requirements discussed above, the following
items, among others, could impact our future capital requirements.
Downgrade in our Credit Rating. In accordance with industry practice, we
have entered into commercial contracts or issued guarantees related to our
trading, marketing and risk management operations that require us to maintain an
investment grade credit rating. If one or more of our credit ratings decline
below investment grade, we may be obligated to provide additional or other
credit support to the guaranteed parties in the form of a pledge of cash
collateral, a letter of credit or other similar credit support.
Counterparty Credit Risk. We are exposed to the risk that counterparties
who owe us money or physical commodities, such as energy or gas, as a result of
market transactions fail to perform their obligations. Should the counterparties
to these arrangements fail to perform, we might incur losses if we are forced to
acquire alternative hedging arrangements or replace the underlying commitment at
then-current market prices. In addition, we might incur additional losses to the
extent of amounts, if any, already paid to the defaulting counterparties.
CONSOLIDATED SOURCES OF CASH
We believe that our current level of cash and borrowing capability, along
with our future anticipated cash flows from operations and assuming successful
refinancings of credit facilities as they mature, will be sufficient to meet the
existing operational needs of our business for the next 12 months. If cash
generated from operations is insufficient to satisfy our liquidity requirements,
we may seek to sell either equity or debt securities or obtain additional credit
facilities or long-term financings from financial institutions. In the
discussion below, we have provided a description of the significant factors that
could impact our cash flows from operations, our currently available liquidity
sources, currently contemplated future liquidity sources and known uncertainties
that could impact these sources.
The following items will affect our future cash flows from operations:
Reliant Resources Restricted Cash. Covenants under the Mid-Atlantic assets
lease, discussed above, restrict REMA's ability to make dividend distributions.
The restricted cash is available for REMA's working capital needs and for it to
make future lease payments. As of December 31, 2001, REMA had $167 million of
restricted cash. We currently anticipate that REMA will be able to satisfy the
conditions necessary to distribute these restricted funds in 2002. In addition,
the terms of two of our subsidiaries' indebtedness restrict their ability to pay
dividends or make restricted payments to us in some circumstances. Specifically,
our subsidiary which holds an electric power generation facility in Channelview,
Texas (Channelview) and our subsidiary which holds an equity investment in the
entity owning and operating an electric power generation facility in Nevada (El
Dorado) are each party to credit agreements used to finance construction of
their generating plants. Both the Channelview credit agreement and the El Dorado
credit agreement allow the respective subsidiary to pay dividends or make
restricted payments only if specified conditions are satisfied, including
maintaining specified debt service coverage ratios and debt service reserve
account balances. In both cases, the amount of the dividends or restricted
payments that may be paid if the conditions are met is limited to a specified
level and may be paid only from a particular account.
Orion Power Restricted Cash. Substantially all of Orion Power's operations
are conducted by its subsidiaries. The terms of some of its subsidiaries'
indebtedness restrict their ability to pay dividends to Orion Power or us.
Restricted funds are available for such subsidiaries to make debt service
payments and to meet their working capital needs. In addition, covenants under
some indebtedness of Orion Power restrict its ability to pay dividends to us
unless Orion Power meets certain conditions, including the ability to incur
additional indebtedness without violating
73
the required fixed charge coverage ratio of 2.0 to 1.0. A credit facility of
Orion Power also restricts its ability to pay dividends to us unless the
restrictions contained in certain of its subsidiaries' credit agreements have
terminated and no restrictions remain under their credit agreements.
California Trade Receivables. As of December 31, 2001, we were owed $302
million by the Cal ISO, the California Power Exchange (Cal PX) and the
California Department of Water Resources (CDWR) and California Energy Resource
Scheduling for energy sales in the California wholesale market, during the
fourth quarter of 2000 through December 31, 2001 and have recorded an allowance
against such receivables of $68 million. From January 1, 2002 through March 26,
2002, we have collected $45 million of these receivable balances. For additional
information regarding uncertainties in the California wholesale market, please
read Notes 13(e) and 13(i) to our consolidated financial statements.
Other Items. For other items that may affect our future cash flows from
operations, please read "-- Certain Factors Affecting Future Earnings."
The following discussion summarizes our currently available liquidity
sources and material factors that could impact that availability.
Credit Facilities. The following table provides a summary of the amounts
owed and amounts available under our various credit facilities (in millions).
TOTAL EXPIRING BY
COMMITTED DRAWN LETTERS OF UNUSED DECEMBER 31,
CREDIT AMOUNT CREDIT AMOUNT 2002(1)
--------- ------ ---------- ------ ------------
Reliant Resources, as of December 31, 2001 ....... $5,563 $1,078 $396 $4,089 $1,114
Orion Power, as of February 19, 2002 ............. 2,028 1,827 95 106 1,736
------
Total ......................................... $2,850
======
- ----------
(1) Excludes $383 million of facilities expiring in November 2002 as
borrowings under such facilities are convertible into a long-term loan.
As of February 19, 2002, we have $2.9 billion of credit facilities which
will expire in 2002. To the extent that we continue to need access to this
amount of committed credit, we expect to extend or replace these facilities. The
current credit environment currently impacting our industry may require our
future facilities to include terms that are more restrictive or burdensome or at
higher borrowing rates than those of our current facilities.
Reliant Resources Credit Facilities Covenants. As of December 31, 2001,
we, including certain of our subsidiaries, had committed credit facilities of
$5.6 billion. Of these facilities, $5.0 billion contain various business and
financial covenants requiring us to, among other things, maintain a ratio of net
balance sheet debt to the sum of net balance sheet debt, subordinated affiliate
balance sheet debt and stockholders' equity not to exceed 0.60 to 1.00. These
covenants are not anticipated to materially restrict us from borrowing funds or
obtaining letters of credit under these facilities. The remaining credit
facilities of $0.6 billion, which were held by certain of our domestic power
generation subsidiaries, contain various business and financial covenants that
are typical for limited or non-recourse project financings. Such covenants
include restrictions on dividends and capital expenditures, as well as
requirements regarding insurance, approval of operating budgets and commercial
contracts. These covenants are not anticipated to materially restrict us from
borrowing funds or obtaining letters of credit under our credit facilities. None
of the above committed bank credit facilities have any defaults or prepayments
triggered by changes in credit ratings, or in any way linked to the price of our
common stock or any other traded instrument.
For additional information regarding the terms and related interest rates
of these credit facilities, please read Note 8 of our consolidated financial
statements.
Orion Power Credit Facilities. The credit facilities of Orion Power and
its subsidiaries contain various business and financial covenants that are
typical for limited or non-recourse project financings. Such covenants include
restrictions on dividends and capital expenditures, as well as requirements
regarding insurance, approval of operating budgets and commercial contracts.
These include covenants that require two of Orion Power's significant
74
subsidiaries which have credit facilities with outstanding borrowings of $1.6
billion as of December 31, 2001, to, among other things, maintain a debt service
coverage ratio of at least 1.5 to 1.0 and for Orion Power, which has a $75
million credit facility, to, among other things, maintain a debt service
coverage ratio of at least 1.4 to 1.0. One of the subsidiaries may not be able
to meet this debt service coverage ratio for the quarter ended June 30, 2002,
and Orion Power did not meet the debt service coverage ratio for the quarter
ended March 31, 2002. In the event that Orion Power is unable to meet this
financial covenant for a second consecutive fiscal quarter it would constitute a
default under its credit facility. It is our current intention to arrange for
the repayment, refinancing or amendment of these facilities prior to June 30,
2002. If these facilities are not repaid, refinanced or amended prior to that
date, and if a waiver is required under either or both of these credit
facilities, we believe that we will be able to obtain such a waiver on or prior
to June 30, 2002. However, we currently have no assurance that we will be able
to obtain such a waiver or amendment from the respective lender groups if
required under either or both of these credit facilities.
Orion Bridge Facility. In November 2001, we entered into a $2.2 billion
term loan facility to be utilized for the acquisition of Orion Power. In January
2002, the facility was increased to $2.9 billion. On February 19, 2002, in
connection with the Orion Power acquisition we borrowed $2.9 billion under the
Orion Bridge Facility, which is required to be repaid on or before February 19,
2003.
Potential Future Liquidity Sources. We are currently considering pursuing
the following sources of cash to meet our future capital requirements.
Commercial Paper Program. We plan to commence a commercial paper program
in 2002, which will be supported by our existing credit facilities. Although we
have not yet determined the size of such program, we do not expect that it would
exceed $300 million initially, due to market conditions and our current credit
ratings. To the extent that we are not successful in placing commercial paper
consistently, we will borrow directly under our existing credit facilities.
Debt Securities in the Capital Markets. As part of refinancing the Orion
Bridge Facility, we currently expect that we will issue various fixed and
floating rate debt securities in 2002 having maturities up to ten years or
greater depending upon market conditions. We expect to offer debt securities in
the amount of $2.5 to $3.0 billion, depending on market conditions. Our ability
to complete such debt offerings in the capital markets will depend on our future
performance and prevailing market conditions. This Form 10-K does not constitute
an offer to sell or the solicitation of an offer to buy our debt securities.
Settlement of Indemnification of REPGB Stranded Costs. In December 2001,
REPGB and its former shareholders entered into a settlement agreement resolving
the former shareholders' stranded cost indemnity obligations under the purchase
agreement of REPGB. Under the settlement agreement, the former shareholders paid
to REPGB NLG 500 million ($202 million based on an exchange rate of 2.48 NLG per
U.S. dollar as of December 31, 2001) in January and February 2002. In addition,
under the settlement agreement, the former shareholders waived all rights under
the original indemnification agreement to claim distributions from NEA, a 22.5%
owned equity investment. We estimate that there will be future distributions
from 2002 through 2005 from NEA to REPGB totaling approximately $299 million.
For additional information regarding the settlement agreement, our investment in
NEA and indemnification of district heat contract obligations, please read Note
13(f) to our consolidated financial statements.
Factors Affecting Our Sources of Cash and Liquidity. As a result of
several recent events, including the United States economic recession, the price
decline of the common stock of participants in our industry sector and the
downgrading of the credit ratings of several of our significant competitors, the
availability and cost of capital for our business and the businesses of our
competitors have been adversely affected. Any future acquisition or development
projects will likely require us to access substantial amounts of capital from
outside sources on acceptable terms. We may also need external financing to fund
capital expenditures, including capital expenditures necessary to comply with
air emission regulations or other regulatory requirements. If we are unable to
obtain outside financing to meet our future capital requirements on terms that
are acceptable to us, our financial condition and future results of operations
could be materially adversely affected. In order to meet our future capital
requirements we may increase the proportion of debt in our overall capital
structure. Increases in our debt levels may adversely affect our credit ratings
thereby increasing the cost of our debt. In addition, the capital constraints
currently impacting our industry may require our future indebtedness to include
terms and or pricing that are more restrictive or burdensome than
75
those of our current indebtedness. This may negatively impact our ability to
operate our business, or severely restrict or prohibit distributions from our
subsidiaries.
Our ability to arrange financing, including refinancing, and our cost of
capital are dependent on the following factors:
- general economic and capital market conditions,
- maintenance of acceptable credit ratings,
- credit availability from banks and other financial institutions,
- investor confidence in us, our competitors and peer companies and
our wholesale power markets,
- market expectations regarding our future earnings and probable cash
flows,
- market perceptions of our ability to access capital markets on
reasonable terms,
- the success of current power generation projects,
- the perceived quality of new power generation projects, and
- provisions of relevant tax and securities laws.
Credit Ratings. Our credit ratings for our senior unsecured debt are as
follows:
DATE ASSIGNED RATING AGENCY RATING
- ------------- ------------- ------
March 22, 2002 Moody's Baa3, stable
February 14, 2002 Fitch (1) BBB, negative outlook
March 21, 2002 Standard & Poor's BBB, stable
- ----------
(1) Fitch assigned a negative rating outlook to reflect its analysis of our
plan for financing and integrating the acquisition of Orion Power.
We cannot assure you that these ratings will remain in effect for any
given period of time or that one or more of these ratings will not be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities and may be revised or
withdrawn at any time by rating agency. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to access capital on acceptable terms. We have commercial contracts and/or
guarantees related to our trading, marketing and risk management and hedging
operations that require us to maintain an investment grade credit rating. If our
credit rating declines below investment grade, we estimate that we could be
obligated to provide significant credit support to the counterparties in the
form of a pledge of cash collateral, a letter of credit or other similar credit
support.
Furthermore, if our credit ratings decline below an investment grade
credit rating, our trading partners may refuse to trade with us or trade only on
terms less favorable to us. As of December 31, 2001, we had $214 million of
margin deposits on energy trading and hedging activities posted as collateral
with counterparties. As of December 31, 2001, we had $1.5 billion available
under our credit facilities to satisfy future commodity obligations.
OFF-BALANCE SHEET TRANSACTIONS
Construction Agency Agreements. In 2001, we, through several of our
subsidiaries, entered into operative documents with special purpose entities to
facilitate the development, construction, financing and leasing of several power
generation projects. The special purpose entities are not consolidated by us.
The special purpose entities have an aggregate financing commitment from equity
and
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debt participants (Investors) of $2.5 billion of which the last $1.1 billion is
currently available only if cash collateralized. The availability of the
commitment is subject to satisfaction of various conditions, including the
obligation to provide cash collateral for the loans and letters of credit
outstanding on November 27, 2004. We, through several of our subsidiaries, act
as construction agent for the special purpose entities and are responsible for
completing construction of these projects by December 31, 2004, but we have
generally limited our risk during construction to an amount not in excess of
89.9% of costs incurred to date, except in certain events. Upon completion of an
individual project and exercise of the lease option, our subsidiaries will be
required to make lease payments in an amount sufficient to provide a return to
the Investors. If we do not exercise our option to lease any project upon its
completion, we must purchase the project or remarket the project on behalf of
the special purpose entities. Our ability to exercise the lease option is
subject to certain conditions. We must guarantee that the Investors will receive
an amount at least equal to 89.9% of their investment in the case of a
remarketing sale at the end of construction. At the end of an individual
project's initial operating lease term (approximately five years from
construction completion), our subsidiary lessees have the option to extend the
lease with the approval of Investors, purchase the project at a fixed amount
equal to the original construction cost, or act as a remarketing agent and sell
the project to an independent third party. If the lessees elect the remarketing
option, they may be required to make a payment of an amount not to exceed 85% of
the project cost, if the proceeds from remarketing are not sufficient to repay
the Investors. We have guaranteed the performance and payment of our
subsidiaries' obligations during the construction periods and, if the lease
option is exercised, each lessee's obligations during the lease period. At
anytime during the construction period or during the lease, we may purchase a
facility by paying an amount approximately equal to the outstanding balance plus
costs. As of December 31, 2001, the special purpose entities had property, plant
and equipment of $428 million, net other assets of $52 million, which were
primarily restricted cash, and debt obligations of $465 million. As of December
31, 2001, the special purpose entities had equity from unaffiliated third
parties of $15 million. We currently estimate the aggregate cost of the three
generating facilities that are currently under construction by the special
purpose entities to be approximately $1.8 billion
Equipment Financing Structure. We, through our subsidiary, REPG, have
entered into an agreement with a bank whereby the bank, as owner, entered or
will enter into contracts for the purchase and construction of power generation
equipment and REPG, or its subagent, acts as the bank's agent in connection with
administering the contracts for such equipment. Under the agreement, the bank
has agreed to provide up to a maximum aggregate amount of $650 million. REPG and
its subagents must cash collateralize their obligation to administer the
contracts. This cash collateral is approximately equivalent to the total
payments by the bank for the equipment, interest and other fees. As of December
31, 2001, the bank had assumed contracts for the purchase of eleven turbines,
two heat recovery steam generators and one air cooled condenser with an
aggregate cost of $398 million. REPG, or its designee, has the option at any
time to purchase or, at equipment completion, subject to certain conditions,
including the agreement of the bank of extend financing, to lease the equipment,
or to assist in the remarketing of the equipment under terms specified in the
agreement. All costs, including the purchase commitment on the turbines, are the
responsibility of the bank. The cash collateral is deposited by REPG or an
affiliate into a collateral account with the bank and earns interest at the
London inter-bank offered rate (LIBOR) less 0.15%. Under certain circumstances,
the collateral deposit or a portion of it will be returned to REPG or its
designee. Otherwise, it will be retained by the bank. At December 31, 2001, REPG
and its subsidiary had deposited $230 million into the collateral account. The
bank's payments for equipment under the contracts totaled $227 million as of
December 31, 2001. In January 2002, the bank sold to the parties to the
construction agency agreements discussed above, equipment contracts with a total
contractual obligation of $258 million under which payments and interest during
construction totaled $142 million. Accordingly, $142 million of our collateral
deposits were returned to us. As of December 31, 2001, there were equipment
contracts with a total contractual obligation of $140 million under which
payments during construction totaled $83 million. Currently this equipment is
not designated for current planned power generation construction projects.
Therefore, we anticipate that we will either purchase the equipment, assist in
the remarketing of the equipment or negotiate to cancel the related contracts.
77
NEW ACCOUNTING PRONOUNCEMENTS AND CRITICAL ACCOUNTING POLICIES
NEW ACCOUNTING PRONOUNCEMENTS
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and
Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method of accounting and broadens the criteria for recording intangible
assets separate from goodwill. Recorded goodwill and intangibles will be
evaluated against these new criteria and may result in certain intangibles being
transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. SFAS
No. 142 provides for a nonamortization approach, whereby goodwill and certain
intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and written
down and charged to results of operations only in the periods in which the
recorded value of goodwill and certain intangibles with indefinite lives is more
than its fair value. We adopted the provisions of each statement which apply to
goodwill and intangible assets acquired prior to June 30, 2001 on January 1,
2002. The adoption of SFAS No. 141 did not have a material impact on our
historical results of operations or financial position. On January 1, 2002, we
discontinued amortizing goodwill into our results of operations pursuant to SFAS
No. 142. We recognized $32 million of goodwill amortization expense in our
statement of consolidated income during 2001, excluding a $19 million write-off
of our Communications business goodwill balance which was recorded as goodwill
amortization expense (please read Note 16 to our consolidated financial
statements). We are in the process of determining further effects of adoption of
SFAS No. 142 on our consolidated financial statements, including the review of
goodwill and certain intangibles for impairment. We have not completed our
review pursuant to SFAS No. 142. However, based on our preliminary review, we
believe an impairment of our European Energy segment goodwill is reasonably
possible. As of December 31, 2001, net goodwill associated with our European
Energy segment is $632 million. We anticipate finalizing our review of goodwill
and certain intangibles for our reporting units during 2002. We do not believe
impairments of goodwill and certain intangibles, if any, related to our other
reporting units will have a material impact on our results of operations or
financial position.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
a liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. We plan to adopt SFAS No. 143 on
January 1, 2003 and are in the process of determining the effect of adoption on
our consolidated financial statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No.
30 "Reporting the Results of Operations -- Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 is not expected to materially change the
methods used by us to measure impairment losses on long-lived assets, but may
result in additional future dispositions being reported as discontinued
operations than is currently permitted. We adopted SFAS No. 144 on January 1,
2002.
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Effective January 1, 2001, we adopted SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities" (SFAS No. 133), as amended. The
application of SFAS No. 133 is still evolving as the FASB clears issues
submitted to the Derivatives Implementation Group for consideration. During the
second quarter of 2001, an issue that applies exclusively to the electric
industry and allows the normal purchases and normal sales exception for
option-type contracts if certain criteria are met was approved by the FASB with
an effective date of July 1, 2001. The adoption of this cleared guidance had no
impact on our results of operations. Certain criteria of this previously
approved guidance were revised in October 2001 and December 2001 and will become
effective on April 1, 2002. We are currently in the process of determining the
effect of adoption of this revised guidance.
During the third quarter of 2001, the FASB cleared an issue related to
application of the normal purchases and normal sales exception to contracts that
combine forward and purchased option contracts. The effective date of this
guidance is April 1, 2002, and we are currently assessing the impact of this
recently cleared issue and do not believe it will have a material impact on our
consolidated financial statements.
During the first quarter of 2002, the FASB considered proposed approaches
related to identifying and accounting for special-purpose entities. The current
proposal being considered by the FASB is likely to limit special purpose
entities used by a company for financing and other purpose not being
consolidated with its results of operations. One criterion being considered is
to require consolidation of a special purposes entity if the equity investments
held by third-party owners in the special purposes entity is less than 10% of
total capitalization. The FASB likely will not grandfather special purpose
entities existing at the date the final interpretation is issued. Special
purpose entities in existence at the date of adoption of this interpretation
will likely be consolidated by the primary beneficiary. For information
regarding special purposes entities affiliated with us, please read "--
Liquidity and Capital Resources -- Off-Balance Sheet Transactions" and Notes
13(c) and (h) to our consolidated financial statements.
CRITICAL ACCOUNTING POLICIES
A critical accounting policy is one that is both important to the
portrayal of our financial condition and results of operations and requires
management to make difficult, subjective or complex judgments. The circumstances
that make these judgments difficult, subjective and/or complex have to do with
the need to make estimates about the effect of matters that are inherently
uncertain. Estimates and assumptions about future events and their effects
cannot be perceived with certainty. We base our estimates on historical
experience and on various other assumptions that are believed to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes.
We believe the following are the most significant estimates used in the
preparation of our consolidated financial statements.
- determination of fair value of trading and marketing assets and
liabilities for our energy trading, marketing and price risk
management services operations, and non-trading derivative assets
and liabilities, including stranded costs obligations related to our
European Energy operations (please read "-- Trading and Marketing
Operations" and "Quantitative and Qualitative Disclosures About
Market Risk" in Item 7A of this Form 10-K and Notes 2(d) and 6 to
our consolidated financial statements); and
- impairment of long-lived assets and intangibles (please read
"European Energy" and Notes 2(f) and 2(q) to our consolidated
financial statements).
For a description of all significant accounting policies, please read Note
2 to our consolidated financial statements.
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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
MARKET RISK
We are exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
our consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risks
include exposures to commodity prices through trading and marketing and
non-trading activities, interest rates, foreign currency exchange rates and
equity prices. A description of each market risk category is set forth below:
- Commodity price risk results from exposures to changes in spot
prices, forward prices and price volatilities of commodities, such
as electricity, natural gas and other energy commodities.
- Interest rate risk primarily results from exposures to changes in
the level of borrowings and changes in interest rates.
- Currency rate risk results from exposures to changes in the value of
foreign currencies relative to our reporting currency, the U.S.
dollar, and exposures to changes in currency rates in transactions
executed in currencies other than a business segment's reporting
currency.
- Equity price risk results from exposures to changes in prices of
individual equity securities.
We seek to manage these risk exposures through the implementation of our
risk management policies and framework. We seek to manage our exposures through
the use of derivative financial instruments and derivative commodity
instruments. During the normal course of business, we review our hedging
strategies and determine the hedging approach we deem appropriate based upon the
circumstances of each situation.
Derivative instruments are financial instruments, such as futures, forward
contracts, swaps or options, that derive their value from underlying assets,
indices, reference rates or a combination of these factors. These derivative
instruments include negotiated contracts, which are referred to as
over-the-counter derivatives, and instruments that are listed and traded on an
exchange.
Our trading operations enter into derivative instrument transactions as a
means of risk management, optimization of our current power generation asset
position, and to take a market position. Derivative instrument transactions are
entered into in our non-trading operations to manage and hedge certain
exposures, such as exposure to changes in electricity and fuel prices, exposure
to interest rate risk on our floating-rate borrowings and foreign currency
exposures related to our foreign investments. We believe that the associated
market risk of these instruments can best be understood relative to the
underlying assets or risk being hedged and our trading strategy.
TRADING MARKET RISK
Trading and marketing operations often involve market risk associated with
managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis, through derivative instruments
(Trading Energy Derivatives). Our trading and marketing businesses depend on
price movements and volatility levels to create business opportunities, but
these businesses must control risk within authorized limits.
We assess the risk of Trading Energy Derivatives using a value-at-risk
(VAR) method, in order to maintain our total exposure within authorized limits.
VAR is the potential loss in value of trading positions due to adverse market
movements over a defined time period within a specified confidence level. We
utilize the variance/covariance model of VAR, which relies on statistical
relationships to describe how changes in different markets can affect a
portfolio of instruments with different characteristics and market exposures.
For the VAR numbers reported below, a one-day holding period and a 95%
confidence level were used, except for our European trading operations which
uses a two-day to five-day holding period. This means that if VAR is calculated
at $10 million, we may state that there is a one in 20 chance that if prices
move against our consolidated
80
diversified positions, our pre-tax loss in liquidating or offsetting with hedges
our portfolio in a one-day period would exceed $10 million.
The VAR methodology employs a seasonally adjusted volatility-based
approach with the following critical parameters: forward prices and volatility
estimates, appropriate market-oriented holding periods and seasonally adjusted
correlation estimates. We use the delta approximation method for reporting
option positions. 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. An inherent limitation of
VAR is that past changes in market risk may not produce accurate predictions of
future market risk. Moreover, VAR calculated for a one-day holding period does
not fully capture the market risk of positions that cannot be liquidated or
offset with hedges within one day. We cannot assure you that market volatility,
failure of counterparties to meet their contractual obligations, future
transactions or a failure of risk controls will not lead to significant losses
from our trading, marketing and risk management activities.
While we believe that our assumptions and approximations are reasonable
for calculating VAR, there is no uniform industry methodology for estimating
VAR, and different assumptions and/or approximations could produce materially
different VAR estimates.
Our VAR limits are set by our Board of Directors, as further discussed
below. Violations in overall VAR limits are required to be reported to the Audit
Committee of our Board of Directors pursuant to our corporate-wide risk limit
parameters. For further discussion on our risk management framework, please read
"-- Risk Management Structure" below.
The following presents the daily VAR for substantially all of our Trading
Energy Derivative positions (in millions).
2000 2001
---- ----
As of December 31, .............. $15 $27
Year Ended December 31:
Average .................... 6 9
High ....................... 36 27
Low ........................ 1 3
The following chart presents the daily VAR for substantially all of our
Trading Energy Derivatives during 2001 (in millions).
COMBINED DOMESTIC AND EUROPEAN VAR
FOR THE YEAR ENDED DECEMBER 31, 2001
(PERFORMANCE GRAPH)
YEAR ENDED
DECEMBER 31, 2001
--------------------------------------------
WHOLESALE EUROPE RETAIL TOTAL
--------- -------- --------- ---------
First Quarter.................................... 5.040953 0.976000 6.016953
Second Quarter................................... 7.938367 0.838000 8.776367
Third Quarter.................................... 4.785587 0.832000 5.617587
Fourth Quarter................................... 8.714555 0.551000 17.785732 27.051287
During the beginning of 2001, the high VAR levels were due to high natural
gas and power prices and volatility levels, which continued from late 2000. VAR
exposure was lower in the second and third quarters of 2001 due to the
significant decline in natural gas and power prices and volatility levels.
During the fourth quarter of 2001, VAR levels increased due to increased power
marketing activities in ERCOT related to our Retail Energy segment.
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NON-TRADING MARKET RISK
Commodity Price Risk
Commodity price risk is an inherent component of our electric power
generation businesses because the profitability of our generation assets depends
significantly on commodity prices sufficient to create gross margin. During
2001, the majority of our non-trading commodity price risk was related to our
electric power generation businesses. Prior to the energy delivery period, we
attempt to hedge, in part, the economics of our electric power facilities by
selling power and purchasing equivalent fuel. Some power capacity is held in
reserve and sold in the spot market. Derivative instruments are used to mitigate
exposure to variability in future cash flows from probable, anticipated future
transactions attributable to a commodity risk. In this way, more certainty is
provided as to the financial contribution associated with the operation of these
assets. Beginning in 2002, our commodity price risk exposures related to our
Retail Energy operations increased, as we began to provide retail electric
services to all customers of Reliant Energy's electricity utility division who
did not select another retail electric provider. For a discussion of risk
factors affecting our Retail Energy operations, please read "Management's
Discussion and Analysis of Financial Condition and Results of Operations --
Certain Factors Affecting Our Future Earnings -- Factors Affecting the Results
of Our Retail Energy Operations" in Item 7 of this Form 10-K.
Derivative instruments, which we use as economic hedges, create exposure
to commodity prices, which we use to offset the commodity exposure inherent in
our businesses. The stand-alone commodity risk created by these instruments,
without regard to the offsetting effect of the underlying exposure these
instruments are intended to hedge, is described below. We measure the commodity
risk of our non-trading derivatives (Non-trading Energy Derivatives) using a
sensitivity analysis. The sensitivity analysis performed on our Non-trading
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, 2001 levels would have
decreased the fair value of our Non-trading Energy Derivatives by $52 million,
excluding non-trading derivatives liabilities associated with our European
Energy segment's stranded cost import contracts.
The above analysis of the Non-trading 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
Non-trading Energy Derivative portfolio, excluding the stranded cost import
contracts, is managed to complement the physical transaction portfolio, thereby
reducing overall risks within limits. Therefore, the adverse impact to the fair
value of the portfolio of Non-trading 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 Non-trading Energy Derivatives are not closed out in advance of
their expected term,
- the Non-trading 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
derivative 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. Non-trading Energy Derivatives intended as hedges, and
which are effective as hedges, may still have some percentage which is not
effective. The change in value of the Non-trading Energy Derivatives which
represents the ineffective component of the hedges, is recorded in our results
of operations. During 2001, we recognized revenues of $8 million in our
statement of consolidated income due to hedge ineffectiveness.
Our European Energy segment's stranded cost import contracts have exposure
to commodity prices. For information regarding these contracts, please read
Notes 6(b) and 13(f) our consolidated financial statements. A decrease of 10% in
market prices of energy commodities from their December 31, 2001 levels would
result in a loss of earnings of $98 million.
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Interest Rate Risk
We have issued long-term debt and have obligations under bank facilities
that subject us to the risk of loss associated with movements in market interest
rates. We utilize interest-rate swaps in order to hedge a portion of our
floating-rate obligations.
Our floating-rate obligations borrowed from third parties aggregated $3.0
billion and $1.1 billion at December 31, 2000 and 2001, respectively. If the
floating interest rates were to increase by 10% from December 31, 2001 rates,
our combined interest expense to third parties would increase by a total of $0.4
million each month in which such increase continued.
At December 31, 2000 and 2001, we had issued fixed-rate debt to third
parties aggregating $67 million and $121 million. As of December 31, 2000 and
2001, fair values were estimated to be equivalent to the carrying amounts of
these instruments. 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. However, the fair value of these instruments would increase by $3 million
if interest rates were to decline by 10% from their rates at December 31, 2001.
During 2001, we have entered into interest-rate swaps in order to adjust
the interest rate on some of our floating-rate debt to a fixed-rate. As of
December 31, 2001, these interest rate swaps had an aggregate notional amount of
$200 million and the fair value was a $4 million liability. A decrease of 10% in
the interest rate level at December 31, 2001 would increase the fair value of
the interest rate swaps by $4 million.
Foreign Currency Exchange Rate Risk
Our European operations expose us to risk of loss in the fair value of our
foreign investments due to the fluctuation in foreign currencies relative to our
reporting currency, the U.S. dollar. Additionally, our European Energy segment
transacts in several European currencies, although the majority of its business
is conducted in the Euro and prior to January 2001, the Dutch Guilder. As of
December 31, 2001, we had entered into foreign currency swaps and foreign
currency forward contracts and had issued Euro-denominated borrowings to hedge
our foreign currency exposure of our net European investment. Changes in the
value of the foreign currency hedging instruments and Euro--denominated
borrowings are recorded as foreign currency translation adjustments as a
component of accumulated other comprehensive income (loss) in stockholders'
equity. As of December 31, 2000 and 2001, we had recorded a loss of $2 million
and $96 million, respectively, 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. 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.
As of December 31, 2001, our European Energy segment had entered into
transactions to purchase $271 million at fixed exchange rates in order to hedge
future fuel purchases payable in U.S. dollars. As of December 31, 2001, the fair
value of these financial instruments was a $3 million asset. An increase in the
value of the Euro of 10% compared to the U.S. dollar from its December 31, 2001
level would result in loss in the fair value of these foreign currency financial
instruments of $27 million.
Our European Energy segment's stranded cost import contracts have foreign
currency exposure. An increase of 10% in the U.S. dollar relative to the Euro
from their December 31, 2001 levels would result in a loss of earnings of $6
million.
Equity Market Value Risk
We have equity investments, which are classified as "available-for-sale"
under SFAS No. 115. As of December 31, 2001, the value of these securities was
$12 million. A 10% decline in the market value per share of these securities
from December 31, 2001 would result in a loss in fair value of $1 million.
83
RISK MANAGEMENT STRUCTURE
We have a risk control framework to limit, monitor, measure and manage the
risk in our existing portfolio of assets and contracts and to risk-measure and
authorize new transactions. These risks include market, credit, liquidity and
operational exposures. We believe that we have effective procedures for
evaluating and managing these risks to which we are exposed. Key risk control
activities include limits on trading and marketing exposures and products,
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.
We seek to monitor and control our risk exposures through a variety of
separate but complementary processes and committees which involve business unit
management, senior management and our Board of Directors, as detailed below.
Board of Directors. Our Board of Directors affirms the overall strategy
and approves overall risk limits for commodity trading and marketing.
Audit Committee. The Audit Committee of our Board of Directors assesses
the adequacy of the risk control organization and policies. The Audit Committee
of our Board of Directors meets at least three times a year to:
- approve the risk control organization structure,
- approve the corporate-wide risk control policy,
- monitor compliance with trading limits,
- review significant risk control issues, and
- recommend to our Board of Directors corporate-wide commodity risk
limit parameters for trading and marketing activities.
Executive Management. Our executive management appoints the Risk Oversight
Committee members, reviews and approves recommendations of the Risk Oversight
Committee prior to presentations to the Audit Committee of our Board of
Directors, and approves and monitors broad risk limit allocations to the
business segments and product types. Our executive management receives daily
position reports of our trading and marketing activities.
Risk Oversight Committee. The Risk Oversight Committee, which is comprised
of corporate and business segment officers, oversees all of our trading,
marketing and hedging activities and other activities involving market risks.
These activities expose us to commodity price, credit, foreign currency and
interest rate risks. The Risk Oversight Committee meets at least monthly. For
trading, marketing and hedging activities, the Risk Oversight Committee:
- monitors compliance of our trading units,
- reviews daily position reports for trading and marketing activities,
- recommends adjustments to trading limits, products and policies to
the Audit Committee of our Board of Directors,
- approves business segment's detailed policies and procedures,
- allocates Board of Director-approved trading and marketing risk
capital limits, including VAR limits,
- approves new trading, marketing and hedging products and
commodities,
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- approves entrance into new trading markets,
- monitors processes and information systems related to the management
of our risk to market exposures, and
- places guidelines and limits around hedging activities.
Commitment Review Committee. The Commitment Review Committee, which is
comprised of corporate officers, establishes corporate-wide standards for the
evaluation of capital projects and other significant commitments, evaluates
proposed capital projects and other significant commitments, and makes
recommendations to the chief executive officer. The Commitment Review Committee
is scheduled to meet on an as needed basis.
Corporate Risk Control Organization. Our Corporate Risk Control
Organization is headed by a chief risk control officer who has corporate-wide
oversight for maintaining consistent application of corporate risk policies
within individual business segments. The Corporate Risk Control Organization:
- recommends the corporate-wide risk management policies and
procedures which are approved by the Audit Committee of our Board of
Directors;
- provides updates of trading and marketing activities to the Audit
Committee of our Board of Directors on a regular basis;
- provides oversight of our ongoing development and implementation of
operational risk policies, framework and methodologies;
- monitors effectiveness of the corporate-wide risk management
policies, procedures and risk limits;
- evaluates the business segment risk control organizations, including
information systems and reporting;
- evaluates all significant valuation methodologies, assumptions and
models;
- evaluates allocation of risk limits within our business segments;
- reviews daily position reports of trading and marketing activities;
and
- reviews inherent risks in proposed transactions.
Business Segment Risk Control Organizations. Each of our business segments
has a Business Segment Risk Control Organization, which is headed by a risk
control officer who reports to the Corporate Risk Control Organization and the
business segment's executive management outside of the commercial trading
organization. The Business Segment Risk Control Organization:
- develops and maintains the risk control infrastructure, including
policies, processes, personnel and information and valuation
systems, to analyze and report the daily risk positions to Executive
Management, the Risk Oversight Committee, the Corporate Risk Control
Organization, the Internal Audit Department and the Controllers
Organization;
- reviews credit exposures for customers and counterparties;
- reviews all significant valuation methodologies, assumptions and
models used for risk measurement, mark-to-market valuations and
structured transaction evaluations;
- ensures risk systems can adequately measure positions and related
risk exposures for new products and transactions;
85
- evaluates new transactions for compliance with risk policies and
limits; and
- evaluates effectiveness of hedges.
The management of each of the business segments is responsible for the
management of its risks and for maintaining a conducive environment for
effective risk control activities as part of its overall responsibility for the
proper management of the business unit. Commercial management has in-depth
knowledge of the primary sources of risk in their individual markets and the
instruments available to hedge our exposures. Commercial management allocates
risk limits that have been allocated to specific markets and to individual
traders, within the limits imposed by the Risk Oversight Committee. Risk limits
are monitored on a daily basis. Risk limit violations, including VAR, are
reported to the appropriate level of management in the business segment and
corporate organizations, depending on the type and severity of the violations.
Segregation of duties and management oversight are fundamental elements of
our risk management process. There are segregation of duties among the trading
and marketing functions; transaction validation and documentation; risk
measurement and reporting; settlements function; accounting and financial
reporting functions; and treasury function. These risk management processes and
related controls are reviewed by our corporate Internal Audit Department on a
regular basis. When appropriate, external advisors or consultants with relevant
experience will assist the Internal Audit Department with their reviews.
The effectiveness of our policies and procedures for managing risk
exposure can never be completely estimated or fully assured. For example, we
could experience losses, which could have a material adverse effect on our
financial condition, results of operations or cash flows, from unexpectedly
large or rapid movements or disruptions in the energy markets, from
regulatory-driven market rules changes and bankruptcy of customers or
counterparties.
CREDIT RISK
Credit risk is inherent in our commercial activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. Broad credit policies and parameters are set by the Risk
Oversight Committee. The Business Segment Risk Control Organizations prepare
daily analysis of credit exposures. We enter into derivative instruments
primarily with counterparties having a minimum investment grade credit rating
(i.e., a minimum credit rating for such entity's senior unsecured debt of BBB-
for Standard & Poor's and Fitch or Baa3 for Moody's). In addition, we seek to
enter into netting agreements that permit us to offset receivables and payables
with a given counterparty. We also attempt to enter into agreements that enable
us to obtain collateral from a counterparty or to terminate upon the occurrence
of credit-related events. We are re-evaluating our current credit risk practices
in light of changes in the marketplace, recent corporate failures and higher
scrutiny of credit practices by the rating agencies.
It is our policy that all transactions must be within approved
counterparty or customer credit limits. For each business segment, counterparty
credit limits are established by the applicable segment's credit risk control
group. We employ tiered levels of approval authority for counterparty credit
limits, with authority increasing from the operating segment's credit analysts
through the business segment's risk control officer, the Risk Oversight
Committee and our executive management. The Business Segment Risk Control
Organization monitors credit exposure daily. The mark-to-market values and cash
settlement values for all transactions are compared to the authorized credit
threshold for each counterparty. For long-term arrangements, we periodically
review the financial condition of these counterparties in addition to monitoring
the effectiveness of these contracts in achieving our objectives.
For information regarding our provision related to our energy sales in the
California market, please read Note 13(i) to our consolidated financial
statements. For information regarding our net provision related to energy sales
to Enron which filed a voluntary petition for bankruptcy, please read Note 17 to
our consolidated financial statements.
The following table presents the distribution by credit ratings of our
total trading and marketing assets and total non-trading derivative assets as of
December 31, 2001, after taking into consideration netting and set-off
agreements with counterparties within each balance sheet caption (in millions).
86
PERCENTAGE OF
COLLATERAL EXPOSURE NET OF EXPOSURE NET OF
CREDIT RATING EQUIVALENT EXPOSURE HELD(3) COLLATERAL COLLATERAL
- ------------------------ -------- ---------- --------------- ---------------
AAA/Aaa ............................... $ 136 $ -- $ 136 5%
AA/Aa2 ................................ 191 -- 191 7%
A/A2 .................................. 1,049 (4) 1,045 39%
BBB/Baa2 .............................. 1,143 (137) 1,006 38%
BB/Ba2 or lower ....................... 251 (26) 225 9%
Unrated (1)(2) ........................ 49 -- 49 2%
------- ------- ------- -----
2,819 (167) 2,652 100%
Less: Credit and other reserves ....... 114 -- 114
------- ------- -------
$ 2,705 $ (167) $ 2,538
======= ======= =======
The following table presents credit exposure by maturity for total trading
and marketing assets and non-trading derivative assets, net of collateral, as of
December 31, 2001 (in millions).
EXPOSURE NET OF
CREDIT RATING EQUIVALENT 0-12 MONTHS 1 YEAR OR GREATER COLLATERAL
- ------------------------ ----------- ----------------- ---------------
AAA/Aaa ................................ $ 95 $ 41 $ 136
AA/Aa2 ................................. 142 49 191
A/A2 ................................... 860 185 1,045
BBB/Baa2 ............................... 653 353 1,006
BB/Ba2 or lower ........................ 125 100 225
Unrated (1)(2) ......................... 31 18 49
------ ------ ------
1,906 746 2,652
Less: Credit and other reserves ........ 69 45 114
------ ------ ------
$1,837 $ 701 $2,538
====== ====== ======
- ----------
(1) For unrated counterparties, we perform financial statement analysis,
considering contractual rights and restrictions, and collateral, to create
a synthetic credit rating.
(2) In lieu of making an individual assessment of the credit of unrated
counterparties, we may make a determination that the collateral held in
respect of such obligations is sufficient to cover a substantial portion
of our exposure. In making this determination, we take into account
various factors, including market volatility.
(3) Collateral consists of cash and standby letters of credit.
87
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
INDEX TO FINANCIAL STATEMENTS
RELIANT RESOURCES, INC. AND SUBSIDIARIES
Independent Auditors' Report.......................................................................F-2
Statements of Consolidated Income for the Years Ended December 31, 1999, 2000 and 2001.............F-3
Consolidated Balance Sheets as of December 31, 2000 and 2001.......................................F-4
Statements of Consolidated Cash Flows for the Years Ended December 31, 1999, 2000 and 2001.........F-5
Statements of Consolidated Stockholders' Equity and Comprehensive Income for the Years Ended
December 31, 1999, 2000 and 2001...................................................................F-6
Notes to Consolidated Financial Statements.........................................................F-7
Supplementary Data of the Company................................................................III-1
F- 1
INDEPENDENT AUDITORS' REPORT
To the Board of Directors and Stockholders of
Reliant Resources, Inc. and Subsidiaries
Houston, Texas
We have audited the accompanying consolidated balance sheets of Reliant
Resources, Inc. and Subsidiaries (the Company), as of December 31, 2000 and
2001, and the related consolidated statements of income, cash flows, and
stockholders' equity and comprehensive income for each of the three years in the
period ended December 31, 2001. 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 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 consolidated financial position of the Company at
December 31, 2000 and 2001, and the consolidated results of its operations and
its consolidated cash flows for each of the three years in the period ended
December 31, 2001, 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.
As discussed in Note 6 to the consolidated financial statements, the
Company changed its method of accounting for derivative instruments and hedging
activities in 2001.
DELOITTE & TOUCHE LLP
Houston, Texas
March 28, 2002
F- 2
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED INCOME
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
YEAR ENDED DECEMBER 31,
------------------------------------------------
1999 2000 2001
------------ ------------ ------------
REVENUES .................................................... $ 7,956,052 $ 19,791,922 $ 36,545,739
EXPENSES:
Fuel and cost of gas sold ................................ 3,948,118 10,581,827 15,805,156
Purchased power .......................................... 3,728,762 7,852,084 18,734,328
Operation and maintenance ................................ 135,620 435,006 510,759
General, administrative and development .................. 100,480 291,661 486,973
Depreciation and amortization ............................ 28,584 193,682 246,764
------------ ------------ ------------
Total ................................................ 7,941,564 19,354,260 35,783,980
------------ ------------ ------------
OPERATING INCOME ............................................ 14,488 437,662 761,759
------------ ------------ ------------
OTHER (EXPENSE) INCOME:
Interest expense ......................................... (8,795) (42,337) (63,268)
Interest income .......................................... -- 17,732 26,645
Interest (expense) income -- affiliated companies, net ... (9,802) (172,269) 12,477
Gains (losses) from investments, net ..................... 15,972 (16,509) 22,040
Income of equity investment of unconsolidated subsidiaries 20,805 42,860 57,440
Gain on sale of development project ...................... -- 18,011 --
Other, net ............................................... (6,062) 5,963 8,890
------------ ------------ ------------
Total other income (expense) ......................... 12,118 (146,549) 64,224
------------ ------------ ------------
INCOME BEFORE INCOME TAXES, CUMULATIVE EFFECT OF ACCOUNTING
CHANGE AND EXTRAORDINARY ITEM ............................ 26,606 291,113 825,983
INCOME TAX EXPENSE .......................................... 2,560 88,593 271,594
------------ ------------ ------------
INCOME BEFORE CUMULATIVE EFFECT OF ACCOUNTING CHANGE AND
EXTRAORDINARY ITEM ....................................... 24,046 202,520 554,389
Cumulative effect of accounting change, net of tax ....... -- -- 3,062
Extraordinary item, net of tax ........................... -- 7,445 --
------------ ------------ ------------
NET INCOME .................................................. $ 24,046 $ 209,965 $ 557,451
============ ============ ============
BASIC AND DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change ..... $ 2.00
Cumulative effect of accounting change, net of tax ....... 0.01
------------
Net income ............................................... $ 2.01
============
See Notes to the Company's Consolidated Financial Statements
F- 3
RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
DECEMBER 31,
------------------------------
2000 2001
------------ ------------
ASSETS
CURRENT ASSETS:
Cash and cash equivalents ...................................................... $ 89,755 $ 118,453
Restricted cash ................................................................ 50,000 167,421
Accounts and notes receivable, principally customer, net ....................... 1,811,355 1,182,140
Accounts and notes receivable -- affiliated companies, net ..................... -- 415,081
Inventory ...................................................................... 99,445 174,035
Stranded costs settlement receivable ........................................... -- 201,503
Trading and marketing assets ................................................... 4,290,803 1,611,393
Non-trading derivative assets .................................................. -- 392,900
Margin deposits on energy trading and hedging activities ....................... 521,004 213,727
Collateral for electric generating equipment ................................... -- 141,701
Prepayments and other current assets ........................................... 130,334 126,936
------------ ------------
Total current assets .................................................... 6,992,696 4,745,290
------------ ------------
PROPERTY, PLANT AND EQUIPMENT, NET ................................................ 4,049,495 4,601,542
------------ ------------
OTHER ASSETS:
Goodwill, net .................................................................. 1,006,782 847,912
Air emissions regulatory allowances and other intangibles, net ................. 283,952 315,438
Notes receivable -- affiliated companies, net .................................. -- 30,278
Equity investments in unconsolidated subsidiaries .............................. 108,727 386,841
Trading and marketing assets ................................................... 544,909 446,610
Non-trading derivative assets .................................................. -- 254,168
Stranded costs indemnification receivable ...................................... -- 203,693
Accumulated deferred income taxes .............................................. -- 8,172
Collateral for electric generating equipment ................................... 84,879 88,268
Other .......................................................................... 142,952 325,344
------------ ------------
Total other assets ...................................................... 2,172,201 2,906,724
------------ ------------
TOTAL ASSETS ............................................................ $ 13,214,392 $ 12,253,556
============ ============
LIABILITIES AND STOCKHOLDERS' EQUITY
CURRENT LIABILITIES:
Current portion of long-term debt .............................................. $ 591 $ 23,769
Short-term borrowings .......................................................... 126,175 296,769
Accounts payable, principally trade ............................................ 2,083,556 1,002,326
Accounts and notes payable -- affiliated companies, net ........................ 1,321,120 --
Trading and marketing liabilities .............................................. 4,272,771 1,478,336
Non-trading derivative liabilities ............................................. -- 323,277
Margin deposits from customers on energy trading and hedging activities ........ 284,603 144,700
Accumulated deferred income taxes .............................................. -- 63,634
Other .......................................................................... 315,592 253,800
------------ ------------
Total current liabilities ............................................... 8,404,408 3,586,611
------------ ------------
OTHER LIABILITIES:
Accumulated deferred income taxes .............................................. 31,181 --
Notes payable -- affiliated companies, net ..................................... 647,499 --
Trading and marketing liabilities .............................................. 530,263 361,786
Non-trading derivative liabilities ............................................. -- 530,211
Major maintenance reserve ...................................................... 19,899 16,784
Non-derivative stranded costs liability ........................................ -- 203,693
Benefit obligations ............................................................ 44,413 127,012
Other .......................................................................... 312,543 455,865
------------ ------------
Total other liabilities ................................................. 1,585,798 1,695,351
------------ ------------
LONG-TERM DEBT .................................................................... 891,736 867,712
------------ ------------
COMMITMENTS AND CONTINGENCIES (NOTE 13)
STOCKHOLDERS' EQUITY:
Preferred stock; par value $0.001 per share (125,000,000 shares authorized; none
outstanding).................................................................. -- --
Common Stock, par value $0.001 per share (2,000,000,000 shares authorized;
240,000,000 and 299,804,000 issued and outstanding; respectively)............. 1 61
Additional paid-in capital ..................................................... 2,336,993 5,777,169
Treasury stock at cost, 0 and 11,000,000 shares ................................ -- (189,460)
Retained earnings .............................................................. -- 557,451
Accumulated other comprehensive loss ........................................... (4,544) (41,339)
------------ ------------
Stockholders' equity .................................................... 2,332,450 6,103,882
------------ ------------
TOTAL LIABILITIES AND STOCKHOLDERS' EQUITY .............................. $ 13,214,392 $ 12,253,556
============ ============
See Notes to the Company's Consolidated Financial Statements
F-4
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
YEAR ENDED DECEMBER 31,
---------------------------------------------
1999 2000 2001
----------- ----------- -----------
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income .................................................. $ 24,046 $ 209,965 $ 557,451
Adjustments to reconcile net income to net cash provided by
(used in) operating activities:
Depreciation and amortization ............................. 28,583 193,682 246,764
Deferred income taxes ..................................... 15,556 (27,476) 22,440
Net trading and marketing assets and liabilities .......... (11,703) (3,984) (185,136)
Net non-trading derivative assets and liabilities ......... -- -- (65,831)
Curtailment and related benefit enhancement ............... -- -- 99,523
Contributions of marketable securities to charitable
foundation .............................................. -- 15,172 --
Impairment of marketable equity securities ................ -- 26,504 --
Undistributed loss (income) of unconsolidated subsidiaries 793 (24,931) (30,280)
Gain on sale of development project ....................... -- (18,011) --
Stranded cost indemnification settlement gain ............. -- -- (36,881)
Cumulative effect of accounting change .................... -- -- (3,062)
Extraordinary item ........................................ -- (7,445) --
Other, net ................................................ (15,948) (2,034) (11,712)
Changes in other assets and liabilities:
Restricted cash ......................................... -- (50,000) (117,421)
Accounts and notes receivable, net ...................... (225,257) (1,174,918) 582,629
Accounts receivable/payable -- affiliated companies, net 32,939 (168,692) 92,906
Inventory ............................................... 69,076 (9,468) (59,153)
Collateral for electric generating equipment, net ....... -- (84,879) (145,090)
Margin deposits on energy trading and hedging activities,
net .................................................. (59,467) (206,480) 167,374
Prepaid lease obligation ................................ -- -- (180,531)
Proceeds from sale of debt securities ................... -- 123,428 --
Other current assets .................................... (11,905) (92,719) 102,348
Other assets ............................................ (8,199) (103,692) (39,882)
Accounts payable ........................................ 274,054 1,485,925 (1,084,239)
Taxes accrued ........................................... (21,450) 49,716 (6,068)
Other current liabilities ............................... 23,974 209,216 (55,984)
Other liabilities ....................................... (80,038) (11,337) 22,814
----------- ----------- -----------
Net cash provided by (used in) operating activities ... 35,054 327,542 (127,021)
----------- ----------- -----------
CASH FLOWS FROM INVESTING ACTIVITIES:
Capital expenditures ........................................ (293,197) (933,180) (839,908)
Payment of business purchase obligation ..................... -- (981,789) --
Business acquisitions, net of cash acquired ................. (1,065,013) (2,121,408) --
Proceeds from sale-leaseback transactions ................... -- 1,000,000 --
Investments in unconsolidated subsidiaries .................. (36,582) (5,755) --
Other, net .................................................. (11,680) 28,830 1,839
----------- ----------- -----------
Net cash used in investing activities ................. (1,406,472) (3,013,302) (838,069)
----------- ----------- -----------
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from long-term debt ................................ 61,601 770,009 --
Proceeds from issuance of stock, net ........................ -- -- 1,696,074
Purchase of treasury stock .................................. -- -- (189,460)
Payments of long-term debt .................................. -- (307,201) (4,084)
(Decrease) increase in short-term borrowings, net ........... (18,591) (31,906) 217,323
Increase (decrease) in notes with affiliated companies, net . 1,306,576 1,219,946 (731,894)
Contributions from owner .................................... 235,877 1,094,259 9,441
Distribution to owner ....................................... (170,211) -- --
Other, net .................................................. (7,691) (23,951) 2,140
----------- ----------- -----------
Net cash provided by financing activities ............. 1,407,561 2,721,156 999,540
----------- ----------- -----------
EFFECT OF EXCHANGE RATE CHANGES ON CASH AND CASH EQUIVALENTS ... 460 5,088 (5,752)
----------- ----------- -----------
NET INCREASE IN CASH AND CASH EQUIVALENTS ...................... 36,603 40,484 28,698
CASH AND CASH EQUIVALENTS AT BEGINNING OF YEAR ................. 12,668 49,271 89,755
----------- ----------- -----------
CASH AND CASH EQUIVALENTS AT END OF YEAR ....................... $ 49,271 $ 89,755 $ 118,453
=========== =========== ===========
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash Payments:
Interest (net of amounts capitalized) ..................... $ 37,126 $ 205,103 $ 84,650
Income taxes .............................................. 16,496 72,784 243,740
See Notes to the Company's Consolidated Financial Statements
F-5
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED
STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(THOUSANDS OF DOLLARS)
ADDITIONAL
COMMON TREASURY PAID-IN RETAINED
STOCK STOCK CAPITAL EARNINGS
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 1998 ..................... $ 668,039
COMPREHENSIVE INCOME: .........................
Net income ................................. 24,046
Contributions from owner ................... 235,877
Distribution to owner ...................... (170,211)
Other comprehensive loss: ..................
Unrealized loss on available-for-sale
securities, net of tax of
$0.4 million ..........................
Foreign currency translation adjustments .
Comprehensive income .....................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 1999 ..................... 757,751
COMPREHENSIVE INCOME: .........................
Net income ................................. 209,965
Contributions from owner ................... 1,369,278
Transfer to common stock and
additional paid-in capital .............. $ 1 $2,336,993 (2,336,994)
Other comprehensive income (loss):
Foreign currency translation adjustments .
Additional minimum non-qualified
pension liability adjustment, net
of tax of $0.4 million ................
Reclassification adjustment for impairment
loss on available-for-sale securities
realized in net income, net of tax
of $9 million .........................
Unrealized loss on available-for-sale
securities, net of tax of $1 million ..
Comprehensive income .....................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2000 ..................... 1 2,336,993 --
Net income ................................. 557,451
Contributions from owner ................... 1,787,311
Purchases of treasury stock ................ (189,460)
Majority owner effect of treasury
stock purchases ......................... (43,149)
IPO proceeds, net .......................... 60 1,696,014
Other comprehensive income (loss):
Foreign currency translation
adjustments, net of tax of
$98 million ...........................
Changes in minimum non-qualified
pension liability, net of tax of
$4 million ............................
Cumulative effect of adoption of
SFAS No. 133, net of tax of $145
million ...............................
Deferred gain from cash flow hedges,
net of tax of $228 million ............
Reclassification of net deferred gain
from cash flow hedges into net income,
net of tax of $51 million .............
Unrealized gain on available-for-sale
securities, net of tax of $9 million ..
Reclassification adjustments for gains
on sales of available-for-sale
securities realized in income, net
of tax of $5 million ..................
Comprehensive income ..................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2001 ..................... $ 61 $ (189,460) $5,777,169 $ 557,451
========== ========== ========== ==========
UNREALIZED (LOSS) FOREIGN ADDITIONAL
GAIN ON AVAILABLE DEFERRED CURRENCY MINIMUM
FOR SALE DERIVATIVE TRANSLATION BENEFITS
SECURITIES GAINS (LOSSES) ADJUSTMENTS LIABILITY
----------------- -------------- ------------ -----------
BALANCE DECEMBER 31, 1998 ..................... $ (16,004)
COMPREHENSIVE INCOME: .........................
Net income .................................
Contributions from owner ...................
Distribution to owner ......................
Other comprehensive loss: ..................
Unrealized loss on available-
for-sale securities, net of
tax of $0.4 million ................... (1,224)
Foreign currency translation adjustments . $ 162
Comprehensive income ...................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 1999 ..................... (17,228) 162
COMPREHENSIVE INCOME:
Net income .................................
Contributions from owner ...................
Transfer to common stock and
additional paid-in capital ..............
Other comprehensive income (loss):
Foreign currency translation adjustments . (1,726)
Additional minimum non-qualified
pension liability adjustment, net
of tax of $0.4 million ................ (716)
Reclassification adjustment for impairment
loss on available-for-sale securities
realized in net income, net of tax
of $9 million ......................... 17,228
Unrealized loss on available-for-sale
securities, net of tax of $1 million .. (2,264)
Comprehensive income .....................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2000 ..................... (2,264) (1,564) (716)
Net income .................................
Contributions from owner ...................
Purchases of treasury stock ................
Majority owner effect of treasury
stock purchases .........................
IPO proceeds, net ..........................
Other comprehensive income (loss):
Foreign currency translation
adjustments, net of tax of
$98 million ........................... (94,066)
Changes in minimum non-qualified
pension liability, net of tax of
$4 million ............................ (6,799)
Cumulative effect of adoption of
SFAS No. 133, net of tax of $145
million ............................... $ (290,294)
Deferred gain from cash flow hedges,
net of tax of $228 million ............ 427,994
Reclassification of net deferred gain
from cash flow hedges into net income,
net of tax of $51 million ............. (81,944)
Unrealized gain on available-for-sale
securities, net of tax of $9 million .. 16,984
Reclassification adjustments for gains
on sales of available-for-sale
securities realized in income, net
of tax of $5 million .................. (8,670)
Comprehensive income ..................
---------- ---------- ---------- ----------
BALANCE DECEMBER 31, 2001 ..................... $ 6,050 $ 55,756 $ (95,630) $ (7,515)
========== ========== ========== ==========
TOTAL
ACCUMULATED
OTHER TOTAL
COMPREHENSIVE STOCKHOLDERS' COMPREHENSIVE
INCOME (LOSS) EQUITY INCOME (LOSS)
------------- ----------- -------------
BALANCE DECEMBER 31, 1998 ..................... $ (16,004) $ 652,035
COMPREHENSIVE INCOME: .........................
Net income ................................. 24,046 $ 24,046
Contributions from owner ................... 235,877
Distribution to owner ...................... (170,211)
Other comprehensive loss: ..................
Unrealized loss on available-
for-sale securities, net of
tax of $0.4 million ................... (1,224) (1,224) (1,224)
Foreign currency translation adjustments . 162 162 162
-----------
Comprehensive income ................... $ 22,984
---------- ----------- ===========
BALANCE DECEMBER 31, 1999 ..................... (17,066) 740,685
COMPREHENSIVE INCOME:
Net income ................................. 209,965 $ 209,965
Contributions from owner ................... 1,369,278
Transfer to common stock and
additional paid-in capital .............. --
Other comprehensive income (loss):
Foreign currency translation adjustments . (1,726) (1,726) (1,726)
Additional minimum non-qualified
pension liability adjustment, net
of tax of $0.4 million ................ (716) (716) (716)
Reclassification adjustment for impairment
loss on available-for-sale securities
realized in net income, net of tax
of $9 million ......................... 17,228 17,228 17,228
Unrealized loss on available-for-sale
securities, net of tax of $1 million .. (2,264) (2,264) (2,264)
-----------
Comprehensive income ..................... $ 222,487
---------- ----------- ===========
BALANCE DECEMBER 31, 2000 ..................... (4,544) 2,332,450
Net income ................................. 557,451 $ 557,451
Contributions from owner ................... 1,787,311
Purchases of treasury stock ................ (189,460)
Majority owner effect of treasury
stock purchases ......................... (43,149)
IPO proceeds, net .......................... 1,696,074
Other comprehensive income (loss):
Foreign currency translation
adjustments, net of tax of
$98 million ........................... (94,066) (94,066) (94,066)
Changes in minimum non-qualified
pension liability, net of tax of
$4 million ............................ (6,799) (6,799) (6,799)
Cumulative effect of adoption of
SFAS No. 133, net of tax of $145
million ............................... (290,294) (290,294) (290,294)
Deferred gain from cash flow hedges,
net of tax of $228 million ............ 427,994 427,994 427,994
Reclassification of net deferred gain
from cash flow hedges into net income,
net of tax of $51 million ............. (81,944) (81,944) (81,944)
Unrealized gain on available-for-sale
securities, net of tax of $9 million .. 16,984 16,984 16,984
Reclassification adjustments for gains
on sales of available-for-sale
securities realized in income, net
of tax of $5 million .................. (8,670) (8,670) (8,670)
-----------
Comprehensive income .................. $ 520,656
---------- ----------- ===========
BALANCE DECEMBER 31, 2001 ..................... $ (41,339) $ 6,103,882
=========== ===========
See Notes to the Company's Consolidated Financial Statements
F-6
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
FOR THE THREE YEARS ENDED DECEMBER 31, 1999, 2000 AND 2001
(1) BACKGROUND AND BASIS OF PRESENTATION
On July 27, 2000, Reliant Energy, Incorporated (Reliant Energy) announced
its intention to form a company, Reliant Resources, Inc. (Reliant Resources), to
own and operate a substantial portion of its unregulated operations and to offer
no more than 20% of the common stock of Reliant Resources in an initial public
offering. Reliant Resources and its subsidiaries are collectively referred to
herein as the "Company." In May 2001, Reliant Resources offered 59.8 million
shares of its common stock to the public at an initial offering price of $30 per
share (IPO) and received net proceeds from the IPO of $1.7 billion. Reliant
Energy expects to distribute the remaining common stock of Reliant Resources
owned by Reliant Energy or its successors to its shareholders (Distribution) in
the summer of 2002. The Distribution is subject to the declaration of the
Distribution by the Board of Directors of Reliant Energy, market and other
conditions, and government actions and approvals. There can be no assurances
that the Distribution will be completed as described or within the periods
outlined above. Reliant Energy, together with its subsidiaries, is a diversified
international energy services company consisting of regulated and unregulated
energy operations. For information regarding the IPO, see Note 9(a).
The unregulated operations included in the consolidated financial
statements of Reliant Resources for 1999 and 2000 consist of Reliant Energy's,
or its direct and indirect subsidiaries', unregulated power generation and
related energy trading, marketing, power origination and risk management
services in North America and Europe; a portion of its retail electric
operations; and other operations, including a communications business and a
venture capital operation. Throughout 1999 and 2000, these operations were
conducted by Reliant Energy and its direct and indirect subsidiaries. On August
9, 2000, Reliant Energy formed Reliant Resources, a Delaware corporation, as a
wholly owned subsidiary. Reliant Resources was incorporated with 1,000 shares of
common stock. Effective December 31, 2000, Reliant Energy consolidated its
unregulated operations under Reliant Resources (Consolidation). A subsidiary of
Reliant Energy, Reliant Energy Resources Corp. (RERC Corp.), transferred some of
its subsidiaries, including its trading and marketing subsidiaries, to Reliant
Resources. In connection with the transfer from RERC Corp., Reliant Resources
paid $94 million to RERC Corp. Also effective December 31, 2000, Reliant Energy
transferred its wholesale power generation businesses, its unregulated retail
electric operations, its communications business and most of its other
unregulated businesses to Reliant Resources. In accordance with accounting
principles generally accepted in the United States of America, the transfers
from RERC Corp. and Reliant Energy were accounted for as a reorganization of
entities under common control.
The accompanying consolidated financial statements for 1999 and 2000 are
presented on a carve-out basis and include the historical operations of the
Company. These financial statements have been prepared from Reliant Energy's
historical accounting records.
The Statements of Consolidated Income include all revenues and costs
directly attributable to the Company, including costs for facilities and costs
for functions and services performed by centralized Reliant Energy organizations
and directly charged to the Company based on usage or other allocation factors.
The results of operations in these Consolidated Financial Statements also
include general corporate expenses allocated by Reliant Energy to the Company.
All of the allocations in the Consolidated Financial Statements are based on
assumptions that management believes are reasonable under the circumstances.
However, these allocations may not necessarily be indicative of the costs and
expenses that would have resulted if the Company had been operated as a separate
entity.
The Company's financial reporting segments include the following:
Wholesale Energy, European Energy, Retail Energy and Other Operations. The
Wholesale Energy segment engages in the acquisition, development and operation
of domestic non-rate regulated electric power generation facilities as well as
wholesale energy trading, marketing, power origination and risk management
activities related to energy and energy-related commodities in North America.
The European Energy segment, which was formed in the fourth quarter of 1999,
operates power generation facilities in the Netherlands and conducts wholesale
energy trading and power origination activities in Europe. The Retail Energy
segment includes the Company's retail electric operations. This segment provides
F-7
customized, integrated energy services to large commercial, industrial and
institutional customers and electricity and related services to residential and
small commercial customers in Texas. In addition, Retail Energy historically
included billing and remittance services provided to Reliant Energy's regulated
electric utility and two of its natural gas utilities. Such services will not be
provided to Reliant Energy's electric utility and its natural gas utilities
after December 31, 2001. Retail Energy charged the regulated electric and gas
utilities for the services provided to these utilities at the Company's cost.
The Other Operations segment includes unallocated general corporate expenses and
non-operating investments.
(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 2001 presentation of financial statements. These reclassifications do not
affect earnings.
The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America 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 and hedging activities. For additional information regarding these
risks, see Notes 6, 13(i) and 17. The Company is also subject to risks, among
others, relating to the timing of the implementation of the business separation
plan of Reliant Energy, supply and prices of fuel and electricity, effects of
competition, changes in interest rates, results of financing efforts, operation
of deregulating power markets, seasonal weather patterns, technological
obsolescence and the regulatory environment in the United States and Europe. In
addition, the Company is subject to risks relating to the reliability of the
systems, procedures and other infrastructure necessary to operate the Company's
retail electric business.
(c) PRINCIPLES OF CONSOLIDATION.
The accounts of the Company 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 uses the equity method of accounting for investments
in entities in which the Company has an ownership interest between 20% and 50%
and exercises significant influence. 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. The
results of the Company's European Energy segment are consolidated on a
one-month-lag basis due to the availability of financial information. The
Company has made adjustments to the European Energy segment's accounts to
include the effect for the settlement of an indemnity for certain energy
obligations in December 2001, see Note 13(f).
(d) REVENUES.
The Company records gross revenue for energy sales and services related to
its electric power generation facilities under the accrual method and these
revenues generally are recognized upon delivery. Energy sales and services
related to its electric power generation facilities not billed by month-end are
accrued based upon estimated energy and services delivered. Domestic electric
power and other energy services are sold at market-based prices through existing
power exchanges or through third-party contracts. Prior to January 1, 2001,
energy revenues related to the Company's power generation facilities in Europe
were determined under a regulated pricing structure, which included compensation
for the cost of fuel, capital and operation and maintenance expenses. The
wholesale electric market in the Netherlands opened to competition on January 1,
2001. Accordingly, beginning in 2001, electric power and other energy services
in Europe are sold at market-based prices or through third-party contracts.
F-8
The Company records gross revenue for energy sales and services to retail
customers except, for sales to large contracted commercial, industrial and
institutional customers, under the accrual method and these revenues generally
are recognized upon delivery.
The Company's energy trading, marketing, power origination and risk
management services activities and contracted sales of electricity to large
commercial, industrial and institutional customers are accounted for under the
mark-to-market method of accounting. Under the mark-to-market method of
accounting, derivative instruments and contractual commitments are recorded at
market value in revenues upon contract execution. The net changes in their fair
values are recognized in the Statement of Consolidated Income as revenues in the
period of change. Trading and marketing revenues related to the physical sale of
natural gas, electric power and other energy related commodities are recorded on
a gross basis in the delivery period. For additional discussion regarding
trading and marketing revenue recognition and the related estimates and
assumptions that can affect reported amounts of such revenues, see Note 6.
The gains and losses related to financial instruments and contractual
commitments qualifying and designated as hedges related to the sale of electric
power and purchase of fuel are recognized in the same period as the settlement
of the underlying physical transaction. These realized gains and losses are
included in operating revenues and operating expenses in the Statements of
Consolidated Income. For additional discussion, see Note 6.
(e) GENERAL, ADMINISTRATIVE AND DEVELOPMENT EXPENSES.
The general, administrative and development expenses in the Statements of
Consolidated Income include employee related costs of the trading, marketing,
power origination and risk management services operations, corporate and
administrative services (including management services, financial and tax
accounting, cash management and treasury support, legal, information technology
system support, office management and human resources); business development
costs; and certain benefit costs.
(f) 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 "accrue in advance"
method for its power generation operations acquired or developed prior to
December 31, 1999. Planned major maintenance cycles primarily range from two to
ten years. Under the accrue 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, 2000 and 2001, the Company's major
maintenance reserve was $27 million and $19 million, respectively, of which $7
million and $2 million, respectively, were included in other current
liabilities. The Company expenses all other repair and maintenance costs as
incurred. For power generation operations acquired or developed subsequent to
January 1, 2000, the Company expenses all repair and maintenance costs as
incurred, including planned major maintenance. Property, plant and equipment
includes the following:
DECEMBER 31,
ESTIMATED USEFUL --------------------------------
LIVES (YEARS) 2000 2001
---------------- ------ ------
(IN MILLIONS)
Electric generation facilities................... 10--40 $2,794 $2,871
Building and building improvements............... 15--20 12 14
Other 3--10 76 164
Land and land improvements....................... 141 147
Assets under construction........................ 1,177 1,682
------ ------
Total....................................... 4,200 4,878
Accumulated depreciation......................... (151) (276)
------ ------
Property, plant and equipment, net.......... $4,049 $4,602
====== ======
The Company records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Historically, goodwill
is amortized on a straight-line basis over 5 to 40 years. See Notes 2(q) and 5
and the following table for additional information regarding goodwill and the
related amortization periods.
F-9
DECEMBER 31,
AMORTIZATION --------------------------------
ACQUISITION PERIOD (YEARS) 2000 2001
- ----------- ------------- ------ -----
(IN MILLIONS)
Reliant Energy Mid-Atlantic Power Holdings, LLC......... 35 $7 $ 5
Reliant Energy Power Generation Benelux N.V............. 30 897 834
Florida Generation Plant................................ 35 2 2
California Generation Plants............................ 30 70 70
Reliant Energy Services, Inc............................ 40 131 131
Other 5--15 59 40
------ ------
Total.............................................. 1,166 1,082
Accumulated amortization................................ (52) (84)
Foreign currency exchange impact........................ (107) (150)
------ ------
Total goodwill, net................................ $1,007 $ 848
====== ======
The Company recognizes specifically identifiable intangibles, including
air emissions regulatory allowances, water rights and permits, when specific
rights and contracts are acquired. 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. An impairment analysis
of generating facilities requires estimates of possible future market prices,
load growth, competition and many other factors over the lives of the
facilities. A resulting impairment loss is highly dependent on these underlying
assumptions. During 2001, the Company determined equipment and goodwill
associated with the Communications business was impaired and accordingly
recognized $22 million of fixed asset impairments and $19 million of goodwill
impairments (see Note 16). For discussion of goodwill impairment analysis in
2002, see Note 2(q).
During December 2001, the Company evaluated its European Energy business
segment's long-lived assets and goodwill for impairment. As of December 31,
2001, pursuant to Statement of Financial Accounting Standards (SFAS) No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to Be Disposed Of" (SFAS No. 121), no impairment had been indicated. For
discussion of goodwill impairment analysis in 2002, see Note 2(q).
(g) DEPRECIATION AND AMORTIZATION EXPENSE.
Depreciation is computed using the straight-line method based on economic
lives. Other amortization expense includes amortization of air emissions
regulatory allowances and other intangibles. The 2001 goodwill amortization
expense includes the $19 million in goodwill impairment related to the
Communications business (see Note 16). The following table presents
depreciation, goodwill amortization and other amortization expense for 1999,
2000 and 2001.
YEAR ENDED DECEMBER 31,
------------------------
1999 2000 2001
---- ---- ----
(IN MILLIONS)
Depreciation expense ..................................... $ 18 $105 $152
Goodwill amortization expense ............................ 11 35 51
Other amortization expense ............................... -- 54 44
---- ---- ----
Total depreciation and amortization expense ........... $ 29 $194 $247
==== ==== ====
(h) CAPITALIZATION OF INTEREST EXPENSE.
Interest expense is capitalized as a component of projects under
construction and is amortized over the assets' estimated useful lives. During
1999, 2000 and 2001, the Company capitalized interest of $8 million, $35 million
and $59 million, respectively.
(i) INCOME TAXES.
The Company is included in the consolidated income tax returns of Reliant
Energy. The Company calculates its income tax provision on a separate return
basis under a tax sharing agreement with Reliant Energy. The Company
F-10
uses the liability method of accounting for deferred income taxes and measures
deferred income taxes for all significant income tax temporary differences.
Current federal and some state income taxes are payable to or receivable from
Reliant Energy. 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 12.
(j) CASH AND RESTRICTED CASH.
The Company records as cash and cash equivalents all highly liquid
short-term investments with original maturities of three months or less. As of
December 31, 2001, the Company has recorded $167 million of restricted cash that
is available for Reliant Energy Mid-Atlantic Power Holdings, LLC and its
subsidiaries' (collectively, REMA) working capital needs and for it to make
future lease payments. For additional discussion regarding REMA's lease
transactions, see Note 13(c).
(k) ALLOWANCE FOR DOUBTFUL ACCOUNTS.
Accounts and notes receivable, principally from customers, on the
Consolidated Balance Sheets are net of an allowance for doubtful accounts of $51
million and $90 million at December 31, 2000 and 2001, respectively. The
provision for doubtful accounts in the Statements of Consolidated Income for
1999, 2000 and 2001 was $1 million, $43 million and $38 million, respectively.
In addition, during 2001, the Company wrote-off $15 million of receivables for
refunds related to energy sales in California and $88 million related to energy
sales to Enron Corp. and its affiliates (Enron) which filed a voluntary petition
for bankruptcy during the fourth quarter of 2001. For information regarding the
provision against receivable balances related to energy sales in the California
market and to Enron, see Notes 13(i) and 17, respectively.
(l) INVENTORY.
Inventory consists of materials and supplies, coal, natural gas and
heating oil. Inventories used in the production of electricity are valued at the
lower of average cost or market. Heating oil and natural gas used in the trading
and marketing operations are accounted for under mark-to-market accounting as
discussed in Note 6. Below is a detail of inventory:
DECEMBER 31,
--------------
2000 2001
---- ----
(IN MILLIONS)
Materials and supplies ......... $ 44 $ 65
Coal ........................... 10 35
Natural gas .................... 16 41
Heating oil .................... 29 33
---- ----
Total inventory ........... $ 99 $174
==== ====
(m) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES.
As of December 31, 2000 and 2001, the Company held marketable equity
securities of $5 million and $12 million, respectively, classified as
"available-for-sale." 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 other long-term
assets in the Consolidated Balance Sheets and any unrealized gain or loss, net
of tax, as a separate component of stockholders' equity and accumulated other
comprehensive loss. At December 31, 2000, the accumulated unrealized loss, net
of tax, relating to these equity securities was $2 million. At December 31,
2001, the Company had an accumulated unrealized gain, net of tax, relating to
these securities of $6 million.
During 2000, pursuant to SFAS No. 115, the Company incurred a pre-tax
impairment loss equal to the $27 million of cumulative unrealized losses that
had been charged to accumulated other comprehensive loss through December 31,
1999. 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
F-11
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.
In addition, the Company has held debt and equity securities classified as
"trading." 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 gains (losses) from
investments in the Statements of Consolidated Income. As of December 31, 2000,
the Company did not hold debt or equity securities that are classified as
"trading." As of December 31, 2001, the Company held equity securities
classified as "trading" totaling $1 million. The Company recorded unrealized
holding gains on "trading" securities included in gains from investments in the
Statements of Consolidated Income of $16 million, $4 million and $5 million
during 1999, 2000 and 2001, respectively.
(n) 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, 2000 and 2001, the Company had recorded in the
Consolidated Balance Sheets project development costs of $7 million and $9
million, respectively.
(o) 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.
(p) FOREIGN CURRENCY ADJUSTMENTS.
Local currencies are the functional currency of the Company's foreign
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 as a component of
accumulated other comprehensive loss in stockholders' equity.
(q) CHANGES IN ACCOUNTING PRINCIPLES AND NEW ACCOUNTING PRONOUNCEMENTS.
Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101),
was issued by the Securities and Exchange Commission (SEC) staff 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. The Consolidated Financial Statements reflect the accounting
guidance provided in SAB No. 101.
In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and
Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method of accounting and broadens the criteria for recording intangible
assets separate from goodwill. Recorded goodwill and intangibles will be
evaluated against these new criteria and may result in certain intangibles being
transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. SFAS
No. 142 provides for a nonamortization approach, whereby goodwill and certain
intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and written
down and charged to results of operations only in the periods in which the
recorded value of goodwill and certain intangibles with indefinite lives is more
than its fair value. The Company adopted the provisions of each statement which
apply to goodwill and intangible assets acquired prior to June 30, 2001 on
F-12
January 1, 2002. The adoption of SFAS No. 141 did not have a material impact on
the Company's historical results of operations or financial position. On January
1, 2002, the Company discontinued amortizing goodwill into its results of
operations pursuant to SFAS No. 142. The Company recognized $32 million of
goodwill amortization expense in the Statement of Consolidated Income during
2001, excluding a $19 million write-off of a Communications business goodwill
balance which was recorded as goodwill amortization expense (see Note 16). The
Company is in the process of determining further effects of adoption of SFAS No.
142 on its Consolidated Financial Statements, including the review of goodwill
and certain intangibles for impairment. The Company has not completed its review
pursuant to SFAS No. 142. However, based on the Company's preliminary review,
the Company believes an impairment of its European Energy segment goodwill is
reasonably possible. As of December 31, 2001, net goodwill associated with the
European Energy segment is $632 million. The Company anticipates finalizing its
review of goodwill and certain intangibles for its reporting units during 2002.
The Company does not believe impairments of goodwill and certain intangibles, if
any, related to the Company's other reporting units will have a material impact
on the Company's results of operations or financial position.
In August 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
a liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. The Company plans to adopt SFAS No.
143 on January 1, 2003, and is in the process of determining the effect of
adoption on its Consolidated Financial Statements.
In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121 "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of" and Accounting Principles Board Opinion No.
30, "Reporting the Results of Operations -- Reporting the Effects of Disposal of
a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions," while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 is not expected to materially change the
methods used by the Company to measure impairment losses on long-lived assets,
but may result in additional future dispositions being reported as discontinued
operations than is currently permitted. The Company adopted SFAS No. 144 on
January 1, 2002.
See Note 6 for the Company's adoption of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended (SFAS No. 133) on
January 1, 2001 and adoption of subsequent cleared guidance.
(3) HISTORICAL RELATED PARTY TRANSACTIONS
The Consolidated Financial Statements include significant transactions
between the Company and Reliant Energy involving services, 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 the Company 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 the Company been a
separate entity. Amounts charged and allocated to the Company
F-13
for these services were $11 million, $34 million and $9 million for 1999, 2000
and 2001, respectively, and are included primarily in operation and maintenance
expenses and general and administrative expenses. In addition, during 2001, the
Company incurred costs primarily related to corporate support services which
were billed to Reliant Energy and its affiliates of $27 million. Some
subsidiaries of the Company have entered into office rental agreements with
Reliant Energy. During 1999, 2000 and 2001, the Company incurred $1 million, $4
million and $16 million, respectively, of rent expense to Reliant Energy.
Certain of these services and the office space lease arrangements between
the Company and Reliant Energy will continue after the Distribution under
transition service agreements or other long-term agreements. It is not
anticipated that a change, if any, in these costs and revenues would have a
material effect on the Company's consolidated results of operations, cash flows
or financial position. For additional information regarding these services and
office space lease arrangements between the Company and Reliant Energy, see Note
4(a).
Below is a detail of accounts and notes receivable (payable) to affiliated
companies that are not part of the Company:
DECEMBER 31,
---------------------
2000 2001
------- -------
(IN MILLIONS)
Net accounts receivable -- affiliated companies ...................................... $ 94 $ 27
Net short-term notes (payable) receivable -- affiliated companies .................... (1,415) 388
Net long-term notes (payable) receivable -- affiliated companies ..................... (648) 30
------- -------
Total net accounts and notes (payable) receivable -- affiliated companies ......... $(1,969) $ 445
======= =======
Net accounts receivable -- affiliated companies, representing primarily
current month balances of transactions between the Company and Reliant Energy or
its subsidiaries, relate primarily to natural gas purchases and sales, interest,
charges for services and office space rental. Net short-term notes
payable/receivable -- affiliated companies represent the accumulation of a
variety of cash transfers and operating transactions and specific negotiated
financing transactions with Reliant Energy or its subsidiaries and generally
bear interest at market-based rates. Net long-term notes payable/receivable --
affiliated companies primarily relate to specific negotiated financing
transactions with Reliant Energy or its subsidiaries that bear interest at
market-based rates. See the discussion below for information regarding the notes
payable entered into by the Company with Reliant Energy during 2000 related to
the acquisition of Reliant Energy Power Generation Benelux, N.V. (REPGB), a
Dutch power generation company, and the acquisition of certain assets and
operations held by REMA during May 2000. Net interest expense related to these
net borrowings/receivables was $10 million and $172 million during 1999 and
2000, respectively. Net interest income related to these net
borrowings/receivables was $12 million during 2001.
Funds for the acquisition of REMA were made available through loans from
Reliant Energy. In May 2000, $1.0 billion of these loans were converted to
equity and $1.0 billion of these loans were repaid in August 2000 from proceeds
received from the sale-leaseback transactions (see Note 5(a)). The loans bore
interest at 9.4%.
In connection with funding its purchase of REPGB (see Note 5(b)), a
subsidiary of the Company entered into a 560 million Euro-denominated note
(approximately $528 million based on the December 31, 2000, exchange rate of
1.0616 Euros per U.S. dollar) with Reliant Energy, which matured on July 1,
2001. At December 31, 2000, the entire Euro 560 million was outstanding on this
note. Outstanding indebtedness under the note bore interest at the inter-bank
offered rate for Euros (EURIBOR) plus 0.75% per annum. The applicable interest
rate was 5.7% at December 31, 2000. In March 2001, the Company paid $236 million
of the debt owed to Reliant Energy, along with the accrued interest on the
amount. The repayment was made with general corporate funds of the Company,
including amounts borrowed under the Company's credit facilities.
In May 2001, Reliant Energy converted or contributed an aggregate of $1.7
billion of the indebtedness owed by the Company to Reliant Energy and its
subsidiaries to equity without the issuance of any additional shares of common
stock of the Company, pursuant to the master separation agreement by recording
an increase to additional paid-in capital of the Company. In addition, the
Company used $147 million of the net proceeds of the IPO to repay certain
indebtedness owed to Reliant Energy in May 2001.
F-14
During 2001, proceeds not initially utilized from the IPO were advanced to
a subsidiary of Reliant Energy (the Reliant Energy money fund) on a short-term
basis. The Company has reduced its advance to the Reliant Energy money fund
following the IPO to fund capital expenditures and to meet its working capital
needs. As of December 31, 2001, the Company had outstanding advances to the
Reliant Energy money fund of $390 million which is included in accounts and
notes receivable in the Company's Consolidated Balance Sheet.
The Company purchases natural gas and transportation services from,
supplies natural gas to, and provides marketing and risk management services to
affiliates of Reliant Energy that are not part of the Company. Purchases of
transportation services and natural gas from Reliant Energy and its subsidiaries
were $200 million, $178 million and $188 million in 1999, 2000 and 2001,
respectively. During 1999, 2000 and 2001, the sales and services to Reliant
Energy and its subsidiaries totaled $330 million, $601 million and $701 million,
respectively.
During 2001, REPGB received efficiency and energy payments from BV
Nederlands Elektriciteit Administratiekantoor (NEA), an equity investment (see
Note 7), totaling $30 million pursuant to a protocol agreement under which the
Dutch generators provided capacity and energy to distributors in exchange for
regulated production payments. In addition, during 2001 REPGB received payments
from NEA totaling $14 million related to environmental tax subsidies for
previous periods.
Pursuant to the provisions of the master separation agreement between the
Company and Reliant Energy, during 2001 the Company has participated in
generation capacity auctions by Reliant Energy's electric utility generation
assets (Texas Genco). The Company has also exercised its option included in the
master separation agreement to purchase 50% of the capacity, energy and
ancillary services of Texas Genco not auctioned in the aforementioned auctions,
at the prices established in these auctions. As of December 31, 2001, the
Company has minimum commitments to purchase capacity of Texas Genco averaging
6,471 megawatts (MW) per month in 2002 and 775 MW per month in 2003. The Company
has no minimum obligations for energy or ancillary services under the master
separation agreement. The Company's anticipated payments related to these
minimum obligations are $213 million in 2002 and $58 million in 2003. For
additional information regarding agreements relating to Texas Genco, see Note
4(b).
During 1999, 2000 and 2001, Reliant Energy or its subsidiaries made equity
contributions to the Company of $236 million, $1.4 billion and $1.8 billion,
respectively. During 1999, the Company made distributions to a subsidiary of
Reliant Energy of $170 million. The contributions received by the Company in
1999 primarily related to cash contributions used to fund (a) the acquisition of
a generating facility in Florida (see Note 5(c)) and (b) general operating
costs. In addition, during 1999, Arkla Finance Corporation, a subsidiary of the
Company, received payment of $170 million on a long-term note receivable from an
affiliate. Arkla Finance Corporation distributed the $170 million to its parent
company, RERC Corp. The contributions in 2000 primarily related to (a)
conversion of $1 billion of the borrowings from Reliant Energy used to fund the
acquisition of REMA (see Note 5(a)), (b) the forgiveness of $284 million of debt
held by subsidiaries that were transferred from RERC Corp. to the Company (see
Note 1) and (c) general operating costs. The contributions in 2001, primarily
related to the conversion into equity of debt owed to Reliant Energy and its
subsidiaries and some related interest expense totaling $1.7 billion and the
contribution of net benefit assets and liabilities, net of deferred income
taxes.
(4) RELATED PARTY TRANSACTIONS -- AGREEMENTS BETWEEN RELIANT ENERGY AND THE
COMPANY
(a) SERVICES AGREEMENTS.
The Company has entered into agreements with Reliant Energy under which
Reliant Energy will provide the Company, on an interim basis, various corporate
support services, 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 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. The charges the Company
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, the Company will have the
right to terminate categories of services at an earlier date. It is not
anticipated that termination of these
F-15
service arrangements will have a material effect on the Company's financial
position, results of operations or cash flows.
Pursuant to lease agreements, Reliant Energy will lease the Company office
space in its headquarters building and in various other locations in Houston,
Texas, for an interim period.
Under a service agreement, the Company provided customer service call
center operations, credit and collections and revenue accounting services for
Reliant Energy's electric utility division and received and processed payments
for the accounts of Reliant Energy's electric utility division and two of
Reliant Energy's natural gas distribution divisions. Reliant Energy provided the
office space and equipment for the Company to perform these services. The
charges Reliant Energy paid the Company for these services were generally
intended to allow the Company to recover its fully allocated costs of providing
the services, plus out-of-pocket costs and expenses. The service agreement
governing these services terminated on December 31, 2001.
(b) AGREEMENTS RELATING TO TEXAS GENCO.
Pursuant to the Texas electric restructuring law, Texas Genco, as the
affiliated power generator of Reliant Energy's transmission and distribution
utility, is required to sell at auction 15% of the output of its installed
generating capacity. This obligation continues until January 1, 2007, unless
before that date the Public Utility Commission of Texas (Texas Utility
Commission) determines at least 40% of the quantity of electric power consumed
in 2000 by residential and small commercial customers in the utility's service
area is being served by retail electric providers other than us. The master
separation agreement requires Texas Genco to auction all of its capacity that
remains subsequent to capacity auctioned pursuant to Texas Utility Commission
rules and after certain other deductions (Texas Genco remaining capacity). The
Company has the right to purchase 50% (but not less than 50%) of Texas Genco's
remaining capacity at the prices to be established in the auction. For a
discussion of the Company's purchases of capacity from Texas Genco in 2001, see
Note 3. It is expected that Texas Genco will have a total of six auctions in
2002 and 2003.
In connection with the separation of the Company's businesses from those
of Reliant Energy, Reliant Energy has agreed either to issue and sell in an
initial public offering or to distribute no more than 20% of the common stock of
Texas Genco by December 31, 2002. Reliant Energy has granted the Company an
option to purchase, subject to the completion of the Distribution, all of the
shares of capital stock of Texas Genco that will hold the Texas generating
assets of Reliant Energy's electric utility division that will be owned by
Reliant Energy after the initial public offering or distribution noted below.
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 ending January 9, 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% 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%.
The Company has agreed that if it exercises the Texas Genco option and purchases
the shares of Texas Genco common stock, the Company 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 or
receivables from Reliant Energy, the Company will assume Reliant Energy's
obligations in exchange for a payment to the Company by Reliant Energy of an
amount equal to the principal plus accrued interest.
The Company has entered into a support agreement with Reliant Energy,
pursuant to which the Company will provide engineering and technical support
services and environmental, safety and industrial health services to support
operations and maintenance of Texas Genco's facilities. The Company 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 the Company to recover its fully allocated direct and indirect
costs and reimbursement of out-of-pocket expenses. Expenses associated with
capital investment
F-16
in systems and software that benefit both the operation of Texas Genco's
facilities and the Company's facilities in other regions will be allocated on an
installed megawatt basis. The term of this agreement will end on the first to
occur of (a) the closing date of the Texas Genco option, (b) Reliant Energy's
sale of Texas Genco, or all or substantially all of the assets of Texas Genco,
if the Company does not exercise the Texas Genco option, or (c) May 31, 2005,
provided the Texas Genco option is not exercised; however, Texas Genco may
extend the term of this agreement until December 31, 2005.
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. The master separation agreement
provides 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
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.
(c) OTHER AGREEMENTS.
In connection with the separation of the Company's businesses from those
of Reliant Energy, the Company has also entered into other agreements providing
for, among other things, mutual indemnities and releases with respect to the
Company's respective businesses and operations, matters relating to corporate
governance, matters relating to responsibility for employee compensation and
benefits, and the allocation of tax liabilities. In addition, the Company and
Reliant Energy have entered into various agreements relating to ongoing
commercial arrangements, including among other things, the leasing of optical
fiber and related maintenance activities, gas purchasing and agency matters and
subcontracting energy services under existing contracts.
The Company has guaranteed, in the event Reliant Energy becomes insolvent,
certain non-qualified benefits of Reliant Energy's and its subsidiaries'
existing retirees at the Distribution totaling approximately $55 million.
(5) 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 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 REMA. The purchase price for the May 2000
transaction was $2.1 billion. In 2002, the Company made an $8 million payment to
the prior owner for post-closing adjustments which resulted in an adjustment to
purchase price. The Company accounted for the acquisition as a purchase with
assets and liabilities of REMA reflected at their estimated fair values. The
Company's fair value adjustments related to the acquisition primarily included
adjustments in property, plant and equipment, air emissions regulatory
allowances, specific intangibles, 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 specific intangibles which relate to water rights and permits of
$43 million will be amortized over the estimated life of the related facility of
35 years. The excess of the purchase price over the fair value of the net assets
acquired of $5 million was recorded as goodwill and historically was amortized
over 35 years. The Company finalized these fair value adjustments in May 2001.
There were no additional material modifications to the preliminary adjustments
from December 31, 2000. Funds for the acquisition of REMA were made available
through loans from Reliant Energy. In May 2000, $1.0 billion of these loans were
subsequently converted to equity.
F-17
The net purchase price of REMA was allocated and the fair value
adjustments to the seller's book value are as follows:
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
(IN MILLIONS)
Current assets ....................... $ 85 $ (27)
Property, plant and equipment ........ 1,898 627
Goodwill ............................. 5 (146)
Other intangibles .................... 196 33
Other assets ......................... 3 (5)
Current liabilities .................. (50) (13)
Other liabilities .................... (39) (15)
------- -------
Total ....................... $ 2,098 $ 454
======= =======
Adjustments to property, plant and equipment, other intangibles which
includes air emissions regulatory allowances and other specific intangibles, 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 covering the Company's respective
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 leveraged 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 intercompany
indebtedness owed by the Company to Reliant Energy.
The Company's results of operations include the results of REMA only for
the period beginning May 12, 2000. 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 for operations prior to November 24, 1999
would not be meaningful since historical financial results of the business and
the revenue generating activities underlying that period are substantially
different from the wholesale generation activities that REMA has been engaged in
after November 24, 1999. Pro forma amounts 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
------------------------- -------------------------
ACTUAL PRO FORMA ACTUAL PRO FORMA
------- --------- ------- ---------
(IN MILLIONS)
Revenues .............................................. $ 7,956 $ 7,986 $19,792 $19,958
Income after tax and before extraordinary item ........ 24 14 203 194
Net income ............................................ 24 14 210 201
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.
F-18
(b) RELIANT ENERGY POWER GENERATION BENELUX N.V.
Effective October 7, 1999, the Company acquired REPGB, 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. A portion ($596 million) of this obligation was financed with a
three-year term loan facility obtained in the first quarter of 2000 (see Note
8(a)).
For the two month period ended November 30, 1999, the Company accounted
for its interest in REPGB using the equity method rather than the consolidation
method. This resulted in income of equity investment of unconsolidated
subsidiaries of $22 million for the year ended December 31, 1999.
The Company recorded the REPGB acquisition under the purchase method of
accounting, with assets and liabilities of REPGB reflected at their estimated
fair values. As outlined in the table below, the Company's fair value
adjustments related to the acquisition of REPGB 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 REPGB for some obligations incurred
prior to the purchase of REPGB. Adjustments to property, plant and equipment are
based on valuation reports prepared by independent appraisers and consultants.
The excess of the purchase price over the fair value of net assets acquired of
$877 million was recorded as goodwill and was historically amortized on a
straight-line basis over 30 years. The Company finalized these fair value
adjustments in September 2000. In 2002, the Company recorded a $43 million
reduction in goodwill related to the accounting for the purchase of treasury
shares (see Note 9(b)). The Company finalized a severance plan (REPGB Plan) in
connection with the REPGB 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. During 2001, the Company utilized $8 million of the
reserve for the REPGB Plan. As of December 31, 2001, the remaining severance
liability is $11 million. The majority of the $ 11 million of remaining
severance liability will be disbursed in accordance with the terms and
conditions outlined by a collective labor bargaining agreement regarding
employees near retirement age (Social Plan) in accordance with applicable Dutch
labor law. The Social Plan, which by formula defines termination benefits,
prescribes a payout period for up to 5 years for an employee subsequent to
termination date. In the fourth quarter of 2001, the Dutch taxing authority
finalized REPGB's tax basis of property, plant and equipment as of October 1999.
As a result, the Company recorded an adjustment to decrease goodwill and
accumulated deferred tax liability by $5 million in the fourth quarter of 2001.
As of December 31, 2001, the tax basis of other certain assets and liabilities
has not been finalized.
In connection with the acquisition of REPGB, the Company developed a
comprehensive business process reengineering and employee severance plan
intended to make REPGB competitive in the deregulated Dutch electricity market
that began January 1, 2001. The REPGB Plan's initial conceptual formulation was
initiated prior to the acquisition of REPGB in October 1999. The finalization of
the REPGB Plan was approved and completed in September 2000. The Company
identified 195 employees who were involuntarily terminated in REPGB'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 REPGB Plan that
they are subject to involuntary termination and the majority of terminations
occurred during 2001. The termination benefits under the REPGB Plan are governed
by REPGB's Social Plan, a collective bargaining agreement between REPGB 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 REPGB 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 REPGB.
The Company is still executing the REPGB Plan as of the date of these
Consolidated Financial Statements.
F-19
The net purchase price of REPGB was allocated and the fair value
adjustments to the seller's book value are as follows:
PURCHASE FAIR
PRICE VALUE
ALLOCATION ADJUSTMENTS
---------- -----------
(IN MILLIONS)
Current assets .................... $ 244 $ 34
Property, plant and equipment ..... 1,899 719
Goodwill .......................... 877 877
Current liabilities ............... (336) --
Deferred taxes .................... (76) (76)
Long-term debt .................... (422) (87)
Other long-term liabilities ....... (244) (35)
------- -------
Total .................... $ 1,942 $ 1,432
======= =======
The following table presents selected actual financial information for
1999 and unaudited pro forma information for 1999, as if the acquisition of
REPGB had occurred on January 1, 1999. The 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 REPGB had
occurred on January 1, 1999. Purchase related adjustments to results of
operations include amortization of goodwill, interest expense and the effects on
depreciation and amortization of the assessed fair value of some of REPGB's net
assets and liabilities.
1999
-----------------------------------
ACTUAL PRO FORMA
-------- ---------
(IN MILLIONS)
Revenues...................................... $7,956 $8,533
Net income (loss)............................. 24 (3)
(c) FLORIDA GENERATION PLANT PURCHASE.
On October 6, 1999, the Company purchased a steam turbine generation plant
(Indian River) with a net generating capacity of 619 MW from a Florida
municipality (Municipality) for a net purchase price of $188 million. Indian
River, located near Titusville, Florida, consists of three conventional steam
generation units fueled by both oil and natural gas. Under the Company's
ownership, the units will sell up to 578 MW of power generation from Indian
River to the Municipality through a power purchase agreement that was originally
scheduled to expire in September 2003, but has been extended through September
2007. During the option period, the Municipality has the right to purchase up to
500 MW for the first two years of the option period and 300 MW for the final two
years. Any excess power generated by the plant may be sold to other utilities
and rural electric cooperatives within the state and other entities within the
Florida wholesale market. The Company recorded the acquisition under the
purchase method of accounting. The purchase price has been allocated to assets
acquired and liabilities assumed based on their estimated fair market values at
the date of acquisition. The Company's fair value adjustments related to the
acquisition of Indian River primarily included increases in property, plant and
equipment, specific intangibles related to water rights and permits, major
maintenance reserves and related deferred taxes. The specific intangibles of
$112 million are being amortized over their contractual lives of 35 years. The
Company finalized these fair value adjustments during September 2000. There were
no material adjustments made to the purchase allocation subsequent to December
31, 1999.
F-20
Net purchase price of Indian River was allocated as follows (in millions):
Current assets .................... $ 15
Property, plant and equipment ..... 93
Goodwill .......................... 2
Other intangibles ................. 112
Major maintenance reserve ......... (3)
Other long-term liabilities ....... (31)
-----
Total .................... $ 188
=====
The Company's results of operations include Indian River's results of
operations only for the period beginning with the October 6, 1999 acquisition
date. Pro forma information has not been presented for Indian River for 1999.
Pro forma information would not be meaningful since historical financial results
of the business and the revenue generating activities underlying that period as
described below are substantially different from the wholesale generation
activities that Indian River has been engaged in after October 6, 1999. Prior to
the Company's acquisition, the acquired Indian River generation operations were
fully integrated with, and its results of operations were consolidated into, the
Municipality's vertically-integrated utility operations. In addition, prior to
the Company's acquisition, the electric output of these facilities was sold
based on rates set by regulatory authorities and are not indicative of these
assets' future operating results as a wholesale electricity provider.
(6) DERIVATIVE INSTRUMENTS
Effective January 1, 2001, the Company adopted 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 (loss), depending on the intended use of the derivative, its resulting
designation and its effectiveness. If certain conditions are met, an entity may
designate a derivative instrument as hedging (a) the exposure to changes in the
fair value of an asset or liability (Fair Value Hedge), (b) the exposure to
variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign
currency exposure of a net investment in a foreign operation. For a derivative
not designated as a hedging instrument, the gain or loss is recognized in
earnings in the period it occurs.
Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax
increase in net income of $3 million and a cumulative after-tax increase in
accumulated other comprehensive loss of $290 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by $615 million, $248 million, $811 million and $339 million,
respectively, in the Company's Consolidated Balance Sheet. During the year ended
December 31, 2001, $199 million of the initial after-tax transition adjustment
recognized in other comprehensive income was recognized in net income.
The application of SFAS No. 133 is still evolving as the FASB clears
issues submitted to the Derivatives Implementation Group for consideration.
During the second quarter of 2001, an issue that applies exclusively to the
electric industry and allows the normal purchases and normal sales exception for
option-type contracts if certain criteria are met was approved by the FASB with
an effective date of July 1, 2001. The adoption of this cleared guidance had no
impact on the Company's results of operations. Certain criteria of this
previously approved guidance were revised in October and December 2001 and will
become effective on April 1, 2002. The Company is currently in the process of
determining the effect of adoption of the revised guidance.
During the third quarter of 2001, the FASB cleared an issue related to
application of the normal purchases and normal sales exception to contracts that
combine forward and purchased option contracts. The effective date of this
guidance is April 1, 2002, and the Company is currently assessing the impact of
this cleared issue and does not believe it will have a material impact on the
Company's consolidated financial statements.
The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
the Company's consolidated financial statements. The Company utilizes derivative
instruments such as futures, physical forward contracts, swaps and options
(Energy Derivatives) to mitigate the impact of changes in electricity, natural
gas and fuel prices on its operating results and cash flows. The
F-21
Company utilizes cross-currency swaps, forward contracts and options to hedge
its net investments in and cash flows of its foreign subsidiaries, interest rate
swaps to mitigate the impact of changes in interest rates and other financial
instruments to manage various other market risks.
Trading and marketing operations often involve risk 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. The Company routinely
enters into Energy Derivatives to hedge sale commitments, fuel requirements and
inventories of natural gas, coal, electricity, crude oil and products, emission
allowances and other commodities and to minimize the risk of market fluctuations
in its trading, marketing, power origination and risk management services
operations.
Energy Derivatives primarily used by the Company are described below:
- Futures contracts are exchange-traded standardized commitments to
purchase or sell an energy commodity or financial instrument, or to
make a cash settlement, at a specific price and future date.
- Physical forward contracts are commitments to purchase or sell
energy commodities in the future.
- Swap agreements require payments to or from counterparties based
upon the differential between a fixed price and variable index price
(fixed price swap) or two variable index prices (variable price
swap) for a predetermined contractual notional amount. The
respective index may be an exchange quotation or an industry pricing
publication.
- Option contracts convey the right to buy or sell an energy commodity
or a financial instrument at a predetermined price or settlement of
the differential between a fixed price and a variable index price or
two variable index prices.
(a) ENERGY TRADING, MARKETING, POWER ORIGINATION AND PRICE RISK MANAGEMENT
SERVICES ACTIVITIES.
The Company offers energy price risk management services primarily related
to natural gas, electric power and other energy related commodities. These
activities also include the establishing of open positions in the energy
markets, primarily on a short-term basis, and transactions intended to optimize
the Company's power generation portfolio, but which do not qualify for hedge
accounting. The Company provides these services by utilizing a variety of
derivative instruments (Trading Energy Derivatives).
The Company applies mark-to-market accounting for all of its energy
trading, marketing, power origination and price risk management services
operations in North America and Europe, as well as to retail contracted sales to
large commercial, industrial and institutional customers. Accordingly, these
Trading Energy Derivatives are recorded at fair value with net realized and
unrealized gains (losses) recorded as a component of revenues. The recognized,
unrealized balances are recorded as trading and marketing assets/liabilities.
FAIR VALUE
-------------------------
ASSETS LIABILITIES
------ -----------
(IN MILLIONS)
DECEMBER 31, 2000
Natural gas ............ $3,823 $3,818
Electricity ............ 974 946
Oil and other .......... 39 39
------ ------
$4,836 $4,803
====== ======
DECEMBER 31, 2001
Natural gas ............ $1,389 $1,303
Electricity ............ 648 517
Oil and other .......... 21 20
------ ------
$2,058 $1,840
====== ======
F-22
All of the fair values shown in the table above at December 31, 2000 and
2001 have been recognized in income. The fair values as of December 31, 2000 and
2001, are estimated by using quoted prices where available, other valuation
techniques when market data is not available, for example in illiquid markets,
and other factors such as the time value and volatility factor for the
underlying commitment. The Company's alternative pricing methodologies include,
but are 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 fair values in the above table are subject to significant changes
based on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, power origination, marketing and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant estimates include natural gas and power forward market prices,
volatility and credit risk. For the contracted retail electric sales to large
commercial, industrial and institutional customers, significant variables
affecting contract values also include the variability in electricity
consumption patterns due to weather and operational uncertainties (within
contract parameters). Market prices assume a normal functioning market with an
adequate number of buyers and sellers providing market liquidity. Insufficient
market liquidity could significantly affect the values that could be obtained
for these contracts, as well as the costs at which these contracts could be
hedged.
The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum term of the trading portfolio is 17 years. These
maximum and average terms 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.
(b) NON-TRADING ACTIVITIES.
Cash Flow Hedges. To reduce the risk from market fluctuations in revenues
and the resulting cash flows derived from the sale of electric power, the
Company may enter into Energy Derivatives in order to hedge some expected
purchases of electric power, natural gas and other commodities and sales of
electric power (Non-trading Energy Derivatives). The Non-trading Energy
Derivative portfolios are managed to complement the physical transaction
portfolio, reducing overall risks within authorized limits.
The Company applies hedge accounting for its Non-trading Energy
Derivatives utilized in non-trading activities only if there is a high
correlation between price movements in the derivative and the item designated as
being 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% to 120% for hedge designation. If and when
correlation ceases to exist at an acceptable level, hedge accounting ceases and
mark-to-market accounting is applied. During 2001, the amount of hedge
ineffectiveness recognized in earnings from derivatives that are designated and
qualify as Cash Flow Hedges was a gain of $8 million. No component of the
derivative instruments' gain or loss was excluded from the assessment of
effectiveness. If it becomes probable that an anticipated transaction will not
occur, the Company realizes in net income the deferred gains and losses
recognized in accumulated other comprehensive loss. During 2001, there were no
deferred gains or losses recognized in earnings as a result of the
discontinuance of Cash Flow Hedges because it was no longer probable that the
forecasted transaction would occur. Once the anticipated transaction occurs, the
accumulated deferred gain or loss recognized in accumulated other comprehensive
income (loss) is reclassified and included in the Company's Statements of
Consolidated Income under the captions (a) fuel expenses, in the case of natural
gas transactions, (b) purchased power, in the case of electric power purchase
transactions, (c) revenues, in the case of electric power sales transactions and
(d) interest expense, in the case of interest rate swap transactions. Cash flows
resulting from these transactions in Non-trading Energy Derivatives are included
in the Statements of Consolidated Cash Flows in the same category as the item
being hedged. As of December 31, 2001, the Company's current
non-trading-derivative assets and liabilities and corresponding amounts in
accumulated other comprehensive loss were expected to be reclassified into net
income during the next twelve months.
The maximum length of time the Company is hedging its exposure to the
variability in future cash flows for forecasted transactions excluding the
payment of variable interest on existing financial instruments is eleven years.
F-23
The maximum length of time the Company is hedging its exposure to the payment of
variable interest rates is four years.
During the year ended December 31, 2001, the Company entered into
interest-rate swaps in order to adjust the interest rate on $200 million of its
floating rate debt. In addition, as of December 31, 2001, European Energy has
entered into transactions to purchase $271 million at a fixed exchange rate in
order to hedge future fuel purchases payable in U.S. dollars.
Hedge of the Foreign Currency Exposure of Net Investment in Foreign
Subsidiaries. The Company has substantially hedged the foreign currency exposure
of its net investment in its European subsidiaries through a combination of
Euro-denominated borrowings, foreign currency swaps and foreign currency forward
contracts to reduce the Company's exposure to changes in foreign currency rates.
During the normal course of business, the Company reviews its currency hedging
strategies and determines the hedging approach deemed appropriate based upon the
circumstances of each situation.
The Company records the changes in the value of the foreign currency
hedging instruments and Euro-denominated borrowings as foreign currency
translation adjustments included as a component of 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
Company's net investment in its European subsidiaries. These amounts generally
offset amounts recorded in stockholders' equity as adjustments resulting from
translation of the hedged investment into U.S. dollars. During 2001, the
derivative and non-derivative instruments designated as hedging the net
investment in the Company's European subsidiaries resulted in a gain of $31
million, which is included in the balance of the cumulative translation
adjustment.
Other Derivatives. In December 2000, the Dutch parliament adopted
legislation allocating to the Dutch generation sector, including REPGB,
financial responsibility for various stranded costs contracts and other
liabilities. The legislation became effective in all material respects on
January 1, 2001. In particular, the legislation allocated to the Dutch
generation sectors, including REPGB, financial responsibility to purchase
electricity and gas under gas supply and electricity contracts. These contracts
are derivatives pursuant to SFAS No. 133. As of December 31, 2001, the Company
had recognized $369 million in short-term and long-term non-trading derivative
liabilities for REPGB's portion of these stranded costs contracts. Future
changes in the valuation of these stranded cost import contracts which remain an
obligation of REPGB will be recorded as adjustments to the Company's Statement
of Consolidated Income. The valuation of the contracts could be affected by,
among other things, changes in the price of electric power, coal, low sulfur
fuel oil and the value of the United States dollar and British pound relative to
the Euro. For additional information regarding REPGB's stranded costs and the
related indemnification by former shareholders of these stranded costs during
2001, see Note 13(f).
During 2001, the Company entered into two structured transactions which
were recorded on the balance sheet in non-trading derivative assets and
liabilities involving a series of forward contracts to buy and sell an energy
commodity in 2001 and to buy and sell an energy commodity in 2002 or 2003. The
change in fair value of these derivative assets and liabilities must be recorded
in the statement of income for each reporting period. During 2001, $117 million
of net non-trading derivative liabilities were settled related to these
transactions, and a $1 million pre-tax unrealized gain was recognized. As of
December 31, 2001, the Company has recognized $221 million of non-trading
derivative assets and $103 million of non-trading derivative liabilities related
to these transactions.
(c) CREDIT RISKS.
In addition to the risk associated with price movements, credit risk is
inherent in the Company's risk management activities and hedging 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. The Company enters into
derivative instruments primarily with counterparties having at least a minimum
investment grade credit rating (i.e., a minimum credit rating for such entity's
senior unsecured debt of BBB- for Standard & Poor's and Fitch or Baa3 for
Moody's). In addition, the Company seeks to enter into netting agreements that
permit us to offset receivables and payables with a given counterparty. The
Company also attempts to enter into agreements that enable the Company to obtain
collateral from a counterparty or to terminate upon the
F-24
occurrence of credit-related events. For long-term arrangements, the Company
periodically reviews the financial condition of these counterparties 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 the provision related to energy sales in California, see Note 13(i).
For information regarding the net provision recorded in 2001 related to energy
sales to Enron, see Note 17.
The following tables show the composition of the trading and marketing
assets of the Company as of December 31, 2000 and 2001 and the non-trading
derivative assets as of December 31, 2001.
DECEMBER 31, 2000 DECEMBER 31, 2001
-------------------------- --------------------------
INVESTMENT INVESTMENT
TRADING AND MARKETING ASSETS GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL
- ---------------------------- ---------- ------- ---------- -------
(IN MILLIONS)
Energy marketers ....................................... $ 2,291 $ 2,481 $ 683 $ 757
Financial institutions ................................. 1,099 1,228 495 495
Gas and electric utilities ............................. 472 542 538 544
Oil and gas producers .................................. 474 566 135 176
Commercial, industrial and institutional customers ..... 73 85 119 184
------- ------- ------- -------
Total ............................................. $ 4,409 4,902 $ 1,970 2,156
======= =======
Credit and other reserves .............................. (66) (98)
------- -------
Trading and marketing assets ........................... $ 4,836 $ 2,058
======= =======
DECEMBER 31, 2001
------------------------
INVESTMENT
NON-TRADING DERIVATIVE ASSETS GRADE(1)(2) TOTAL
- ----------------------------- ----------- -----
(IN MILLIONS)
Energy marketers ....................................... $ 371 $ 408
Financial institutions ................................. 76 76
Gas and electric utilities ............................. 89 90
Oil and gas producers .................................. 8 76
Commercial, industrial and institutional customers ..... 7 8
Others ................................................. 5 5
----- -----
Total ............................................. $ 556 663
=====
Credit and other reserves .............................. (16)
-----
Non-trading derivative assets .......................... $ 647
=====
- ----------
(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) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions, and collateral,
to create a synthetic credit rating.
(d) TRADING AND NON-TRADING -- GENERAL POLICY.
The Company has established a Risk Oversight Committee comprised of
corporate and business segment officers that oversees all commodity price,
foreign currency and credit risk activities, including the Company's trading,
marketing, power origination, risk management services and hedging activities.
The committee's duties are to approve 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 monitor compliance with the Company's risk management policies and
procedures and trading limits established by the Company's board of directors.
F-25
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.
(7) EQUITY INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
The Company has a 50% interest in a 490 MW electric generation plant in
Boulder City, Nevada. The plant became operational in May 2000. The Company has
a 50% partnership interest in a 100 MW cogeneration plant in Orange, Texas which
began commercial operations in December 1999. In addition, the Company, through
REPGB, has a 22.5% interest in NEA, which was formerly the coordinating body for
the Dutch electricity generating sector. For information regarding the Company's
investment in NEA and financial impacts, see Note 13(f). See Note 5(b) for a
description of 1999 equity accounting related to REPGB during 1999.
The Company's equity investments in unconsolidated subsidiaries are as
follows:
AS OF DECEMBER 31,
------------------
2000 2001
---- ----
(IN MILLIONS)
Nevada generation plant .................................... $ 77 $ 57
Texas cogeneration plant ................................... 32 31
NEA ........................................................ -- 299
---- ----
Equity investments in unconsolidated subsidiaries ....... $109 $387
==== ====
The Company's income (loss) from equity investments of unconsolidated
subsidiaries is as follow:
YEAR ENDED DECEMBER 31,
---------------------------------
1999 2000 2001
---- ---- ----
(IN MILLIONS)
Nevada generation plant .............................................. $ (1) $ 42 $ 5
Texas cogeneration plant ............................................. -- 1 1
NEA .................................................................. -- -- 51
REPGB ................................................................ 22 -- --
---- ---- ----
Income from equity investments in unconsolidated subsidiaries ..... $ 21 $ 43 $ 57
==== ==== ====
During 1999, there were no distributions from these investments. During
2000 and 2001, $18 million and $27 million, respectively, were the net
distributions from these investments.
(8) SHORT-TERM BORROWINGS AND LONG-TERM DEBT TO THIRD PARTIES
The following table presents the components of short-term borrowings and
long-term debt to third parties as of December 31, 2000 and 2001.
2000 2001
------------------------ -------------------------
LONG-TERM CURRENT(1) LONG-TERM CURRENT(1)
--------- ---------- --------- ----------
(IN MILLIONS)
Total short-term borrowings(2) ............................... $ -- $126 $ -- $297
Long-term debt:
Reliant Energy Power Generation, Inc. notes payable ....... 260 -- 295 2
European Energy(2)(3) ..................................... 631 1 572 22
Debentures unamortized premium(3) ....................... 1 -- 1 --
---- ---- ---- ----
Total long-term borrowings ........................... 892 1 868 24
---- ---- ---- ----
Total borrowings ..................................... $892 $127 $868 $321
==== ==== ==== ====
- ----------
(1) Includes amounts due within one year of the date noted.
F-26
(2) Borrowings were primarily denominated in Euros and the assumed exchange
rate was 1.0616 Euros per U.S. dollar and 1.1242 Euros per U.S. dollar at
December 31, 2000 and 2001, respectively, except for $92 million included
in short-term borrowings at December 31, 2001.
(3) REPGB debt was adjusted to fair market value as of the acquisition date.
The unamortized premium is related to these fair value adjustments and was
amortized over the respective remaining term of the related long-term
debt.
(a) SHORT-TERM BORROWINGS.
As of December 31, 2001, the Company had $5.6 billion in committed credit
facilities, including facilities of subsidiaries of REPG and REPGB, of which
$4.1 billion remained unused. These facilities expire as follows: $1.1 billion
in 2002, $3.3 billion in 2003 and $800 million in 2004. These expirations
exclude $383 million of facilities that will be converted to long-term loans in
2002, as further discussed below. Credit facilities aggregating $4.6 billion
were unsecured. As of December 31, 2001, letters of credit outstanding under
these facilities aggregated $396 million. As of December 31, 2001, borrowings of
$1.1 billion were outstanding under these facilities of which $829 million were
classified as long-term debt, based upon the availability of committed credit
facilities and management's intention to maintain these borrowings in excess of
one year.
As of December 31, 2000, the Company had $1.8 billion of committed credit
facilities in effect, which included facilities of subsidiaries of REPG and
REPGB. As of December 31, 2000, $470 million was unused. As of December 31,
2000, letters of credit outstanding under two of the facilities aggregated $384
million. As of December 31, 2000, borrowings of $825 million were outstanding
under these facilities that were classified as long-term debt, based upon the
availability of committed credit facilities with expiration dates exceeding one
year and management's intention to maintain these amounts in excess of one year.
In 2001, the Company entered into two syndicated revolving credit
facilities with financial institutions, which provide for $800 million each or
an aggregate of $1.6 billion in committed credit. As of December 31, 2001,
letters of credit outstanding under these two facilities aggregated $51 million.
At December 31, 2001, there were no outstanding borrowings under these
facilities. One of these facilities expires on August 22, 2002, with any
outstanding loans on such date being converted at the Company's option to term
loans with a maturity of one year from the date of conversion, provided the
Company meets certain conditions. The other facility has a maturity date of
August 22, 2004. 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. 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.
During the fourth quarter of 2001 the Company also entered into a term
loan facility that provided for $2.2 billion in funding to finance the purchase
of Orion Power Holdings, Inc. (Orion Power). Interest rates on the borrowings
are based on LIBOR plus a margin or a base rate. The facility was subject to
commitment fees that were calculated based on the amount of the unused facility.
In January 2002, the facility was increased to $2.9 billion. This facility was
funded on February 19, 2002 for $2.9 billion. This term loan must be repaid
within one year from the date on which it was funded. For discussion of the
acquisition of Orion Power, see Note 19. At December 31, 2001, there were no
outstanding borrowings under this facility.
The three facilities, as discussed above, contain various business and
financial covenants requiring us to, among other things, maintain a ratio of net
balance sheet debt to the sum of net balance sheet debt, subordinated affiliate
balance sheet debt and stockholders' equity not to exceed 0.60 to 1.00. These
covenants are not anticipated to materially restrict us from borrowing funds or,
in the case of the revolvers, obtaining letters of credit under these
facilities.
In July 2000, REPGB entered into two credit facilities which include (a) a
364-day revolving credit facility for Euro 250 million ($222 million assuming
the December 31, 2001 exchange rate of 1.1242 Euros per U.S. dollar), which was
extended one year in July 2001, and (b) a three-year letter of credit facility
for $420 million. These credit facilities will be used by REPGB for working
capital purposes and to support REPGB's contingent obligations under its cross
border leases (see Note 13(d)). Under the two facilities, there is no recourse
to any affiliate of the Company other than REPGB. The 364-day revolving credit
facility for Euro 250 million bears interest at EURIBOR plus a margin. A
commitment fee of 0.175% per annum was payable on the average daily unused
portion of the
F-27
Euro 250 million facility. At December 31, 2000 and 2001, borrowings of $126
million and $155 million, respectively, were outstanding under the REPGB
facility. The weighted-average interest rate on these short-term borrowings as
of December 31, 2000 and 2001 was 5.65% and 4.18%, respectively. Under the
letter of credit facility, a fee is payable by the Company on each letter of
credit that is outstanding based on REPGB's credit rating. A commitment fee of
0.25% per annum is payable on the average daily unused portion of the $420
million letter of credit facility. At December 31, 2000 and 2001, letters of
credit of $274 million and $272 million were outstanding under this facility.
These facilities contain covenants and requirements that must be met by REPGB to
borrow funds or obtain letters of credit, that require REPGB to, among other
things, maintain a ratio of net balance sheet debt to the sum of net balance
sheet debt and total equity of 0.60 to 1.00. These covenants are not anticipated
to materially restrict the Company from borrowing funds or obtaining letters of
credit, as applicable, under these facilities.
As of December 31, 2001, the Company, through REPGB, has $50 million
(assuming the exchange rate of 1.1242 Euros per U.S. dollar at December 31,
2001) of short-term borrowings arranged via brokers or directly from financial
institutions. These borrowings were used by REPGB to meet its short-term
liquidity needs.
(b) LONG-TERM DEBT.
In February 2000, a subsidiary of the Company established a Euro 600
million term loan facility ($534 million assuming the December 31, 2001 exchange
rate of 1.1242 Euros per U.S. dollar) that terminates in March 2003. The
facility bears interest at EURIBOR plus a margin. At December 31, 2000 and 2001,
$565 million and $534 million (assuming the exchange rate of 1.0616 and 1.1242
Euros per U.S. dollar, respectively) under this facility was outstanding at an
interest rate of 5.873% and 4.6396%, respectively. This facility is secured by a
pledge of the shares of REPGB's indirect holding company. This facility contains
covenants that require the Company's subsidiary to, among other things, maintain
a ratio of net balance sheet debt to the sum of net balance sheet debt and total
equity of 0.60 to 1.00.
On December 15, 1999, a special purpose project subsidiary of REPG entered
into a $475 million syndicated credit facility to finance the construction and
start-up operations of an electric power generation plant located in
Channelview, Texas. The maximum availability under this facility is (a) $92
million in equity bridge loans for the purpose of paying or reimbursing project
costs, (b) $369 million in non-recourse loans to finance the construction of the
project and (c) $14 million in revolving loans for general working capital
purposes. As of December 31, 2000 and 2001, the project subsidiary had drawn
$260 million and $389 million in equity bridge and construction loans,
respectively. As of December 31, 2001, $92 million related to the equity bridge
loan is classified in short-term borrowings and $2 million is classified in
current portion of long-term debt. The loans bear interest at either (a) at the
borrower's option (i) a base rate or (ii) a Euro dollar rate plus a margin, or
(b) a fixed rate of 9.547%. The applicable interest rate was 7.9466% and 5.6565%
at December 31, 2000 and 2001, respectively. Notes issued under the facility are
pre-payable at any time and are due at various expiration dates beginning
November 2002 through August 2024. Amounts drawn under the construction loan
facility is convertible into term loans at project completion. Under the credit
agreement, the equity bridge loans will be repaid no later than November 2002
and the construction loans will be converted into term loans at completion.
Final maturities of the term loans range from 15 to 22 years following the
plant's commercial operation. Commercial operation is expected no later than
November 2002. Advances under the working capital facility mature five years
after the plant begins commercial operations. A commitment fee of 0.35% per
annum is payable on the average daily unused portions of the equity and
construction loan commitments and working capital commitment once available. The
Company incurred $7 million in debt financing costs in 1999 associated with this
project financing. These costs are being amortized over the term of the
facility. Obligations under the construction and term loans and revolving credit
facility are secured by a first priority security interest in the assets and
future revenues of the plant and a pledge of the ownership interest in the
plant. Although the loans are non-recourse in nature, an indemnification
agreement exists that may require REPG, in some circumstances, to reimburse the
lenders for amounts up to the total contract price for the construction of the
plant (approximately $331 million). This indemnity agreement terminates upon
achievement of certain performance standards under the construction agreement.
The $475 million credit facility contains covenants and requirements that must
be met by the project subsidiary to borrow funds. These covenants are not
anticipated to materially restrict the borrowing of funds under the facility.
Outstanding long-term indebtedness of REPGB of $67 million and $61 million
at December 31, 2000 and 2001, respectively, consisted primarily of loans
maturing through 2006. Some covenants under these loans restrict some
F-28
actions by REPGB. The weighted-average interest rate of these loans at December
31, 2000 and 2001 was 7.93% and 7.35%, respectively. During the second quarter
of 2000, REPGB 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 REPGB were used to finance the debt
repurchase.
As of December 31, 2001, maturities of borrowings classified as long-term
debt were $24 million in 2002, $539 million in 2003, $42 million in 2004, $12
million in 2005, $12 million in 2006 and $263 million in 2007 and beyond.
(c) OFF-BALANCE SHEET FINANCINGS.
For information regarding off-balance sheet financings and REMA
sale-leaseback transactions, see Notes 13(c) and 13(h).
(9) STOCKHOLDERS' EQUITY
(a) INITIAL PUBLIC OFFERING.
In May 2001, Reliant Resources offered 59.8 million shares of its common
stock to the public at an IPO price of $30 per share and received net proceeds
from the IPO of $1.7 billion. Pursuant to the terms of the master separation
agreement between Reliant Energy and Reliant Resources, the Company used $147
million of the net proceeds to repay certain indebtedness owed to Reliant
Energy. The Company used the remainder of the net proceeds of the IPO for
repayment of third party borrowings, capital expenditures, repurchases of common
stock and to increase the Company's working capital.
(b) TREASURY STOCK PURCHASES.
In July 2001, the Board of Directors authorized the Company to purchase up
to one million shares of its common stock in anticipation of funding benefit
plan obligations expected to be funded prior to the Distribution. On September
18, 2001, the Board of Directors authorized the Company to purchase up to 10
million additional shares of common stock through February 2003, and on December
6, 2001, the Board of Directors authorized the Company to purchase up to an
additional 10 million shares of its common stock through June 2003. During 2001,
the Company purchased 11 million shares of its common stock at an average price
of $17.22 per share, or an aggregate purchase price of $189 million. The 11
million shares in treasury stock purchases increased Reliant Energy's percentage
ownership in the Company from approximately 80% to approximately 83%. Reliant
Energy recorded the acquisition of treasury shares under the purchase method of
accounting and pushed-down the effect to the Company. As such, the Company
recorded a decrease in goodwill related to REPGB and additional paid-in capital
of $43 million.
F-29
(10) EARNINGS PER SHARE
The following table presents Reliant Resources' basic and diluted earnings
per share (EPS) calculation for the year ended December 31, 2001 (shares in
thousands). There were no dilutive reconciling items to net income.
Diluted Weighted Average Shares Calculation:
Weighted average shares outstanding ............................. 277,144
Plus: Incremental shares from assumed conversions:
Stock options .............................................. 2
Restricted stock ........................................... 244
Employee stock purchase plan ............................... 83
-------
Weighted average shares assuming dilution .................... 277,473
=======
Basic and Diluted EPS:
Income before cumulative effect of accounting change ......... $ 2.00
Cumulative effect of accounting change, net of tax ........... 0.01
-------
Net income ................................................... $ 2.01
=======
For 2001, the computation of diluted EPS excludes purchase options for
8,528,098 shares of common stock that have an exercise price (ranging from
$23.20 to $34.03) greater than the per share average market price ($22.11) for
the period and would thus be anti-dilutive if exercised.
Prior to August 9, 2000, Reliant Resources, Inc. was not a separate legal
entity and therefore had no historical capital structure. Accordingly, earnings
per share have not been presented for 2000.
Reliant Resources' Certificate of Incorporation was amended to effect a
240,000 to 1 stock split of Reliant Resources' common stock on January 5, 2001.
(11) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS
(a) Stock-Based Incentive Compensation Plans.
Subsequent to the IPO, the Company's eligible employees and non-employee
directors began participating in Reliant Resources' Long-Term Incentive Plan
(LTIP) that provides for the issuance of stock-based incentives, including
performance-based shares or units, restricted shares, stock options and stock
appreciation rights, to key employees of the Company, including officers.
Prior to the IPO, the Company's eligible employees participated in Reliant
Energy's Long-Term Incentive Compensation Plan (Reliant Energy LICP) and other
incentive compensation plans that provide for the issuance of stock-based
incentives, including performance-based shares, 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 Reliant
Energy LICP. Stock-based incentive grants and expense information presented
herein represents the Company's portion of the overall plans.
Performance-based shares and restricted shares have been granted to
employees without cost to the participants under the Reliant Energy LICP and the
LTIP. The performance-based shares generally vest three years after the grant
date based upon performance objectives 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 six-year period. Upon
vesting, the shares are issued to the plans' participants. During 1999, 2000 and
2001, the Company recorded compensation expense of $0.9 million, $6.7 million
and $8.2 million, respectively, related to performance-based shares and
restricted share grants. The following table summarizes performance-based shares
and restricted share grant activity related to the Company for the years 1999
through 2001:
F-30
RELIANT ENERGY RELIANT RESOURCES
----------------------------------- --------------------------------
NUMBER OF NUMBER OF NUMBER OF NUMBER OF
PERFORMANCE-BASED RESTRICTED PERFORMANCE-BASED RESTRICTED
SHARES SHARES SHARES SHARES
----------------- ---------- ----------------- ----------
Outstanding at December 31, 1998 ...................... 135,301 8,626
Granted ............................................ 115,501 87,429
Released to participants ........................... (14,764) (2,869)
------- -------
Outstanding at December 31, 1999 ...................... 236,038 93,186
Granted ............................................ 106,125 143,727
Released to participants ........................... (16,225) (3,473)
Canceled ........................................... (40,610) --
------- --------
Outstanding at December 31, 2000 ...................... 285,328 233,440
Shares relating to transferred employees ........... 224,325 72,390
Granted ............................................ -- -- 693,135 156,674
Released to participants ........................... (57,735) (99,561) -- --
Canceled ........................................... (26,843) (330) -- --
-------- -------- ------- -------
Outstanding at December 31, 2001 ...................... 425,075 205,939 693,135 156,674
-------- -------- ------- -------
Weighted average fair value of performance and
restricted stock granted for 1999 .................. $ 26.16 $ 26.97
======== ========
Weighted average fair value of performance and
restricted stock granted for 2000 .................. $ 24.18 $ 30.87
======== ========
Weighted average fair value of performance and
restricted stock granted for 2001 .................. $ 22.50 $ 33.11
======= =======
Assuming the Distribution occurs during 2002, as of the Distribution,
Reliant Energy's compensation committee will convert outstanding performance
shares under the Reliant Energy LICP 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-based 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 Reliant Energy or with the Company
through December 31, 2002. On the date of the Distribution, holders of these
time-based restricted shares will receive shares of the Company's common stock
in the same manner as other holders of Reliant Energy common stock, but these
shares of the Company's 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-based shares were granted. Thus, following the
Distribution, employees who held performance-based shares under Reliant Energy's
LICP for the performance cycle ending December 31, 2002 will hold time-based
restricted shares of Reliant Energy's common stock and time-based restricted
shares of the Company's common stock which will vest following continuous
employment through December 31, 2002.
In 2001, some employees of Reliant Energy, primarily corporate support and
executive officers, transferred to the Company. These employees held Reliant
Energy performance-based shares and restricted shares of approximately 224,000
and approximately 72,000, respectively.
Under both Reliant Energy's and the Company's plans, 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 based on
the average of the high and low sales price of the applicable 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 related to the
Company for the years 1999 through 2001:
F-31
RELIANT ENERGY RELIANT RESOURCES
--------------------------------- --------------------------------
NUMBER WEIGHTED AVERAGE NUMBER WEIGHTED AVERAGE
OF SHARES EXERCISE PRICE OF SHARES EXERCISE PRICE
--------- ---------------- --------- ----------------
Outstanding at December 31, 1998 ................... 681,109 $ 25.11
Options granted ................................. 1,311,657 27.06
Options exercised ............................... (21,836) 14.47
Options canceled ................................ (145,345)
-----------
Outstanding at December 31, 1999 ................... 1,825,585 26.47
-----------
Options granted ................................. 2,100,239 23.33
Options exercised ............................... (700,863) 21.67
Options canceled ................................ (128,706)
-----------
Outstanding at December 31, 2000 ................... 3,096,255 24.71
-----------
Options relating to transferred employees ....... 3,714,223 24.31
Options granted ................................. 116,492 41.62 8,826,432 $ 29.82
Options exercised ............................... (817,563) 24.06 --
Options canceled ................................ (223,288) (245,830)
----------- -----------
Outstanding at December 31, 2001 ................... 5,886,119 24.81 8,580,602 29.86
----------- -----------
Options exercisable at December 31, 1999 ........... 256,958 24.92
===========
Options exercisable at December 31, 2000 ........... 458,659 26.64
===========
Options exercisable at December 31, 2001 ........... 2,683,755 25.62 6,500 30.00
=========== ===========
Exercise prices for Reliant Energy stock options outstanding and held by
Company employees ranged from $17.75 to $50.00. Exercise prices for Reliant
Resources stock options outstanding held by Company employees ranged from $15.65
to $34.03. The following tables provide information with respect to outstanding
Reliant Energy and Reliant Resources stock options held by the Company's
employees at December 31, 2001:
RELIANT ENERGY
-----------------------------------------------
AVERAGE REMAINING AVERAGE
OPTIONS EXERCISE CONTRACTUAL LIFE
OUTSTANDING PRICE (YEARS)
----------- -------- -----------------
Ranges of Exercise Prices
Exercisable at:
$17.75 -- $26.00 .............. 3,586,020 $21.46 7.7
$26.01 -- $50.00 .............. 2,300,099 30.03 7.6
---------
Total ....................... 5,886,119 24.81 7.7
=========
RELIANT RESOURCES
----------------------------------------------
AVERAGE REMAINING AVERAGE
OPTIONS EXERCISE CONTRACTUAL LIFE
OUTSTANDING PRICE (YEARS)
----------- -------- -----------------
Ranges of Exercise Prices
Exercisable at:
$15.65 -- $23.50 .............. 95,436 $20.62 9.7
$23.51 -- $34.03 .............. 8,485,166 29.97 9.2
---------
Total ....................... 8,580,602 29.86 9.2
=========
The following table provides information with respect to exercisable
Reliant Energy stock options held by the Company's employees at December 31,
2001:
RELIANT ENERGY
-----------------------------
OPTIONS AVERAGE
EXERCISABLE EXERCISE PRICE
----------- --------------
Ranges of Exercise Prices Exercisable at:
$17.75 -- $26.00 .............................. 1,413,013 $22.69
$26.01 -- $47.22 .............................. 1,270,742 28.88
---------
Total ................................... 2,683,755 25.62
=========
F-32
At December 31, 2001, there were 6,500 exercisable Reliant Resources stock
options with an exercise price of $30.00 and a remaining contractual life of 9.2
years.
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 Reliant Energy options granted during 1999, 2000 and 2001 were
$3.13, $5.07 and $9.25, respectively. The weighted average fair value at date of
grant for Reliant Resources options granted during 2001 was $13.35. The fair
values were estimated using the Black-Scholes option valuation model with the
following weighted-average assumptions:
RELIANT ENERGY
------------------------------------
1999 2000 2001
------ ------ ------
Expected life in years ................... 5 5 5
Interest rate ............................ 5.10% 6.57% 4.87%
Volatility ............................... 21.23% 24.00% 31.91%
Expected common stock dividend ........... $ 1.50 $ 1.50 $ 1.50
RELIANT RESOURCES
-----------------
2001
-----------------
Expected life in years.................... 5
Interest rate............................. 4.94%
Volatility................................ 42.65%
Pro forma information for 1999, 2000 and 2001 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 income would have
been reduced by $1.3 million, $2.6 million and $22.5 million in 1999, 2000 and
2001, respectively.
Subject to the Distribution, Reliant Energy expects to convert all
outstanding Reliant Energy stock options granted prior to May 4, 2001 to a
combination of adjusted Reliant Energy stock options and Company stock options.
For the converted stock options, the sum of the intrinsic value of Reliant
Energy stock options immediately prior to the record date of the Distribution
will equal the sum of the intrinsic values of the adjusted Reliant Energy stock
options and the Company stock options granted immediately after the record date
of the Distribution. As such, Reliant Energy employees who do not work for the
Company will hold stock options of the Company.
(b) PENSION.
Effective March 1, 2001, the Company no longer accrued benefits under a
noncontributory pension plan for its domestic non-union employees (Resources
Participants). Effective March 1, 2001, each Resources Participant's unvested
accrued benefit was fully vested and a one-time benefit enhancement was provided
to some qualifying participants. After the Distribution, each Resources
Participant may elect to have his accrued benefit (a) left in the Reliant Energy
pension plan, (b) rolled over to a new Company savings plan or an individual IRA
account, or (c) paid in a lump-sum or annuity distribution. During 2001, the
Company incurred a charge to earnings of approximately $83 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 noncontributory and
non-qualified pension plans. In connection with the Distribution, the Company
expects to incur a loss of $57 million (pre-tax) related to the settlement of
Reliant Energy's pension plan and non-qualified pension plans. These charges
include costs incurred for former employees of Reliant Energy, primarily
corporate support and executive officers, who transferred to the Company on
January 1, 2001.
Except for its foreign subsidiaries and REMA union employees, prior to
March 1, 2001, the Company participated in Reliant Energy's noncontributory
pension plan. REMA union employees participate in a REMA noncontributory pension
plan. Effective January 1, 1999, Reliant Energy amended and restated its pension
plan and converted the present value of the accrued benefits under the existing
pension plan into a cash balance pension plan. 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, 2000 and first two months of 2001 was 4% in
each period.
F-33
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. As
of December 31, 2001, approximately 9% of the Reliant Energy noncontributory
pension plan assets was an investment in Reliant Energy common stock.
REPGB 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 $1.7 million for the three months ended December 31, 1999, and $6.4
million and $5.6 million for 2000 and 2001, respectively.
Net pension cost for the Company (excluding REPGB) includes the following
components:
YEAR ENDED DECEMBER 31,
---------------------------------
1999 2000 2001
----- ----- -----
(IN MILLIONS)
Service cost -- benefits earned during the period ..... $ 1.8 $ 3.6 $ 3.5
Interest cost on projected benefit obligation ......... 1.8 2.1 8.2
Expected return on plan assets ........................ (2.3) (3.3) (11.9)
Curtailment and benefits enhancements ................. -- -- 44.9
Net amortization ...................................... 0.1 (0.3) 0.6
----- ----- -----
Net pension cost ............................. $ 1.4 $ 2.1 $45.3
===== ===== =====
F-34
Following are reconciliations of the Company's beginning and ending
balances of its retirement plan benefit obligation, plans assets and funded
status for 2000 and 2001 (excluding REPGB). The prepaid pension asset is
primarily recorded in other long-term assets.
YEAR ENDED DECEMBER 31,
------------------------
2000 2001
-------- --------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year ........... $ 24.0 $ 28.7
Service cost .................................... 3.6 3.5
Interest cost ................................... 2.1 8.2
Curtailments and benefits enhancement ........... -- 55.8
Transfers from affiliates ....................... -- 35.4
Acquisitions .................................... 1.0 --
Actuarial (gain) loss ........................... (2.0) 6.0
-------- --------
Benefit obligation, end of year ................. $ 28.7 $137.6
======== ========
CHANGE IN PLANS ASSETS
Plans assets, beginning of year ................. $ 31.0 $ 27.3
Transfers/allocations from affiliates ........... -- 124.8
Employer contributions .......................... -- 0.7
Acquisitions .................................... 1.0 --
Actual investment return ........................ (4.7) --
-------- --------
Plans assets, end of year ....................... $ 27.3 $152.8
======== ========
RECONCILIATION OF FUNDED STATUS
Funded status ................................... $ (1.4) $ 15.2
Unrecognized transition asset ................... -- (0.2)
Unrecognized prior service cost ................. (2.8) --
Unrecognized actuarial loss ..................... 4.6 14.8
-------- --------
Net amount recognized at end of year ............ $ 0.4 $ 29.8
======== ========
ACTUARIAL ASSUMPTIONS
Discount rate ................................... 7.5% 7.25%
Rate of increase in compensation levels ......... 3.5--5.5% 3.5--5.5%
Expected long-term rate of return on assets ..... 10.0% 9.5%
As all distributions from the Reliant Energy noncontributory plan to
Resources Participants after the Distribution will be made from Reliant Energy
plan assets, actual investment returns on plan assets above or below expected
returns on plan assets are included in "transfers/allocations from affiliates"
in the above reconciliation in 2001.
The accumulated benefit obligation and fair value of plan assets for the
REMA noncontributory pension plan were $4.7 million and $1.7 million,
respectively, as of December 31, 2001.
The actuarial loss during 2001 was primarily due to the decrease in
discount rate and changes in demographics of the participants.
In addition to the noncontributory pension plans discussed above, the
Company participates in Reliant Energy's non-qualified pension plans which allow
participants to retain the benefits to which they would have been entitled under
Reliant Energy's qualified 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 $2 million in 2001 and was immaterial in 1999 and 2000. The accrued
benefit liability for the nonqualified pension plan was $1 million and $30
million of December 31, 2000 and December 31, 2001, respectively. In addition,
the accrued benefit liabilities as of December 31, 2001 include the recognition
of minimum liability adjustments of $11 million, which is reported as a
component of comprehensive income net of income tax effects. Effective March 1,
2001, the Company no longer provides future non-qualified pension benefits to
its employees.
F-35
(c) SAVINGS PLAN.
Except for its foreign subsidiaries and REMA employees, the Company
participates in Reliant Energy's employee savings plan that is a tax qualified
plan under Section 401(a) of the Internal Revenue Code of 1986, as amended
(Code), and includes a cash or deferred arrangement under Section 401(k) of the
Code. REMA employees participate in REMA employee savings plans that are
tax-qualified plans under Section 401(a) of the Code and include cash or
deferred arrangements under Section 401(k) of the Code. Under the plans,
participating 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 some
matching contributions subject to a vesting schedule. Through March 1, 2001, a
substantial portion of Reliant Energy's employee savings plan match was made in
Reliant Energy common stock.
Effective March 1, 2001, Reliant Energy amended its savings plan and
REMA's non-union employee savings plan to generally provide for (a) employer
matching contributions equal to 100% of the first 6% of each employee's
contributions to the plan, (b) a 2% employer contribution on a payroll basis for
2002, limited to the first $85,000 of compensation, and (c) discretionary
employer contributions up to 3% at the end of the plan year based on each
employee's eligible compensation. Effective March 1, 2001, all prior and future
employer contributions on behalf of such employees are fully vested.
The Company's savings plan benefit expense was $2 million, $6 million and
$20 million in 1999, 2000 and 2001, respectively.
On February 1, 2002, the Company established an employee savings plan that
is a tax-qualified plan under Section 401(a) of the Code and includes a cash or
deferred arrangement under Section 401(k) of the Code for substantially all its
non-union employees except for its foreign subsidiaries' employees. The Company
savings plan match and any payroll period discretionary employer contribution
will be made in cash; any discretionary annual employer contribution may be made
in the Company's common stock, cash or both. Beginning January 1, 2002, the
Company established a separate savings plan for its union employees.
(d) POSTRETIREMENT BENEFITS.
Effective March 1, 2001, the Company discontinued providing subsidized
postretirement benefits to its domestic non-union employees. 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. In connection
with the Distribution, the Company expects to incur a pre-tax gain of $21
million related to the settlement of the postretirement benefit obligation.
These charges include the effect of the curtailment and settlement of the
postretirement obligation for former employees of Reliant Energy, primarily
corporate support and executive officers, who transferred to the Company on
January 1, 2001. Prior to March 1, 2001, through a Reliant Energy subsidized
postretirement plan, the Company provided some postretirement benefits for
substantially all of its retired employees. The Company continues to provide
subsidized postretirement benefits to certain union employees.
REPGB 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.
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 was amortizing over a 20-year period approximately
$4 million to cover the "transition cost" of adopting SFAS No. 106. Upon
curtailment of the plan, the remaining transition cost was recognized. The
Company funds its portion of the postretirement benefits on a pay-as-you-go
basis.
F-36
Net postretirement benefit cost for the Company includes the following
components:
YEAR ENDED DECEMBER 31,
-------------------------------
1999 2000 2001
----- ----- -----
(IN MILLIONS)
Service cost -- benefits earned during the period ...... $ 0.5 $ 1.4 $ 2.0
Interest cost on projected benefit obligation .......... 1.0 2.0 2.7
Curtailment ............................................ -- -- 39.5
Net amortization ....................................... 0.4 0.4 0.1
----- ----- -----
Net postretirement benefit cost ................... $ 1.9 $ 3.8 $44.3
===== ===== =====
Following are reconciliations of the Company's beginning and ending
balances of its postretirement benefit plans' benefit obligation and funded
status for 2000 and 2001:
YEAR ENDED DECEMBER 31,
-----------------------
2000 2001
-------- ---------
(IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year ......... $ 31.5 $ 35.0
Service cost .................................. 1.4 2.0
Interest cost ................................. 2.0 2.7
Benefit payments .............................. (1.0) (1.4)
Transfers from affiliates ..................... -- 9.8
Acquisitions .................................. 2.2 --
Foreign exchange impact ....................... (1.4) (2.5)
Actuarial loss ................................ 0.3 2.9
-------- ---------
Benefit obligation, end of year ............... $ 35.0 $ 48.5
======== =========
RECONCILIATION OF FUNDED STATUS
Funded status ................................. $(35.0) $(48.5)
Unrecognized transition obligation ............ 2.7 --
Unrecognized prior service cost ............... 2.9 --
Unrecognized actuarial loss ................... 1.2 5.7
-------- ---------
Net amount recognized at end of year .......... $(28.2) $(42.8)
======== =========
ACTUARIAL ASSUMPTIONS
Discount rate ................................. 6.6--7.5% 6.6--7.25%
Rate of increase in compensation levels ....... 2.0% 2.0%
(e) POSTEMPLOYMENT BENEFITS.
The Company records postemployment benefits based on SFAS No. 112,
"Employer's Accounting for Postemployment Benefits," which requires the
recognition of a liability for benefits provided to 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). Net postemployment benefit costs
were not material in 1999, 2000 and 2001.
(f) EMPLOYEE STOCK PURCHASE PLAN.
In the second quarter 2001, the Company established the Employee Stock
Purchase Plan (ESPP). Under the ESPP, employees may contribute up to 15% of
their compensation, as defined, towards the purchase of shares of the Company's
common stock at a price of 85% of the lower of the market value at the beginning
of the purchase period or end of each six-month purchase period. The initial
purchase period began on the date of the IPO and ended December 31, 2001. The
market value of the shares acquired by a participant in any year may not exceed
$25,000. In January 2002, 550,781 shares were sold to employees under the ESPP
at a price of $14.07 per share, related to the initial purchase period.
F-37
(g) OTHER NON-QUALIFIED PLANS.
Through December 31, 2001, certain eligible employees participated in
Reliant Energy's deferred compensation plans, which permit participants to elect
each year to defer a percentage of that year's salary (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. On January 1,
2001, some employees of Reliant Energy, primarily corporate support and
executive officers, transferred to the Company. As of January 1, 2001, the
discounted deferred compensation obligation of $13 million attributable to these
employees was transferred to the Company. The Company recorded interest expense
related to its deferred compensation obligation of approximately $1 million
during 1999 and 2000 and $4 million during 2001. The discounted deferred
compensation obligation recorded by the Company was $7 million and $29 million
as of December 31, 2000 and 2001, respectively. Each Reliant Resources
participant has elected to have his non-qualified deferred compensation plan
account balance, after the Distribution: (a) placed in a new Reliant Resources
deferred compensation plan, which generally mirrors the former Reliant Energy
deferred compensation plans, or (b) rolled over to the new non-qualified
deferred compensation plan discussed below.
Effective January 1, 2002, select key and highly compensated employees
were eligible to participate in a new Company nonqualified deferred compensation
and restoration plan. The plan allows eligible employees to elect to defer up to
80% of their annual base salary and/or up to 100% of their eligible annual
bonus. In addition, the plan allows participants to retain the benefits which
they would have been entitled to under Reliant Resources' qualified savings
plans, except for the federally mandated limits on these benefits or on the
level of salary on which these benefits may be calculated. The Company funds
these deferred compensation and restoration liabilities by making contributions
to a rabbi trust. Plan participants direct the allocation of their deferrals and
restoration benefits between one or more of the Company's designated investment
funds within the rabbi trust.
(h) OTHER EMPLOYEE MATTERS.
As of December 31, 2001, approximately 31% of the Company's employees are
subject to collective bargaining arrangements, of which contracts covering 17%
of the Company's employees will expire prior to December 31, 2002. Of these
employees subject to collective bargaining agreements, 48% are employed by REPGB
in the Netherlands.
(12) INCOME TAXES
The components of income before taxes are as follows:
YEAR ENDED DECEMBER 31,
----------------------------------
1999 2000 2001
------ ------ ------
(IN MILLIONS)
United States ........................... $ 0.3 $178.5 $720.5
Foreign ................................. 26.3 112.6 105.5
------ ------ ------
Income before income taxes ......... $ 26.6 $291.1 $826.0
====== ====== ======
F-38
The Company's current and deferred components of income tax expense
(benefit) were as follows:
YEAR ENDED DECEMBER 31,
------------------------------------
1999 2000 2001
------ ------ ------
(IN MILLIONS)
Current
Federal ................ $(13.6) $ 99.7 $247.6
State .................. 0.6 16.4 4.3
Foreign ................ -- -- (2.7)
------ ------ ------
Total current ........ (13.0) 116.1 249.2
------ ------ ------
Deferred
Federal ................ 16.4 (28.2) 10.7
State .................. (0.8) 0.7 15.7
Foreign ................ -- -- (4.0)
------ ------ ------
Total deferred ....... 15.6 (27.5) 22.4
------ ------ ------
Income tax expense ........ $ 2.6 $ 88.6 $271.6
====== ====== ======
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
YEAR ENDED DECEMBER 31,
--------------------------------------
1999 2000 2001
------ ------ ------
(IN MILLIONS)
Income before income taxes ........................................................ $ 26.6 $291.1 $826.0
Federal statutory rate ............................................................ 35% 35% 35%
------ ------ ------
Income tax expense at statutory rate .............................................. 9.3 101.9 289.1
------ ------ ------
Net addition (reduction) in taxes resulting from:
State income taxes, net of valuation allowances and federal income tax
benefit ...................................................................... (0.1) 11.1 13.0
REPGB tax holiday .............................................................. (10.1) (37.8) (49.9)
Goodwill amortization .......................................................... 1.4 2.1 8.6
Federal and foreign valuation allowance ........................................ 1.6 12.8 3.3
Other, net ..................................................................... 0.5 (1.5) 7.5
------ ------ ------
Total ........................................................................ (6.7) (13.3) (17.5)
------ ------ ------
Income tax expense ................................................................ $ 2.6 $ 88.6 $271.6
====== ====== ======
Effective rate .................................................................... 9.6% 30.4% 32.9%
REPGB Tax Holiday. Under 1998 Dutch tax law relating to the Dutch
electricity industry, REPGB qualifies for a zero percent tax rate through
December 31, 2001. The tax holiday applies only to the Dutch income earned by
REPGB. Beginning January 1, 2002, REPGB is subject to Dutch corporate income tax
at standard statutory rates, which is currently 34.5% which was enacted in 2001.
Prior to 2001, the enacted rate was 35%. The effect of the change in the enacted
tax rate was not material to the Company's results of operations.
Undistributed Earnings of Foreign Subsidiaries. The undistributed earnings
of foreign subsidiaries aggregated $266 million as of December 31, 2001, 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.
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:
F-39
YEAR ENDED DECEMBER 31,
-----------------------
2000 2001
------ ------
(IN MILLIONS)
Deferred tax assets:
Current:
Allowance for doubtful accounts and credit provisions ...... $ 16.0 $ 59.5
Other ...................................................... -- 4.8
------ ------
Total current deferred tax assets ........................ 16.0 64.3
------ ------
Non-current:
Employee benefits .......................................... 17.8 44.3
Operating loss carryforwards ............................... 21.8 18.1
Environmental reserves ..................................... 19.5 15.0
Foreign exchange gains ..................................... 11.5 11.1
Non-trading derivative liabilities, net .................... -- 95.5
Non-derivative stranded costs liability .................... -- 73.1
Other ...................................................... 34.7 30.1
Valuation allowance ........................................ (20.3) (15.6)
------ ------
Total non-current deferred tax assets .................... 85.0 271.6
------ ------
Total deferred tax assets ................................ $101.0 $335.9
====== ======
Deferred tax liabilities:
Current:
Trading and marketing assets, net .......................... $ 16.0 $ 48.4
Non-trading derivative assets, net ......................... -- 27.4
Hedges of net investment in foreign subsidiaries ........... -- 52.1
------ ------
Total current deferred tax liabilities ................... 16.0 127.9
------ ------
Non-current:
Depreciation ............................................... 108.5 133.6
Trading and marketing assets, net .......................... -- 27.5
Stranded costs indemnification receivable .................. -- 73.1
Other ...................................................... 7.7 29.3
------ ------
Total non-current deferred tax liabilities ............... 116.2 263.5
------ ------
Total deferred tax liabilities ........................... $132.2 $391.4
------ ------
Accumulated deferred income taxes, net ................... $ 31.2 $ 55.5
====== ======
Tax Attribute Carryforwards. At December 31, 2001, the Company had
approximately $6 million, $132 million and $45 million of federal, state and
foreign net operating loss carryforwards, respectively. The federal and state
loss carryforwards can be carried forward to offset future income through the
year 2021. The foreign losses can be carried forward indefinitely.
The valuation allowance reflects a net increase of $17 million in 2000 and
a $5 million net decrease in 2001. These net changes resulted from a
reassessment of the Company's future ability to use federal, state and foreign
tax net operating loss carryforwards.
As discussed in Note 13(f), the Dutch parliament has adopted legislation
allocating to the Dutch generation sector, including REPGB, financial
responsibility for certain stranded costs and other liabilities incurred by NEA
prior to the deregulation of the Dutch wholesale market. These obligations
include NEA's obligations under a stranded cost gas supply contract and three
stranded cost electricity contracts. As a result of the above, the Company
recorded an out-of-market, net stranded cost liability of $369 million and a
related deferred tax asset of $127 million at December 31, 2001 for the
Company's statutorily allocated share of these gas supply and electricity
contracts. The Company believes that the costs incurred by REPGB subsequent to
the tax holiday ending in 2001 related to these contracts will be deductible for
Dutch tax purposes. However, due to the uncertainties related to the
deductibility of these costs, the Company has recorded an offsetting liability
in other liabilities of $127 million as of December 31, 2001.
F-40
(13) COMMITMENTS AND CONTINGENCIES
(a) COMMITMENTS AND GUARANTEES.
As of December 31, 2001, the Company's Wholesale Energy segment had
entered into commitments associated with various non-rate regulated electric
generating projects, including commitments for the purchase of combustion
turbines, aggregating $440 million. In addition, Wholesale Energy has options to
purchase additional generating equipment for a total estimated cost of $42
million for future generation projects. The Company is actively attempting to
remarket this equipment.
The Company is a party to several fuel supply contracts, commodity
transportation contracts, and purchase power and electric capacity contracts,
that have various quantity requirements and durations that are not classified as
non-trading derivatives assets and liabilities or trading and marketing assets
and liabilities in the Company's Consolidated Balance Sheet as of December 31,
2001 as these contracts meet the SFAS No. 133 exception to be classified as
"normal purchases contracts" (see Note 6) or do not meet the definition of a
derivative. The maximum duration of any of these commitments is 21 years.
Minimum purchase commitment obligations under these agreements are as follows
for the next five years, as of December 31, 2001 (in millions):
PURCHASED POWER
AND ELECTRIC AND
TRANSPORTATION GAS CAPACITY
FUEL COMMITMENTS COMMITMENTS COMMITMENTS
---------------- -------------- ----------------
2002 .................... $105 $ 45 $315
2003 .................... 39 84 119
2004 .................... 45 101 61
2005 .................... 45 101 61
2006 .................... 45 101 61
---- ---- ----
Total ................ $279 $432 $617
==== ==== ====
The maximum duration under any individual fuel supply contract and
transportation contract is 18 years and 21 years, respectively.
The Company's aggregate electric capacity commitments, including capacity
auction products, are for 7,496 MW, 1,800 MW, 1,000 MW, 1,000 MW and 1,000 MW
for 2002, 2003, 2004, 2005 and 2006, respectively. The maximum duration under
any individual commitment is five years. Included in the above purchase power
and electric capacity commitments are amounts acquired through an affiliate of
the Company. For additional discussion of this related party commitment, see
Note 3.
As of December 31, 2001, the Company has sale commitments, including
electric energy and capacity sale contracts and district heating contracts (see
Note 13(f)) which are not classified as non-trading derivative assets and
liabilities or trading and marketing assets and liabilities in the Company's
Consolidated Balance Sheet as these contracts meet the SFAS No. 133 exception to
be classified as "normal sales contracts" or do not meet the definition of a
derivative. The estimated minimum sale commitments under these contracts are
$450 million, $211 million, $194 million, $174 million and $159 million in 2002,
2003, 2004, 2005 and 2006, respectively.
In addition, in January 2002, the Company began providing retail electric
services to approximately 1.5 million residential and small commercial customers
previously served by Reliant Energy's electric utility division. Within Reliant
Energy's electric utility division's territory, prices that may be charged to
residential and small commercial customers by this retail electric service
provider are subject to a fixed, specified price (price to beat) at the outset
of retail competition. The Texas Utility Commission's regulations allow this
retail electric provider to adjust its price to beat fuel factor based on a
percentage change in the price of natural gas. In addition, the retail electric
provider may also request an adjustment as a result of changes in its price of
purchased energy. The retail electric provider may request that its price to
beat be adjusted twice a year. The Company will not be permitted to sell
electricity to residential and small commercial customers in the incumbent's
traditional service territory 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
the relevant class of customers is committed to be served by other retail
electric providers.
F-41
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 Statement of Consolidated Income 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.
The Company guarantees the performance of certain of its subsidiaries'
trading and hedging obligations. As of December 31, 2001, the fixed maximum
amount of such guarantees was $4.7 billion. In addition, the Company has issued
letters of credit totaling $51 million in connection with its trading
activities. The Company does not consider it likely that it would be required to
perform or otherwise incur any losses associated with these guarantees.
In addition to the above discussions, the Company's other commitments have
various quantity requirements and durations and are not considered material
either individually or in the aggregate to the Company's results of operations
or cash flows.
(b) TRANSPORTATION AGREEMENT.
Prior to the merger of a subsidiary of Reliant Energy and RERC Corp., a
predecessor of Reliant Energy Services Inc. (Reliant Energy Services) (a wholly
owned subsidiary of the Company) entered into a transportation agreement (ANR
Agreement) with ANR Pipeline Company (ANR) that contemplated a transfer to ANR
of an interest in some of RERC Corp.'s pipelines and related assets that are not
a part of the Company. The interest represented capacity of 250 million cubic
feet (Mmcf)/day. Under the ANR agreement, an ANR affiliate advanced $125 million
to Reliant Energy Services. Subsequently, the parties restructured the ANR
Agreement and Reliant Energy Services refunded in 1993 and 1995, $34 million and
$50 million, respectively, to ANR. As of December 31, 2000 and 2001, Reliant
Energy Services had recorded $28 million and $31 million, respectively, in
long-term other liabilities in the Consolidated Balance Sheets to reflect the
Company's discounted obligation to ANR for the use of 130 Mmcf/day of capacity
in some of RERC Corp.'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 the remaining
balance of $36 million.
Prior to the IPO, Reliant Energy Services and a subsidiary of Reliant
Energy entered into an agreement whereby the subsidiary of Reliant Energy agreed
to reimburse Reliant Energy Services for any transportation payments made under
the ANR Agreement and for the refund of the $41 million discussed above. In the
Consolidated Balance Sheets, the Company has recorded a long-term notes
receivable from an affiliate of $28 million and $31 million as of December 31,
2000 and 2001, respectively.
(c) LEASE COMMITMENTS.
In August 2000, the Company entered into separate sale-leaseback
transactions with each of three owner-lessors 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
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, including having a rating on REMA's long-term
unsecured senior debt of at least BBB from Standard and Poor's and Baa2 from
Moody's, guarantees the lease obligations. The Company will make lease payments
through 2029. The lease term expires in 2034. As of December 31, 2001, REMA had
$167 million of restricted funds that are available for REMA's working capital
needs and to make future lease payments, including a lease payment of $55
million which was made in January 2002.
F-42
In the first quarter of 2001, the Company entered into tolling
arrangements with a third party to purchase the rights to utilize and dispatch
electric generating capacity of approximately 1,100 MW extending through 2012.
This electricity will be generated by two gas-fired, simple-cycle peaking
plants, with fuel oil backup which are being constructed by a tolling partner.
The Company anticipates construction to be completed by the summer of 2002, at
which time the Company will commence tolling payments. The tolling arrangements
qualify as operating leases.
In February 2001, Reliant Energy entered into a lease for office space for
the Company in a building under construction. The lease agreement was assigned
by Reliant Energy to the Company by an assignment and assumption agreement in
June 2001. The lease term, which commences in the second quarter 2003, is 15
years with two five-year renewal options. The Company has the right to name the
building.
The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases as of December 31,
2001, which primarily relate to the REMA leases mentioned above. Other
non-cancelable, long-term operating leases principally consist of tolling
arrangements, as discussed above, rental agreements for building space,
including the office space lease discussed above, data processing equipment and
vehicles, including major work equipment:
REMA SALE-
LEASE OBLIGATION OTHER TOTAL
---------------- ------ ------
(IN MILLIONS)
2002 .............................. $ 136 $ 52 $ 188
2003 .............................. 77 72 149
2004 .............................. 84 87 171
2005 .............................. 75 89 164
2006 .............................. 64 90 154
2007 and beyond ................... 1,124 469 1,593
------ ------ ------
Total ........................ $1,560 $ 859 $2,419
====== ====== ======
Total lease expense for all operating leases was $2 million, $24 million
and $75 million during 1999, 2000 and 2001, respectively. During 2001, the
Company made lease payments related to the REMA sale-leaseback of $259 million.
As of December 31, 2001, the Company had recorded a prepaid lease obligation
related to the REMA sale-leaseback of $59 million and $122 million in other
current assets and other long-term assets, respectively.
(d) CROSS BORDER LEASES.
During the period from 1994 through 1997, under cross border lease
transactions, REPGB 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, 2001 of 1 to 23 years. REPGB 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 $1.6 billion
remained outstanding as of December 31, 2001. These transactions involve REPGB
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 REPGB of the
transactions were recorded as a deferred gain and are currently being amortized
to income over the lease terms. At December 31, 2000 and 2001, the unamortized
deferred gain on these transactions totaled $77 million and $68 million,
respectively. The power plants, related equipment and turbines remain on the
financial statements of REPGB and continue to be depreciated.
REPGB is required to maintain minimum insurance coverages, perform minimum
annual maintenance and, in specified situations, post letters of credit. REPGB's
shareholder is subject to some restrictions with respect to the liquidation of
REPGB's shares. In the case of early termination of these contracts, REPGB would
be contingently liable for some payments to the sublessors, which at December
31, 2001, are estimated to be $272 million. Starting in March 2000, REPGB 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 $272 million as of December 31, 2001. Commitments
for these letters of credit have been obtained as of December 31, 2001.
F-43
(e) ENVIRONMENTAL AND LEGAL MATTERS.
The Company is involved in environmental and legal proceedings before
various courts and governmental agencies regarding matters arising in the
ordinary course of business, some of which involve substantial amounts. The
Company's management regularly analyzes current information and, as necessary,
provides accruals for probable liabilities on the eventual disposition of these
matters. The Company's management believes that the effects on the Company's
respective financial statements, if any, from the disposition of these matters
will not have a material adverse effect on the Company's financial condition,
results of operations or cash flows.
Legal Matters.
California Wholesale Market. Reliant Energy, Reliant Energy Services, REPG
and several other subsidiaries of Reliant Resources, as well as three officers
of some of these companies, 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. Pursuant to the terms of the master separation agreement between
Reliant Energy and Reliant Resources (see Note 4(c)), Reliant Resources has
agreed to indemnify Reliant Energy for any damages arising under these lawsuits
and may elect to defend these lawsuits at the Company's 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; and
one was filed in the Superior Court of Los Angeles 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, costs of suit and attorneys' fees. The cases were initially removed
to federal court and were then assigned to Judge Robert H. Whaley, United States
District Judge, pursuant to the federal procedures for multi-district
litigation. On July 30, 2000, Judge Whaley remanded the cases to state court.
Upon remand to state court, the cases were assigned to Superior Court Judge
Janis L. Sammartino pursuant to the California state coordination procedures. On
March 4, 2002, Judge Sammartino adopted a schedule proposed by the parties that
would result in a trial beginning on March 1, 2004. On March 8, 2002, the
plaintiffs filed a single, consolidated complaint naming numerous defendants,
including Reliant Energy Services and other Reliant Resources' subsidiaries,
that restated the allegations described above and alleged that damages against
all defendants could be as much as $1 billion.
Plaintiffs have voluntarily dismissed Reliant Energy from two of the three
class actions in which it was named as a defendant. The ultimate outcome of the
lawsuits cannot be predicted with any degree of certainty at this time. However,
the Company believes, based on its analysis to date of the claims asserted in
these lawsuits and the underlying facts, that resolution of these lawsuits will
not have a material adverse effect on the Company's financial condition, results
of operations or cash flows.
On March 11, 2002, the California Attorney General filed a civil lawsuit
in San Francisco Superior Court naming Reliant Energy, Reliant Resources,
Reliant Energy Services, REPG, and several other subsidiaries of Reliant
Resources as defendants. Pursuant to the terms of the master separation
agreement between Reliant Energy and Reliant Resources (see Note 4(c)), Reliant
Resources has agreed to indemnify Reliant Energy for any damages arising under
these lawsuits and may elect to defend these lawsuits at the Company's own
expense. The Attorney General alleges various violations by the defendants of
state laws against unfair and unlawful business practices arising out of
transactions in the markets for ancillary services run by the California
Independent System Operator (Cal ISO). In addition to injunctive relief, the
Attorney General seeks restitution and disgorgement of alleged unlawful profits
for sales of electricity, and civil penalties. The ultimate outcome of this
lawsuit cannot be predicted with any degree of certainty at this time.
On March 19, 2002, the California Attorney General filed a complaint with
the FERC naming Reliant Energy Services and "all other public utility sellers"
in California as defendants. The complaint alleges that sellers with
market-based rates have violated their tariffs by not filing with the FERC
transaction-specific information about all of their sales and purchases at
market-based rates. The California Attorney General argues that, as a result,
all past sales should be subject to refund if found to be above just and
reasonable levels. The ultimate outcome of this complaint proceeding cannot be
predicted with any degree of certainty at this time. However, the Company
believes, based on its analysis to date of the claims asserted in the complaint,
the underlying facts, and the relevant
F-44
statutory and regulatory provisions, that resolution of this lawsuit will not
have a material adverse effect on the Company's financial condition, results of
operations or cash flows.
Environmental.
REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see Note 5(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 and 2001, REMA has liabilities associated with six future ash
disposal site closures and six current 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 and 2001. The
Company expects approximately $16 million will be paid over the next five years.
REPGB Asbestos Abatement and Soil Remediation. Prior to the Company's
acquisition of REPGB (see Note 5(b)), REPGB 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 REPGB's properties. REPGB 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 and 2001, the recorded estimated undiscounted liability for this asbestos
abatement and soil remediation was $24 million and $18 million, respectively
(f) INDEMNIFICATION AND SETTLEMENT OF STRANDED COSTS.
Background. In January 2001, the Dutch Electricity Production Sector
Transitional Arrangements Act (Transition Act) became effective and, among other
things, allocated to REPGB and the three other large-scale Dutch generation
companies, a share of the assets, liabilities and stranded cost commitments of
NEA. Prior to the enactment of the Transition Act, NEA acted as the national
electricity pooling and coordinating body for the generation output of REPGB and
the three other large-scale national Dutch generation companies. REPGB and the
three other large-scale Dutch generation companies are shareholders of NEA.
The Transition Act and related agreements specify that REPGB has a 22.5%
share of NEA's assets, liabilities and stranded cost commitments. NEA's stranded
cost commitments consisted primarily of various uneconomical or stranded cost
investments and commitments, including a gas supply and three power contracts
entered into prior to the liberalization of the Dutch wholesale electricity
market. REPGB's stranded cost obligations also include uneconomical district
heating contracts which were previously administrated by NEA prior to
deregulation of the Dutch power market.
The gas supply contract expires in 2016 and provides for gas imports
aggregating 2.283 billion cubic meters per year. Prior to December 31, 2001, one
of the stranded cost power contracts was settled. The two remaining stranded
cost power contracts have the following capacities and terms: (a) 300 MW through
2005, and (b) 600 MW through March 2002 and 750 MW through 2009. Under the
Transition Act, REPGB can either assume its 22.5% allocated interest in the
contracts or, subject to the terms of the contracts, sell its interests to third
parties. The district heating obligations relate to three heating water supply
contacts entered into with various municipalities and expire from 2013 through
2015. Under the district heating contracts, the municipal districts are required
to take annually a combined minimum of 5549 terajoules (TJ) increasing annually
to 7955 TJ over the life of the contracts.
The Transition Act also authorized the government to purchase from NEA at
least a majority of the shares in the Dutch national transmission grid company
which was sold to the Dutch government on October 25, 2001 for approximately NLG
2.6 billion (approximately $1.05 billion based on an exchange rate of 2.48 NLG
per U.S. dollar as of December 31, 2001).
Prior to December 31, 2001, the former shareholders agreed pursuant to a
share purchase agreement to indemnify REPGB for up to NLG 1.9 billion in
stranded cost liabilities (approximately $766 million). The
F-45
indemnity obligation of the former shareholders and various provincial and
municipal entities (including the city of Amsterdam), was secured by a NLG 900
million escrow account (approximately $363 million).
The Transition Act provided that, subject to the approval of the European
Commission, the Dutch government will provide financial compensation to the
Dutch generation companies, including REPGB, for liabilities associated with (a)
long-term district heating contracts and (b) an experimental coal facility. In
July 2001, the European Commission ruled that under certain conditions the Dutch
government can provide financial compensation to the generation companies for
the district heating contracts. To the extent that this compensation is not
ultimately provided to the generation companies by the Dutch government, REPGB
was to collect its compensation directly from the former shareholders as further
discussed below.
In January 2001, the Company recognized an out-of-market, net stranded
cost liability for its gas and electric contracts and district heating
commitments. At such time, the Company recorded a corresponding asset of equal
amount for the indemnification of this obligation from REPGB's former
shareholders and the Dutch government, as applicable. Pursuant to SFAS No. 133,
the gas and electric contracts are marked-to-market (see Note 6). As of December
31, 2001, the Company has recorded a liability of $369 million for its stranded
cost gas and electric commitments in non-trading derivative liabilities and a
liability of $206 million for its district heating commitments in current and
non-current other liabilities. As of December 31, 2001, the Company has recorded
an indemnification receivable from the Dutch government for the district heating
stranded cost liability of $206 million. The settlement of the indemnification
related to gas and electric contract commitments in December 2001 is discussed
below.
Settlement of Stranded Cost Indemnification. In December 2001, REPGB and
its former shareholders entered into a settlement agreement immediately
resolving the former shareholders of their stranded cost indemnity obligations
related to the gas supply and power contracts under the original share purchase
agreement, and provides conditional terms for the possible settlement of their
stranded cost indemnity obligation related to district heating obligations under
certain conditions. The settlement agreement was approved in December 2001 by
the Ministry of Economic Affairs of the Netherlands.
Under the settlement agreement, the former shareholders paid to REPGB NLG
500 million ($202 million) in January and February 2002. The payment represents
a settlement of the obligations of the former shareholders to indemnify REPGB
for all stranded cost liabilities other than those relating to the district
heating contracts. The full amount of this payment was placed into an escrow
account in the name of REPGB to fund its stranded cost obligations related to
the gas and electric import contracts. Any remaining escrow funds as of January
1, 2004 will be distributed to the REPGB.
Under the settlement agreement, the former shareholders will continue to
indemnify REPGB for the certain stranded cost liabilities relating to district
heating contracts. The terms of the indemnity are as follows:
- The settlement agreement acknowledges that the Netherlands is
finalizing regulations for compensation of stranded cost associated
with district heating projects. Within 21 days after the date these
compensation rules take effect, REPGB can elect to receive one of
two forms of indemnification under the settlement agreement.
- If the compensation to be paid by the Netherlands under these rules
is at least as much as the compensation to be paid under the
original indemnification agreement, REPGB can elect to receive a
one-time payment of NLG 60 million ($24 million). In addition,
unless the decree implementing the new compensation rules provides
for compensation for the lifetime of the district heating projects,
REPGB can receive an additional cash payment of NLG 15 million ($6
million).
- If the compensation rules do not provide for compensation at least
equal to that provided under the original indemnification agreement,
REPGB can claim indemnification for stranded cost losses up to a
maximum of NLG 700 million ($282 million) less the amount of
compensation provided by the new compensation rules and certain
proceeds received from arbitrations.
- If no new compensation rules have taken effect on or prior to
December 31, 2003, REPGB is entitled, but not obligated, to elect to
receive indemnification under the formula described above.
F-46
Under the terms of the original indemnification agreement, the former
shareholders were entitled to receive any and all distributions and dividends
above NLG 125 million ($51 million) paid by NEA. Under the settlement agreement,
the former shareholders waived all rights under the original indemnification
agreement to claim distributions of NEA.
The Company recognized a net gain of $37 million for the difference
between the sum of (a) the cash settlement payment of $202 million and the
additional rights to claim distributions of the Company's NEA investment
recognized of $248 million and (b) the amount recorded as stranded cost
indemnity receivable related to the stranded cost gas and electric commitments
of $369 million and claims receivable related to stranded cost incurred in 2001
of $44 million both previously recorded in the Company's Consolidated Balance
Sheet.
Investment in NEA. During the second quarter of 2001, the Company recorded
a $51 million pre-tax gain (NLG 125 million) recorded as equity income for the
preacquisition gain contingency related to the acquisition of REPGB for the
value of its equity investment in NEA. This gain was based on the Company's
evaluation of NEA's financial position and fair value. The fair value of the
Company's investment in NEA is dependent upon the ultimate resolution of its
existing contingencies and proceeds received from liquidating its remaining net
assets. Prior to the settlement agreement discussed above, pursuant to the
purchase agreement of REPGB, as amended, REPGB was entitled to a NLG 125 million
dividend from NEA with any remainder owing to the former shareholders. As
mentioned above, REPGB entered into an agreement with its former shareholders to
settle the original indemnification agreement and the former shareholders waived
all rights to distributions of NEA. Accordingly, as a component of the net gain
recognized from the settlement of the stranded cost indemnity, the Company
recorded a $248 million increase in its investment in NEA. As of December 31,
2001, the Company has recorded $299 million in equity investments of
unconsolidated subsidiaries for its investment in NEA.
(g) PAYMENT TO RELIANT ENERGY IN 2004.
To the extent the Company's price to beat mandated by the Texas electric
restructuring law for providing retail electric service to residential and small
commercial customers in Reliant Energy's Houston service territory during 2002
and 2003 exceeds the market price of electricity, the Company may be required to
make a payment to Reliant Energy in early 2004. This payment will be required
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 Reliant
Energy's Houston service territory is committed to be served by retail electric
providers other than the Company. If the 40% test is not met and a payment is
required, the amount of this payment will be equal to (a) the amount that the
price to beat, less non-bypassable delivery charges, is in excess of the
prevailing market price of electricity during such period per customer, but not
to exceed $150 per customer, multiplied by (b) the number of residential or
small commercial customers, as the case may be, that the Company serves on
January 1, 2004 in Reliant Energy's Houston service territory, less the number
of new retail electric customers the Company serves in other areas of Texas. As
of December 31, 2001, Reliant Energy had approximately 1.5 million residential
and small commercial customers. In the master separation agreement between the
Company and Reliant Energy, the Company has agreed to make this payment, if any,
to Reliant Energy.
(h) CONSTRUCTION AGENCY AGREEMENTS AND EQUIPMENT FINANCING STRUCTURE.
In 2001, the Company, through several of its subsidiaries, entered into
operative documents with special purpose entities to facilitate the development,
construction, financing and leasing of several power generation projects. The
special purpose entities are not consolidated by the Company. The special
purpose entities have an aggregate financing commitment from equity and debt
participants (Investors) of $2.5 billion of which the last $1.1 billion is
currently available only if cash collaterized. The availability of the
commitment is subject to satisfaction of various conditions, including the
obligation to provide cash collateral for the loans and letters of credit
outstanding on November 27, 2004. The Company, through several of its
subsidiaries, acts as construction agent for the special purpose entities and is
responsible for completing construction of these projects by December 31, 2004,
but the Company has generally limited its risk during construction to an amount
not in excess of 89.9% of costs incurred to date, except in certain events. Upon
completion of an individual project and exercise of the lease option, the
Company's subsidiaries will be required to make lease payments in an amount
sufficient to provide a return to the Investors. If the Company does not
exercise its option to lease any project upon its completion, the Company must
purchase the project or remarket the project on behalf of the special purpose
entities. The Company's ability to exercise the lease option is subject to
certain conditions.
F-47
The Company must guarantee that the Investors will receive an amount at least
equal to 89.9% of their investment in the case of a remarketing sale at the end
of construction. At the end of an individual project's initial operating lease
term (approximately five years from construction completion), the Company's
subsidiary lessees have the option to extend the lease with the approval of
Investors, purchase the project at a fixed amount equal to the original
construction cost, or act as a remarketing agent and sell the project to an
independent third party. If the lessees elect the remarketing option, they may
be required to make a payment of an amount not to exceed 85% of the project
cost, if the proceeds from remarketing are not sufficient to repay the
Investors. The Company has guaranteed the performance and payment of its
subsidiaries' obligations during the construction periods and, if the lease
option is exercised, each lessee's obligations during the lease period. At any
time during the construction period or during the lease, the Company may
purchase a facility by paying an amount approximately equal to the outstanding
balance plus costs.
The Company, through its subsidiary, REPG, has entered into an agreement
with a bank whereby the bank, as owner, entered or will enter into contracts for
the purchase and construction of power generation equipment and REPG, or its
subagent, acts as the bank's agent in connection with administering the
contracts for such equipment. Under the agreement, the bank has agreed to
provide up to a maximum aggregate amount of $650 million. REPG and its subagents
must cash collateralize their obligation to administer the contracts. This cash
collateral is approximately equivalent to the total payments by the bank for the
equipment, interest and other fees. As of December 31, 2001, the bank had
assumed contracts for the purchase of eleven turbines, two heat recovery steam
generators and one air cooled condenser with an aggregate cost of $398 million.
REPG, or its designee, has the option at any time to purchase, or, at equipment
completion, subject to certain conditions, including the agreement of the bank
to extend financing, to lease the equipment, or to assist in the remarketing of
the equipment under terms specified in the agreement. All costs, including the
purchase commitment on the turbines, are the responsibility of the bank. The
cash collateral is deposited by REPG or an affiliate into a collateral account
with the bank and earns interest at LIBOR less 0.15%. Under certain
circumstances, the collateral deposit or a portion of it, will be returned to
REPG or its designee. Otherwise, it will be retained by the bank. At December
31, 2001, REPG and its subsidiary had deposited $230 million into the collateral
account. The bank's payments for equipment under the contracts totaled $227
million as of December 31, 2001. In January 2002, the bank sold to the parties
to the construction agency agreements discussed above, equipment contracts with
a total contractual obligation of $258 million, under which payments and
interest during construction totaled $142 million. Accordingly, $142 million of
the Company's collateral deposits were returned to the Company. As of December
31, 2001, there were equipment contracts with a total contractual obligation of
$140 million under which payments during construction totaled $83 million.
Currently this equipment is not designated for current planned power generation
construction projects. Therefore, the Company anticipates that it will either
purchase the equipment, assist in the remarketing of the equipment or negotiate
to cancel the related contracts.
(i) CALIFORNIA WHOLESALE MARKET UNCERTAINTY.
Receivables. During portions of 2000 and 2001, 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,
decreased net electric imports and limitations on supply as a result of
maintenance and other outages. The resulting supply and demand imbalance
disproportionately impacted California utilities that relied too heavily on
short-term power markets to meet their load requirements. Although wholesale
prices increased, California's deregulation legislation kept retail rates frozen
at 10% below 1996 levels for two of California's public utilities, Pacific Gas
and Electric (PG&E) and Southern California Edison Company (SCE), until rates
were raised by the California Public Utilities Commission (CPUC) early in 2001.
Due to the disparity between wholesale and retail rates, the credit
ratings of PG&E and SCE fell below investment grade. Additionally, PG&E filed
for protection under the bankruptcy laws on April 6, 2001. As a result, PG&E and
SCE are no longer considered creditworthy and since January 17, 2001 have not
directly purchased power from third-party suppliers through the Cal ISO to serve
their net short load. Pursuant to emergency legislation enacted by the
California Legislature, the California Department of Water Resources (CDWR) has
negotiated and purchased power through short- and long-term contracts on behalf
of PG&E and SCE to meet their net short loads. In December 2001, the CDWR began
making payments to the Cal ISO for real-time transactions. The CDWR has now made
payment through the Cal ISO for most real-time energy deliveries subsequent to
January 17, 2001.
In addition, certain contracts intended to serve as collateral for sales
to the California Power Exchange (Cal PX) were seized by California Governor
Gray Davis in February 2001. The Ninth Circuit Court of Appeals subsequently
F-48
ruled that Governor Davis' seizure of these contracts was wrongful. The Company
has filed a lawsuit, currently pending in California, to require the state of
California to compensate it for the seizure of these contracts. Although SCE
made a payment on March 1, 2002 to the Cal PX that included amounts it owed to
the Company under these contracts, the Company is still seeking to recover the
market value of the contracts at the time they were seized by Governor Davis,
which was significantly higher than the contract value, and to collect amounts
owed as a result of payment defaults by PG&E under the contracts. The timing and
ultimate resolution of these claims is uncertain at this time.
On September 20, 2001, PG&E filed a Plan of Reorganization and an
accompanying disclosure statement with the bankruptcy court. Under this plan,
PG&E would pay all allowed creditor claims in full, through a combination of
cash and long-term notes. Components of the plan will require the approval of
the FERC, the SEC and the Nuclear Energy Regulatory Commission, in addition to
the bankruptcy court. PG&E has stated it seeks to have this plan confirmed by
December 31, 2002. A number of parties are contesting PG&E's reorganization
plan, including a number of California parties and agencies. The bankruptcy
judge in the PG&E case has ordered that the CPUC may file a competing plan. The
details of the CPUC's proposal are unknown at this time. The ability of PG&E to
have its reorganization plan confirmed, including the provision providing for
the payment in full of unsecured creditors, is uncertain at this time.
On October 5, 2001, a federal district court in California entered a
stipulated judgment approving a settlement between SCE and the CPUC in an action
brought by SCE regarding the recovery of its wholesale power costs under the
filed rate doctrine. Under the stipulated judgment, a rate increase approved
earlier in 2001 will remain in place until the earlier of SCE recovering $3.3
billion or December 31, 2002. After that date, the CPUC will review the
sufficiency of retail rates through December 31, 2005. A consumer organization
has appealed the judgment to the Ninth Circuit Court of Appeals, and no hearing
has been held to date. Under the stipulated judgment, any settlement with SCE's
creditors that is entered into after March 1, 2002 must be approved by the CPUC.
The Company has appealed this provision of the judgment. On March 1, 2002, SCE
made a payment to the Cal PX that included amounts it owed the Company. The
Company has made a filing with FERC seeking an order providing for the
disbursement of the funds owed to the suppliers. The FERC and the bankruptcy
court governing the Cal PX bankruptcy proceedings are considering how to
dispense this money and it remains uncertain when those funds will be paid over
to the Company.
As of December 31, 2000, the Company was owed a total of $282 million by
the Cal PX and the Cal ISO. As of December 31, 2001, the Company was owed a
total of $302 million by the Cal ISO, the Cal PX, the CDWR, and California
Energy Resources Scheduling for energy sales in the California wholesale market
during the fourth quarter of 2000 through December 31, 2001. From January 1,
2002 through March 26, 2002, the Company has collected $45 million of these
receivable balances. As of December 31, 2001, the Company had a pre-tax
provision of $68 million against receivable balances related to energy sales in
the California market, including $39 million recorded in 2000 and $29 million
recorded in 2001. Management will continue to assess the collectability of these
receivables based on further developments affecting the California electricity
market and the market participants described herein.
FERC Market Mitigation. In response to the filing of a number of
complaints challenging the level of wholesale prices, the FERC initiated a staff
investigation and issued a number of orders implementing a series of wholesale
market reforms. Under these orders, and subject to review and adjustment based
on the pending refund proceeding described below, the Company may face an as yet
undetermined amount of refund liability. See "-- FERC Refunds" below. Under
these orders, for the period January 1, 2001 through June 19, 2001,
approximately $20 million of the $149 million charged by the Company for sales
in California to the Cal ISO and the Cal PX were identified as being subject to
possible refunds. During the second quarter of 2001, the Company accrued refunds
of $15 million, $3 million of which had been previously expensed during the
first quarter of 2001.
On April 26, 2001, the FERC issued an order replacing previous price
review procedures and establishing a market monitoring and mitigation plan,
effective May 29, 2001, for the California markets. The plan establishes a cap
on prices during periods when power reserves fall below 7% in the Cal ISO
(reserve deficiency periods). The Cal ISO is instructed to use data submitted
confidentially by gas-fired generators in California and daily indices of
natural gas and emissions allowance costs to establish the market-clearing price
in real-time based on the marginal cost of the highest-cost generator called to
run. The plan also requires generators in California to offer all their
available capacity for sale in the real-time market, and conditions sellers'
market-based rate authority such that sellers engaging in certain bidding
practices will be subject to increased scrutiny by the FERC, potential refunds
and even revocation of their market-based rate authority.
F-49
On June 19, 2001, the FERC issued an order modifying the market monitoring
and mitigation plan adopted in its April 26 order, to apply price controls to
all hours, instead of just hours of low operating reserve, and to extend the
mitigation measures to other Western states in addition to California, including
Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington
and Wyoming. The FERC set July 2, 2001 as the refund effective date for sales
subject to the price mitigation plan throughout the West region. This means that
transactions after that date may be subject to refund if found to be unjust or
unreasonable. The proxy market clearing price calculated by the Cal ISO will
apply during periods of reserve deficiency to all sales in the Cal ISO and
Western spot markets. In non-reserve deficiency hours in California, the maximum
price in California and the other Western states will be capped at 85% of the
highest Cal ISO hourly market clearing price established during the most recent
reserve deficiency period. Sellers other than marketers will be allowed to bid
higher than the maximum prices, but such bids are subject to justification and
potential refund. Justification of higher prices is limited to establishing
higher actual gas costs than the proxy calculation averages and making a showing
that conditions in natural gas markets changed significantly. The modified
monitoring and mitigation plan went into effect June 20, 2001, and will
terminate on September 30, 2002, covering two summer peak seasons, or
approximately 16 months.
On December 19, 2001, the FERC issued a series of orders on price
mitigation in California and the West region. These orders largely maintained
existing mitigation mechanisms, but did make a temporary modification to the way
that mitigated market clearing prices will be set during the winter months,
allowing the maximum prices to rise if gas prices rise. The FERC removed the
requirement that non-reserve deficiency prices be limited to 85% of the most
recent reserve deficiency prices, allowing prices to rise to a mitigated
clearing price of $108/MWh (above which price transactions must be justified as
described above). In addition, the FERC determined that if gas prices in
California rise by 10%, the mitigated price may be revised to take that change
into account. The formula will then track subsequent cumulative changes of at
least 10%, but may not fall below a maximum price of $108/MWh. This modification
is effective December 20, 2001 through April 30, 2002, at which point the
previous mitigation formula is reinstated.
Also, the December 19 orders affirm the June 19 order's requirement that
generators must offer all available capacity for sale in the real-time market.
As a result of this requirement, the Company's opportunity to sell ancillary
services in the West region in the future may be reduced. During 2001, the
Company recorded $42 million in revenues related to ancillary services in the
West region.
In addition to the impact on ancillary services sales, certain aspects of
the December 19, 2001 orders may have retroactive application that may affect
prices charged in the West region since June 21, 2001. Because the precise
application of the December 19, 2001 order is not known at this time, the
Company cannot anticipate the resulting impact on earnings.
The Company believes that while the mitigation plan will reduce volatility
in the market, the Company will nevertheless be able to profitably operate its
facilities in the West. Additionally, as noted above, the mitigation plan allows
sellers, such as the Company, to justify prices above the proxy price. However,
previous efforts by the Company to justify prices above the proxy price have
been rejected by the FERC and there is no certainty that the FERC will allow for
the recovery of costs above the proxy price. Finally, any adverse impacts of the
mitigation plan on the Company's operations would be mitigated, in part, by the
Company's forward hedging activities.
FERC Refunds. The FERC issued an order on July 25, 2001 adopting a refund
methodology and initiating a hearing schedule to determine (1) revised mitigated
prices for each hour from October 2, 2000 through June 20, 2001; (2) the amount
owed in refunds by each supplier according to the methodology (these amounts may
be in addition to or in place of the refund amounts previously determined by the
FERC); and (3) the amount currently owed to each supplier. The amounts of any
refunds will be determined by the FERC after the conclusion of the hearing
process. On December 19, 2001, the FERC issued an order modifying the
methodology to be used to determine refund amounts. The schedule currently
anticipates that the Administrative Law Judge will make his refund amount
recommendations to the FERC in October 2002. However, the Company does not know
when the FERC will issue its final decision. The Company has not reserved any
amounts for potential future refund liability resulting from the FERC refund
hearing, nor can it currently predict the amount of these potential refunds, if
any, because the methodology used to calculate these refunds is not final and
will depend on information that is still
F-50
subject to review and challenge in the hearing process. Any refunds that are
determined in the FERC proceeding will likely be offset against unpaid amounts
owed, if any, to the Company for its prior sales.
On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including the Company. In this proceeding, the
FERC conditions the market-based rate authority of all sellers on their not
engaging in anti-competitive behavior. Such condition will apply upon a further
order from FERC establishing a refund effective date. This condition allows the
FERC, if it determines that a seller has engaged in anti-competitive behavior
subsequent to the start of the refund effective period, to order refunds back to
the date of such behavior. The FERC invited comments regarding this proposal,
and the Company has filed comments in opposition to the proposal. On March 11,
2002, the FERC's Staff held a conference with market participants to discuss the
comments FERC has received, and possible modification of the proposed conditions
to address concerns raised in the comments while protecting consumers against
anticompetitive behavior. The timing of further action by FERC is uncertain. If
the FERC does not modify or reject its proposed approach for dealing with
anti-competitive behavior, the Company's future earnings may be affected by the
open-ended refund obligation.
On February 13, 2002, the FERC issued an order initiating a staff
investigation into potential manipulation of electric and natural gas prices in
the West region for the period January 1, 2000 forward. While this order does
not propose any action against the Company, if the investigation results in
findings that markets were dysfunctional during this period, those findings may
be used in support of existing or future claims by the FERC or others that
prices in the Company's long-term contracts entered into after January 1, 2000
for sales in the West region should be altered.
Other Investigations. 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
State Senate and the California Office of the Attorney General have separate
ongoing investigations into the high prices and their causes. Although these
investigations have not been completed and no findings have been made in
connection with either of them, the California Attorney General has filed a
civil lawsuit in San Francisco Superior Court alleging that the Company has
violated state laws against unfair and unlawful business practices and a
complaint with the FERC alleging the Company violated the terms of its tariff
with the FERC (see Note 13(e)). Adverse findings or rulings could result in
punitive legislation, sanctions, fines or even criminal charges against the
Company or its employees. The Company is cooperating with both investigations
and has produced a substantial amount of information requested in subpoenas
issued by each body. The Washington and Oregon attorneys general have also begun
similar investigations.
Legislative Efforts. Since the inception of the California energy crisis,
various pieces of legislation, including tax proposals, have been introduced in
the U.S. Congress and the California Legislature addressing several issues
related to the increase in wholesale power prices in 2000 and 2001. For example,
a bill was introduced in the California legislature that would have created a
"windfall profits" tax on wholesale electricity sales and would subject exempt
wholesale generators, such as the Company's subsidiaries that own generation
facilities in California, to regulation by the CPUC as "public utilities." To
date, only a few energy-related bills have passed and the Company does not
believe that the legislation that has been enacted to date on these issues will
have a material adverse effect on the Company. However, it is possible that
legislation could be enacted on either the state or federal level that could
have a material adverse effect on the Company's financial condition, results of
operations and cash flows.
(14) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
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 and long-term borrowings are estimated to be
approximately equivalent to carrying amounts and have been excluded from the
table below. The fair value of financial instruments included in the trading
operations are marked-to-market at December 31, 2000 and 2001 (see Note 6). The
fair values of non-trading derivative assets and liabilities are recognized in
the Consolidated Balance Sheet at December 31, 2001 (see Note 6). Therefore,
these financial instruments are stated at fair value and are excluded from the
table below. The fair values of non-trading derivative assets and liabilities as
of December 31,
F-51
2000 have been determined using quoted market prices for the same or similar
instruments when available or other estimation techniques.
DECEMBER 31, 2000
------------------------
CARRYING FAIR
AMOUNT VALUE
-------- -----
(IN MILLIONS)
Financial assets:
Energy derivatives -- non-trading ......... $ -- $427
Financial liabilities:
Energy derivatives -- non-trading ......... -- 35
Foreign currency swaps .................... 62 68
(15) UNAUDITED QUARTERLY INFORMATION
Summarized quarterly financial data is as follows:
YEAR ENDED DECEMBER 31, 2000
--------------------------------------------------------------------
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
------------- -------------- ------------- --------------
(IN MILLIONS)
Revenues ..................................... $ 2,321 $3,613 $6,886 $ 6,972
Operating income (loss) ...................... 2 173 301 (38)
(Loss) income before extraordinary item ...... (23) 104 164 (42)
Net (loss) income ............................ (23) 111 164 (42)
YEAR ENDED DECEMBER 31, 2001
--------------------------------------------------------------------
FIRST QUARTER SECOND QUARTER THIRD QUARTER FOURTH QUARTER
------------- -------------- ------------- --------------
(IN MILLIONS)
Revenues ..................................................... $ 9,871 $ 9,698 $ 10,348 $ 6,629
Operating income ............................................. 114 294 352 2
Income before cumulative effect of accounting change ......... 79 228 214 33
Net income ................................................... 82 228 214 33
BASIC EARNINGS PER SHARE:
Income before cumulative effect of accounting change ...... $ 0.33 $ 0.83 $ 0.71 $ 0.11
Cumulative effect of accounting change, net of tax ........ 0.01 -- -- --
---------- ---------- ---------- ----------
Net income .............................................. $ 0.34 $ 0.83 $ 0.71 $ 0.11
========== ========== ========== ==========
DILUTED EARNINGS PER SHARE:
Income before cumulative effect of accounting change ...... $ 0.33 $ 0.82 $ 0.71 $ 0.11
Cumulative effect of accounting change, net of tax ........ 0.01 -- -- --
---------- ---------- ---------- ----------
Net income .............................................. $ 0.34 $ 0.82 $ 0.71 $ 0.11
========== ========== ========== ==========
The quarterly operating results incorporate the results of operations of
REMA from its May 2000 acquisition date as discussed in Note 5(a). The variances
in revenues from quarter to quarter were primarily due to the REMA acquisition,
the seasonal fluctuations in demand for energy and energy services and changes
in energy commodity prices. Changes in operating income (loss) and net (loss)
income from quarter to quarter were primarily due to the acquisition, the
seasonal fluctuations in demand for energy and energy services, changes in
energy commodity prices and the timing of maintenance expenses on electric
generation plant and provisions related to energy sales in California and Enron.
In addition, in the first quarter of 2001, the Company recognized a $100 million
pre-tax, non-cash charge relating to the redesign of some of Reliant Energy's
benefit plans in anticipation of the Company's separation from Reliant Energy
(see Note 11).
F-52
(16) RELIANT ENERGY COMMUNICATIONS
During the third quarter of 2001, management decided to exit the Company's
Communications business which served as a facility-based competitive local
exchange carrier and Internet services provider and owned network operations
centers and managed data centers in Houston and Austin. Consequently, the
Company determined the goodwill associated with the Communications business was
impaired. The Company recorded a total of $54 million of pre-tax disposal
charges in the third and fourth quarters of 2001. These charges included the
write-off of goodwill of $19 million, fixed asset impairments of $22 million,
and severance accruals and other incremental costs associated with exiting the
Communications business, totaling $13 million.
(17) BANKRUPTCY OF ENRON CORP AND ITS AFFILIATES
During the fourth quarter of 2001, Enron filed a voluntary petition for
bankruptcy. Accordingly, the Company recorded an $85 million provision,
comprised of provisions against 100% of receivables of $88 million and net
non-trading derivative balances of $52 million, offset by the Company's net
trading and marketing liabilities to Enron of $55 million.
The non-trading derivatives with Enron were designated as Cash Flow Hedges
(see Note 6). The net gain on these derivative instruments previously reported
in other comprehensive income will remain in accumulated other comprehensive
loss and will be reclassified into earnings during the period in which the
originally designated hedged transactions occur.
(18) REPORTABLE SEGMENTS
The Company has identified the following reportable segments: Wholesale
Energy, European Energy, Retail Energy and Other Operations. For descriptions of
the financial reporting segments, see Note 1. 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. Financial information
for REMA, REPGB and Indian River are included in the segment disclosures only
for periods beginning on their respective acquisition dates. The Company
evaluates performance based on operating income. The Company accounts for
intersegment revenue as if the sales were to third parties, that is, at current
market prices.
Long-lived assets include net property, plant and equipment, net goodwill,
net air emissions regulatory allowances and other intangibles and equity
investments in unconsolidated subsidiaries.
F-53
Financial data for business segments, products and services and geographic
areas are as follows:
WHOLESALE EUROPEAN RETAIL OTHER
ENERGY ENERGY ENERGY OPERATIONS ELIMINATIONS CONSOLIDATED
--------- -------- ------ ---------- ------------ ------------
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 1999:
Revenues from external customers ................... 7,866 56 34 -- -- 7,956
Depreciation and amortization ...................... 21 6 -- 2 -- 29
Operating income (loss) ............................ 19 12 (13) (4) -- 14
Total assets ....................................... 2,710 2,782 70 62 -- 5,624
(Loss) income of equity investment of
unconsolidated subsidiaries ...................... (1) 22 -- -- -- 21
Equity investments in unconsolidated
subsidiaries ..................................... 78 -- -- -- -- 78
Expenditures for long-lived assets ................. 501 839 55 -- -- 1,395
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2000:
Revenues from external customers ................... 19,142 580 64 6 -- 19,792
Depreciation and amortization ...................... 108 76 4 6 -- 194
Operating income (loss) ............................ 485 84 (70) (61) -- 438
Total assets ....................................... 10,505 2,473 131 105 -- 13,214
Income of equity investments of unconsolidated
subsidiaries ..................................... 43 -- -- -- -- 43
Equity investments in unconsolidated
subsidiaries ..................................... 109 -- -- -- -- 109
Expenditures for long-lived assets ................. 1,966 995 22 59 -- 3,042
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2001:
Revenues from external customers ................... 35,137 1,192 206 11 -- 36,546
Intersegment revenues .............................. 21 -- 5 -- (26) --
Depreciation and amortization ...................... 118 76 11 42 -- 247
Operating income (loss) ............................ 899 56 (13) (180) -- 762
Total assets ....................................... 8,252 3,380 391 599 (368) 12,254
Income of equity investment of unconsolidated
subsidiaries ..................................... 6 51 -- -- -- 57
Equity investments in unconsolidated
subsidiaries ..................................... 88 299 -- -- -- 387
Expenditures for long-lived assets ................. 658 21 117 44 -- 840
F-54
AS OF AND FOR THE YEAR ENDED DECEMBER 31,
-----------------------------------------
1999 2000 2001
------- -------- --------
(IN MILLIONS)
RECONCILIATION OF OPERATING INCOME TO NET INCOME:
Operating income ................................... $ 14 $ 438 $ 762
Other income (expense) ............................. 12 (147) 64
Income tax expense ................................. (2) (88) (272)
Cumulative effect of accounting change ............. -- -- 3
Extraordinary item ................................. -- 7 --
------- -------- --------
Net income .................................... $ 24 $ 210 $ 557
======= ======== ========
REVENUES BY PRODUCTS AND SERVICES:
Wholesale energy and energy related sales .......... $ 7,922 $ 19,722 $ 36,350
Energy products and services ....................... 34 70 222
Eliminations ....................................... -- -- (26)
------- -------- --------
Total ......................................... $ 7,956 $ 19,792 $ 36,546
======= ======== ========
REVENUES AND LONG-LIVED ASSETS BY GEOGRAPHIC AREAS:
REVENUES:
United States .................................... $ 7,783 $ 18,163 $ 33,031
Netherlands ...................................... 56 580 1,192
Canada ........................................... 117 1,049 2,323
------- -------- --------
Total ......................................... $ 7,956 $ 19,792 $ 36,546
======= ======== ========
LONG-LIVED ASSETS:
United States .................................... $ 1,065 $ 3,078 $ 3,728
Netherlands ...................................... 2,572 2,371 2,424
------- -------- --------
Total ......................................... $ 3,637 $ 5,449 $ 6,152
======= ======== ========
(19) SUBSEQUENT EVENTS
In February 2002, the Company acquired all of the outstanding shares of
Orion Power for $26.80 per share in cash for an aggregate purchase price of $2.9
billion. The Company funded the Orion Power acquisition with a $2.9 billion
credit facility (see Note 8(a)) and $41 million of cash on hand. As a result of
the acquisition, the Company's consolidated net debt obligations also, increased
by the amount of Orion Power's net debt obligations. As of February 19, 2002,
Orion Power's debt obligations were $2.4 billion ($2.1 billion net of cash
acquired, some of which is restricted pursuant to debt covenants). Orion Power
is an independent electric power generating company formed in March 1998 to
acquire, develop, own and operate power-generating facilities in certain
deregulated wholesale markets throughout North America. As of February 28, 2002,
Orion Power had 81 power plants in operation with a total generating capacity of
5,644 MW and an additional 804 MW in construction or in various stages of
development.
* * *
F-55
RELIANT RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2001
(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
DESCRIPTION OF PERIOD INCOME ACCOUNT(1) RESERVES(2) OF PERIOD
----------- ---------- ------- ---------- ----------- ----------
For the Year Ended December 31, 2001:
Accumulated provisions:
Uncollectible accounts receivable ....................... $51,466 $ 38,274 $ 1,455 $ 1,487 $89,708
Reserves deducted from trading and marketing assets ..... 66,132 31,717 -- -- 97,849
Reserves for accrue-in-advance major maintenance ........ 27,075 2,383 (663) 9,419 19,376
Reserve for inventory ................................... 6,828 51 (6,424) -- 455
Reserves for severance .................................. 32,500 5,003 (1,802) 16,050 19,651
Deferred tax assets valuation ........................... 20,260 (4,628) -- -- 15,632
For the Year Ended December 31, 2000:
Accumulated provisions:
Uncollectible accounts receivable ....................... 7,803 43,100 -- (563) 51,466
Reserves deducted from trading and marketing assets ..... 11,511 54,621 -- -- 66,132
Reserves for accrue-in-advance major maintenance ........ 47,809 41,306 (787) 61,253 27,075
Reserve for inventory ................................... 5,716 -- 17,053 15,941 6,828
Reserves for severance .................................. 17,760 -- 20,065 5,325 32,500
Deferred tax assets valuation ........................... 3,028 17,232 -- -- 20,260
For the Year Ended December 31, 1999:
Accumulated provisions:
Uncollectible accounts receivable ....................... 6,703 1,100 -- -- 7,803
Reserves deducted from trading and marketing assets ..... 6,464 5,047 -- -- 11,511
Reserves for accrue-in-advance major maintenance ........ 35,249 5,826 17,411 10,677 47,809
Reserve for inventory ................................... 6,505 -- -- 789 5,716
Reserves for severance .................................. -- -- 18,080 320 17,760
Deferred tax assets valuation ........................... 1,404 1,624 -- -- 3,028
- ----------
(1) Charged to other account represents obligations acquired through business
acquisitions.
(2) Deductions from reserves represent losses or expenses for which the
respective reserves were created. In the case of the uncollectible
accounts reserve, such deductions are net of recoveries of amounts
previously written off.
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.
None.
PART III
III-1
ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.
The information called for by Item 10, to the extent not set forth in
"Executive Officers" in Item 1, will be set forth in the definitive proxy
statement relating to Reliant Resources' 2002 annual meeting of stockholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a
meeting of stockholders 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.
ITEM 11. EXECUTIVE COMPENSATION.
The information called for by Item 11 will be set forth in the definitive
proxy statement relating to Reliant Resources' 2002 annual meeting of
stockholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of stockholders 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.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT.
The information called for by Item 12 will be set forth in the definitive
proxy statement relating to Reliant Resources' 2002 annual meeting of
stockholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of stockholders 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.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.
Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Related-Party Transactions" in Item 7 of this Form
10-K and Notes 3 and 4 to our consolidated financial statements for a discussion
of related party transactions. Additional information called for by Item 13 will
be set forth in the definitive proxy statement relating to Reliant Resources'
2002 annual meeting of stockholders pursuant to SEC Regulation 14A. Such
definitive proxy statement relates to a meeting of stockholders 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.
III-2
PART IV
ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.
(a)(1) Financial Statements.
Independent Auditors' Report.......................................... F-2
Statements of Consolidated Income for the Years Ended
December 31, 1999, 2000 and 2001................................... F-3
Consolidated Balance Sheets as of December 31, 2001 and 2000.......... F-4
Statements of Consolidated Cash Flows for the Years Ended
December 31, 1999, 2000 and 2001................................... F-5
Statements of Consolidated Stockholders' Equity and Comprehensive
Income for the Years Ended December 31, 1999, 2000 and 2001........ F-6
Notes to Consolidated Financial Statements............................ F-7
(a)(2) Financial Statement Schedules for the Years Ended December 31,1999,
2000 and 2001.
Schedule II -- Reserves............................................... III-1
The following schedules are omitted 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 (page IV-3), which index 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.
On November 28, 2001, we filed a Current Report on Form 8-K dated
September 26, 2001 filing pro forma financial statements for the
acquisition of Orion Power Holdings, Inc..
On January 11, 2002, we filed a Current Report on Form 8-K dated December
18, 2001 relating to the execution of a settlement agreement regarding
European stranded cost indemnification.
On February 5, 2002, we filed a Current Report on Form 8-K dated February
5, 2002 regarding a delay in the release of earnings and restatement of
2001 results.
On March 6, 2002, we filed a Current Report on Form 8-K dated February 19,
2002 regarding our acquisition of Orion Power Holdings, Inc.
On March 15, 2002, we filed a Current Report on Form 8-K dated March 15,
2002 regarding our 2001 earnings and the effects of our restatement.
On March 28, 2002, we filed an Amended Current Report on Form 8-K/A,
amending our Current Report on Form 8-K dated September 26, 2001 filing
pro forma financial statements for the acquisition of Orion Power
Holdings, Inc.
On April 8, 2002, we filed a Current Report on Form 8-K dated April 5,
2002 regarding an SEC informal inquiry.
On April 9, 2002, we filed an Amended Current Report on Form 8-K/A,
amending our Current Report on Form 8-K dated February 19, 2002 regarding
our acquisition of Orion Power Holdings, Inc.
IV-1
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 12th day of April, 2002.
RELIANT RESOURCES, INC.
(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 April 12th, 2002.
SIGNATURE TITLE
--------- -----
/s/ R. Steve Letbetter Chairman, President, Chief Executive Officer and Director
- --------------------------------------- (Principal Executive Officer)
(R. Steve Letbetter)
/s/ Stephen W. Naeve Executive Vice President 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/ Milton Carroll Director
- ---------------------------------------
(Milton Carroll)
/s/ L. Lowry Mays Director
- ---------------------------------------
(L. Lowry Mays)
/s/ Philip B. Miller Director
- ---------------------------------------
(Philip B. Miller)
IV-2
RELIANT RESOURCES, INC.
EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2001
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.
SEC FILE OR
EXHIBIT REPORT OR REGISTRATION REGISTRATION EXHIBIT
NUMBER DOCUMENT DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- -------------------- ---------------------- ------------ ---------
2.1 - Agreement Plan of Merger dated as of September 26, Reliant Resources, Inc. Current 1-16455 2.1
2001 by and Among Orion Power Holdings, Inc., Report on Form 8-K dated September
Reliant Resources, Inc. and Reliant Energy Power 27, 2002
Generation Merger Sub, Inc.
3.1 - Restated Certificate of Incorporation. Reliant Resources, Inc. 333-48038 3.1
Registration Statement on Form S-1
3.2 - Amended and Restated Bylaws. Reliant Resources, Inc. Quarterly 1-16455 3
Report on Form 10-Q for the
Quarterly Period Ended March 31,
2001
4.2 - Rights Agreement effective as of January 15, 2001 Reliant Energy, Incorporated's 1-3187 4.2
Manhattan Bank, as between Reliant Resources, Inc. Quarterly Report on Form 10-Q for
and The Chase Rights Agent, including a form of the Quarterly Period Ended March
Rights Certificate. 31, 2001
10.1 - Master Separation Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.1
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001. the Quarterly Period Ended March
31, 2001
10.2 - Transition Services Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.2
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001. the Quarterly Period Ended March
31, 2001
10.3 - Technical Services Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.3
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001. the Quarterly Period Ended March
31, 2001
10.4 - Texas Genco Option Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.4
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001. the Quarterly Period Ended March
31, 2001
10.5 - Employee Matters Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.5
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001 the Quarterly Period Ended March
31, 2001
10.6 - Retail Agreement between Reliant Resources and Reliant Energy, Incorporated's 1-3187 10.6
Reliant Energy, dated December 31, 2001 Quarterly Report on Form 10-Q for
the Quarterly Period Ended March
31, 2001
IV-3
SEC FILE OR
EXHIBIT REPORT OR REGISTRATION REGISTRATION EXHIBIT
NUMBER DOCUMENT DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- -------------------- ---------------------- ------------ ---------
10.7 - Registration Rights Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.7
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001 the Quarterly Period Ended March
31, 2001
10.8 - Tax Allocation Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.8
Resources and Reliant Energy, dated December 31, Quarterly Report on Form 10-Q for
2001 the Quarterly Period Ended March
31, 2001
*+10.9 - Reliant Resources, Inc. Annual Incentive
Compensation Plan effective January 1, 2001
*+10.10 - Reliant Resources, Inc. 2001 Long-Term Incentive
Plan effective January 1, 2001
*10.11 - Reliant Energy, Incorporated's Executive Benefits Reliant Resources, Inc. 333-48038 10.11
Plan effective June 1, 1982, including the first, Registration Statement on Form S-1
second and third amendments thereto (Reliant
Resources has adopted certain obligations under
this plan with respect to some of its officers).
*10.12 - Reliant Energy, Incorporated's Benefit Restoration Reliant Resources, Inc. 333-48038 10.12
Plan, as amended and restated effective July 1, Registration Statement on Form S-1
1991, including the first amendment thereto
(Reliant Resources has adopted certain obligations
under this plan with respect to some of its
employees).
10.13 - Share Subscription Agreement dated March 29, 1999 Reliant Energy, Incorporated's 1-3187 10.2
among Reliant Energy Wholesale Holdings (Europe) Quarterly Report on Form 10-Q for
Inc., Provincie Noord Holland, Gemeente Amsterdam, the quarter ended March 31, 1999.
N.V., Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy Power
Generation, Inc. and UNA.
10.14 - Share Purchase Agreement dated March 29, 1999 among Reliant Energy, Incorporated's 1-3187 10.3
Reliant Energy Wholesale Holdings (Europe) Inc., Quarterly Report on Form 10-Q for
Provincie Noord Holland, Gemeente Amsterdam, N.V., the quarter ended March 31, 1999.
Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy Power
Generation, Inc. and UNA.
10.15 - Deed of Amendment dated September 2, 1999 among Reliant Energy, Incorporated's 1-3187 2(b)(3)
Reliant Energy Wholesale Holdings (Europe) Inc., Annual Report on Form 10-K for the
Provincie Noord Holland, Gemeente Amsterdam, N.V., year ended December 31, 1999.
Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy Power
Generation, Inc. and UNA.
10.16 - Purchase Agreement dated as of February 19, 2000 Reliant Energy, Incorporated's 1-3187 2(c)
among Reliant Energy Power Generation, Reliant Annual Report on Form 10-K for the
Energy Sithe Energies, Inc. and Sithe Northeast year ended December 31, 1999.
Generating Company, Inc.
10.17 - Facility Lease Agreement dated as of August 14, Registration Statement on Form S-4 333-51464 4.6a
2000 between Conemaugh Lessor Genco LLC and of REMA.
Reliant Energy Mid-Atlantic Power Holding, LLC
(REMA).
10.18 - Schedule identifying substantially identical Registration Statement on Form S-4 333-51464 4.6b
agreements to Facility Lease Agreement of REMA.
constituting Exhibit 10.17.
IV-4
SEC FILE OR
EXHIBIT REPORT OR REGISTRATION REGISTRATION EXHIBIT
NUMBER DOCUMENT DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- -------------------- ---------------------- ------------ ---------
10.19 - Series A Pass Through Trust Agreement dated as Registration Statement on Form S-4 333-51464 4.4a
of August 24, 2000 between Reliant Energy of REMA.
Mid-Atlantic Power Holding, LLC and Bankers
Trust Company, made with respect to the
formation of the Series A Pass Through Trust
and the issuance of Series A Pass Through
Certificates.
10.20 - Schedule identifying substantially identical Registration Statement on Form S-4 333-51464 4.4b
agreements to Pass Through Trust Agreement of REMA.
constituting Exhibit 10.19.
10.21 - Participation Agreement dated as of August 24, Registration Statement on Form S-4 333-51464 4.5a
2000 among Conemaugh Lessor Genco LLC, as Owner of REMA.
Lessor, Reliant Energy Mid-Atlantic Power
Holding, LLC, as Facility Lessee, Wilmington
Trust Company, as Lessor Manager, PSEGR
Conemaugh Generation, LLC, as Owner
Participant, Bankers Trust Company, as Lease
Indenture Trustee, and Bankers Trust Company,
as Pass Through Trustee.
10.22 - Schedule Identifying substantially identical Registration Statement on Form S-4 333-51464 4.5b
agreements to Participation Agreement of REMA.
constituting Exhibit 10.21.
10.23 - Lease Indenture of Trust, Mortgage and Registration Statement on Form S-4 333-51464 4.8a
Security Agreement dated as of August 24, of REMA.
2000 between Conemaugh Lessor Genco LLC and
Bankers Trust Company.
10.24 - Schedule identifying substantially identical Registration Statement on Form S-4 333-51464 4.8b
agreements to Lease Indenture of Trust of REMA.
constituting Exhibit 10.23.
*10.25 - Reliant Energy, Incorporated's Deferred Reliant Resources, Inc. 333-48038 10.25
Compensation Plan effective as of September 1, Registration Statement on Form S-1
1985, including the first nine amendments
thereto (Reliant Resources has adopted certain
obligations under this plan with respect to
some of its employees).
*10.26 - Reliant Energy, Incorporated's Deferred Reliant Resources, Inc. 333-48038 10.26
Compensation Plan, as amended and restated Registration Statement on Form S-1
effective January 1, 1989, including the first
nine amendments thereto (Reliant Resources has
adopted certain obligations under this plan
with respect to some of its employees).
*10.27 - Reliant Energy, Incorporated's Deferred Reliant Resources, Inc. 333-48038 10.27
Compensation Plan, as amended and restated Registration Statement on Form S-1
effective January 1, 1991, including the first
ten amendments thereto (Reliant Resources has
adopted certain obligations under this plan
with respect to some of its employees).
*10.28 - Reliant Energy, Incorporated's Savings Reliant Resources, Inc. 333-48038 10.28
Restoration Plan effective January 1, 1991, Registration Statement on Form S-1
including the first and second amendments
thereto (Reliant Resources has adopted certain
obligations under this plan with respect to
some of its employees).
*10.29 - Reliant Energy, Incorporated's Director Reliant Resources, Inc. 333-48038 10.29
Benefits Plan effective January 1, 1992, Registration Statement on Form S-1
including the first amendment thereto (Reliant
Resources has adopted certain obligations under
this plan with respect to members of its board
of directors).
IV-5
SEC FILE OR
EXHIBIT REPORT OR REGISTRATION REGISTRATION EXHIBIT
NUMBER DOCUMENT DESCRIPTION STATEMENT NUMBER REFERENCE
- ------- -------------------- ---------------------- ------------ ---------
*10.30 - Reliant Energy, Incorporated's Executive Life Reliant Resources, Inc. 333-48038 10.30
Insurance Plan effective January 1, 1994, Registration Statement on Form S-1
including the first and second amendments thereto
(Reliant Resources has adopted certain obligations
under this plan with respect to some of its
officers).
*10.31 - Employment and Supplemental Benefits Agreement Reliant Resources, Inc. 333-48038 10.31
dated September 4, 1984 between Reliant Energy, Registration Statement on Form S-1
Incorporated and Hugh Rice Kelly (Reliant Resources
has adopted Reliant Energy, Incorporated's
obligations under this agreement).
+10.32 - REPGB Stranded Cost Settlement Agreement
+*10.33 - Retention Agreement effective May 4, 2001 between
Reliant Resources, Inc. and R. Steve Letbetter
+*10.34 - Retention Agreement effective May 4, 2001 between
Reliant Resources, Inc. and Robert W. Harvey
+*10.35 - Retention Agreement effective May 4, 2001 between
Reliant Resources, Inc. and Stephen W. Naeve
+*10.36 - Retention Agreement effective May 4, 2001 between
Reliant Resources, Inc. and Joe Bob Perkins
+*10.37 - Reliant Resources, Inc. Transition Stock Plan,
effective May 4, 2001
+10.38 - Form of Amended and Restated
Construction Agency Agreement for a Facility
+10.39 - Form of Amended and Restated Guaranty regarding
Restated Construction Agency Agreement
+21.1 - Subsidiaries of Reliant Resources, Inc.
+23.1 - Consent of Deloitte & Touche LLP
IV-6