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UNITED STATES SECURITIES
AND EXCHANGE COMMISSION
Washington, D.C. 20549
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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, 2002
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
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Reliant Resources, Inc.
(Exact Name of Registrant as Specified in Its Charter)
Delaware 76-0655566
(State or Other
Jurisdiction of
Incorporation or (I.R.S. Employer
Organization) Identification No.)
1111 Louisiana Street
Houston, Texas 77002 (713) 497-3000
(Address and Zip Code of (Registrant's Telephone
Principal Executive Number, Including Area
Offices) Code)
Securities registered pursuant to Section 12(b) of the Act:
Name of each exchange on
Title of each class which registered
------------------- ----------------
Common Stock, par value New York Stock Exchange
$.001 per share, and
associated rights to
purchase Series A
Preferred Stock
Securities registered pursuant to Section 12(g) of the Act: None
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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. [_]
Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [_]
The aggregate market value of the voting stock held by non-affiliates of the
Registrant was $433,427,759 as of June 28, 2002 (computed by reference to the
closing sale price of the Registrant's common stock on the New York Stock
Exchange on that date), 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 June 28, 2002,
the Registrant had 289,663,717 shares of common stock outstanding, excluding
10,140,283 shares of common stock held by the Registrant as treasury stock.
Portions of the definitive proxy statement relating to the 2003 Annual
Meeting of Stockholders of the Registrant's, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2002, 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
Page
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Cautionary Statement Regarding Forward-Looking Information...... 1
Glossary of Terms............................................... 1
PART I
ITEM 1. Business................................................ 5
Our Business............................................ 5
General................................................ 5
Formation, IPO and Distribution........................ 5
Orion Power Acquisition................................ 5
Disposition of European Energy Operations.............. 6
Retail Energy........................................... 6
Residential and Small Commercial Services.............. 7
Large Commercial, Industrial and Institutional Services 8
Provider of Last Resort................................ 8
Retail Energy Supply................................... 8
ERCOT.................................................. 9
Competition............................................ 9
Wholesale Energy........................................ 10
Overview of Wholesale Energy Market.................... 10
Power Generation Operations............................ 10
Mid-Atlantic Region.................................... 12
New York Region........................................ 13
Midwest Region......................................... 14
Southeast Region....................................... 15
West Region............................................ 15
ERCOT Region........................................... 17
Long-term Purchase and Sale Agreements................. 17
Commercial Operations.................................. 17
Regulation............................................. 19
Competition............................................ 20
European Energy......................................... 21
European Power Generation and Supply................... 21
European Trading and Origination....................... 22
Regulation............................................. 22
Competition............................................ 22
Other Operations........................................ 22
Environmental Matters................................... 23
General................................................ 23
Air Quality Matters.................................... 23
Water Quality Matters.................................. 24
Liability for Preexisting Conditions and Remediations.. 25
Other European Environmental Matters................... 26
Employees.............................................. 27
Executive Officers...................................... 27
ITEM 2. Properties.............................................. 28
Character of Ownership................................. 28
Retail Energy.......................................... 28
Wholesale Energy....................................... 28
European Energy........................................ 28
Other Operations....................................... 28
ITEM 3. Legal Proceedings....................................... 28
ITEM 4. Submission of Matters to a Vote of Security Holders..... 28
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Page
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PART II
ITEM 5. Market for Our Common Equity and Related Stockholder Matters...................... 29
ITEM 6. Selected Financial Data........................................................... 30
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of
Operations...................................................................... 32
Overview.......................................................................... 32
Consolidated Results of Operations................................................ 34
2002 Compared to 2001............................................................ 34
2001 Compared to 2000............................................................ 36
EBIT by Business Segment.......................................................... 37
Retail Energy.................................................................... 38
Wholesale Energy................................................................. 42
European Energy.................................................................. 49
Other Operations.................................................................. 54
Trading and Marketing Operations.................................................. 55
Related-Party Transactions........................................................ 61
Agreements With CenterPoint...................................................... 61
Risk Factors...................................................................... 62
Risks Related to Our Retail Energy Operations.................................... 62
Risks Related to Our Wholesale Energy Operations................................. 66
Risks Related to Our European Energy Operations.................................. 71
Risks Related to Our Businesses Generally........................................ 72
Risks Related to Our Corporate and Financial Structure........................... 75
Risks Related to the Sale of Our European Energy Operations...................... 77
Liquidity and Capital Resources................................................... 78
Historical Cash Flows............................................................ 78
Consolidated Capital Requirements................................................ 82
Consolidated Future Uses and Sources of Cash and Certain Factors Impacting Future
Uses and Sources of Cash....................................................... 84
Off-Balance Sheet Transactions................................................... 90
New Accounting Pronouncements, Significant Accounting Policies and Critical
Accounting Estimates............................................................ 90
New Accounting Pronouncements.................................................... 90
Significant Accounting Policies.................................................. 90
Critical Accounting Estimates.................................................... 90
ITEM 7A. Quantitative and Qualitative Disclosures About Market Risk........................ 99
Market Risk...................................................................... 99
Trading Market Risk.............................................................. 100
Non-trading Market Risk.......................................................... 103
Risk Management Structure........................................................ 105
ITEM 8. Financial Statements and Supplementary Data....................................... F-1
ITEM 9. Changes in and Disagreements with Accountants on Accounting and Financial
Disclosure...................................................................... III-15
PART III
ITEM 10. Directors and Executive Officers.................................................. III-15
ITEM 11. Executive Compensation............................................................ III-15
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters............................................................. III-15
ITEM 13. Certain Relationships and Related Transactions.................................... III-15
ITEM 14. Controls and Procedures........................................................... III-15
Evaluation of Disclosure Controls and Procedures................................. III-15
Changes in Internal Controls..................................................... III-15
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K................... III-16
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Cautionary Statement Regarding Forward-Looking Information
This Form 10-K includes statements concerning expectations, assumptions,
beliefs, plans, projections, objectives, goals, strategies and future events or
performance that are intended as "forward-looking statements" within the
meaning of the Private Securities Litigation Reform Act of 1995. 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" and similar words.
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 and performance 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. For more
information regarding the risks and uncertainties that could cause our actual
results to differ materially from those expressed or implied in our
forward-looking statements, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Risk Factors" in Item 7 of this
Form 10-K.
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.
Glossary of Terms
In this Form 10-K, "Reliant Resources" refers to Reliant Resources, Inc.,
and "we," "us" and "our" refer to Reliant Resources, Inc. and its subsidiaries,
unless we specify or the context indicates otherwise. In addition, the
following terms are used in this Form 10-K:
Alliance RTO..... the proposed RTO for all or parts of Missouri, Illinois, Indiana,
Michigan, Ohio, Kentucky, West Virginia, Pennsylvania, Tennessee,
Virginia and North Carolina.
APB No. 25....... Accounting Principles Board Opinion No. 25, "Accounting for Stock
Issued to Employees."
Bcf.............. one billion cubic feet of natural gas.
Cal ISO.......... California Independent System Operator.
Cal PX........... California Power Exchange.
CDWR............. California Department of Water.
CenterPoint...... CenterPoint Energy, Inc., on and after August 31, 2002 and Reliant
Energy, Incorporated prior to August 31, 2002.
CenterPoint Plans CenterPoint Long-Term Incentive Compensation Plan and certain other
incentive compensation plans of CenterPoint.
CERCLA........... Comprehensive Environmental Response Corporation and Liability Act
of 1980.
CFTC............. Commodity Futures Trading Commission.
Channelview...... Reliant Energy Channelview L.P.
CPUC............. California Public Utility Commission.
Distribution..... the distribution of approximately 83% of our common stock owned by
CenterPoint to its stockholders on September 30, 2002.
EBIT............. earnings (loss) before interest expense, interest income and income
taxes.
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EBITDA......... earnings (loss) before interest expense, interest income, income taxes,
depreciation and amortization expense.
ECAR........... East Central Area Reliability Coordination Council.
ECAR Market.... the wholesale electric market operated by ECAR.
EFL............ Electricity Facts Label.
EITF........... Emerging Issues Task Force.
EITF No. 02-03. EITF No. 02-03, "Issues Related to Accounting for Contracts Involved
in Energy Trading and Risk Management Activities."
EITF No. 94-3.. EITF No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity."
EITF No. 98-10. EITF No. 98-10, "Accounting for Contracts Involved in Energy Trading
and Risk Management Activities."
Enron.......... Enron Corp. and its subsidiaries.
EPA............ Environmental Protection Agency.
ERCOT.......... Electric Reliability Council of Texas.
ERCOT ISO...... ERCOT Independent System Operator.
ERCOT Region... the electric market operated by ERCOT.
ESPP........... Reliant Resources Employee Stock Purchase Plan.
EURIBOR........ inter-bank offered rate for Euros.
FASB........... Financial Accounting Standards Board.
FERC........... Federal Energy Regulatory Commission.
FIN No. 45..... FASB Interpretation No. 45, "Guarantor's Accounting and Disclosure
Requirements for Guarantees, Including Direct Guarantees of
Indebtedness of Others."
FIN No. 46..... FASB Interpretation No. 46, "Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51."
FPSC........... Florida Public Service Commission.
GAAP........... United States generally accepted accounting principles.
GridFlorida RTO the FERC approved RTO for Florida.
GW............. gigawatt.
GWh............ gigawatt hour.
Headroom....... the difference between the price to beat and the sum of (a) the charges,
fees and transportation and distribution utility rates approved by the
PUCT and (b) the price paid for electricity to serve price to beat
customers.
IPO............ our initial public offering in May 2001.
ISO............ independent system operator.
KWh............ kilowatt hour.
LEP............ Liberty Electric Power, LLC.
Liberty........ Liberty Electric PA, LLC.
LIBOR.......... London inter-bank offered rated.
MAIN........... Mid-America Interconnected Network.
MAIN Market.... the wholesale electric market operated by MAIN.
MISO........... Midwest Independent Transmission System Operator.
MMbtu.......... one million British thermal units.
Mmcf........... million cubic feet.
MW............. megawatt.
MWh............ megawatt hour.
NEA............ NEA, B.V., formerly the coordinating body for the Dutch electric
generating sector.
NLG............ Dutch Guilders.
Nuon........... N.V. Nuon, a Netherlands-based electricity distributor.
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NYISO.......... New York Independent System Operator.
NY Market...... the wholesale electric market operated by NYISO.
Orion Capital.. Orion Power Capital, LLC.
Orion MidWest.. Orion Power MidWest, L.P.
Orion NY....... Orion Power New York, L.P. Orion MidWest
Orion Power.... Orion Power Holdings, Inc., one of our subsidiaries that we acquired in
February 2002.
OTC............ over-the-counter market.
PGET........... PG&E Energy Trading-Power, L.P.
PJM............ PJM Interconnection, LLC.
PJM Market..... the wholesale electric market operated by PJM regional transmission
organization in all or part of Delaware, the District of Columbia,
Maryland, New Jersey and Virginia.
PJM West Market the wholesale electric market operated by PJM in the Midwest.
Protocols...... structure, agreements, tariffs, rules, regulations, mechanisms and
requirements that govern rates, terms and conditions for electricity
services.
PUCT........... Public Utility Commission of Texas.
PUHCA.......... Public Utility Holding Company Act of 1935.
QSPE........... qualified special purpose entity.
REDB........... Reliant Energy Desert Basin, LLC, one of our subsidiaries.
Reliant Energy. Reliant Energy, Incorporated and its subsidiaries.
REMA........... Reliant Energy Mid-Atlantic Power Holdings, LLC, one of our
subsidiaries, and its subsidiaries.
REPG........... Reliant Energy Power Generation, Inc., one of our subsidiaries.
REPGB.......... Reliant Energy Power Generation Benelux, N.V., one of our
subsidiaries.
RERC Corp...... Reliant Energy Resources Corp.
RTO............ regional transmission organizations.
RTO West....... the FERC approved RTO for Idaho, Montana, Nevada, Oregon, Utah
and Washington.
SEC............ Securities and Exchange Commission.
SeTrans RTO.... the FERC approved RTO for all or parts of Georgia, Alabama,
Louisiana, Mississippi, Arkansas and eastern Texas.
SMD............ the standard market design for the wholesale electric market proposed
by the FERC.
SFAS........... Statement of Financial Accounting Standards.
SFAS No. 5..... SFAS No. 5, "Accounting for Contingencies."
SFAS No. 86.... SFAS No. 86, "Employers' Accounting for Pensions."
SFAS No. 106... SFAS No. 106, "Employers' Accounting for Postretirement Benefits
Other Than Pensions."
SFAS No. 115... SFAS No. 115, "Accounting for Certain Investments in Debt and
Equity Securities."
SFAS No. 123... SFAS No. 123, "Accounting for Stock Based Compensation."
SFAS No. 133... SFAS No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended.
SFAS No. 140... SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities."
SFAS No. 141... SFAS No. 141, "Business Combinations."
SFAS No. 142... SFAS No. 142, "Goodwill and Other Intangible Assets."
SFAS No. 143... SFAS No. 143, "Accounting for Asset Retirement Obligations."
3
SFAS No. 144.................... SFAS No. 144, "Accounting for Impairment or Disposal of Long-Lived
Assets."
SFAS No. 145.................... SFAS No. 145, "Rescission of FASB Statements Nos. 4, 44 and 64,
Amendment of FASB Statement No. 13, and Technical Corrections."
SFAS No. 148.................... SFAS No. 148, "Accounting for Stock Based Compensation--
Transition and Disclosure."
Spark spread.................... the difference between power prices and natural gas fuel costs.
SRP............................. Saltwater River Project Agricultural Improvement and Power District of
the State of Arizona.
TCE............................. Texas Commercial Energy, a retail electric provider to ERCOT.
Texas electric restructuring law Texas Electric Choice Plan adopted by the Texas legislature in June
1999.
Texas Genco..................... Texas Genco Holdings, Inc., a subsidiary of CenterPoint, and its
subsidiaries.
Transition Plan................. Reliant Resources Transition Stock Plan, governing CenterPoint awards
held by our employees.
West Connect RTO................ the FERC approved RTO for all or part of Colorado, Arizona, New
Mexico and a portion of Texas.
4
PART I
ITEM 1. Business.
Our Business
General
Our business operations consist of the following four business segments:
. Retail energy--provides electricity and related services to retail
customers primarily in Texas and acquires and manages the electric
energy, capacity and ancillary services associated with supplying these
retail customers;
. Wholesale energy--provides electric energy and energy services in the
competitive segments of the United States wholesale energy markets;
. European energy--includes power generation assets in the Netherlands and
a related trading and origination business; and
. Other operations--includes our venture capital investment portfolio and
unallocated corporate costs.
For information about the revenues, operating income, assets and other
financial information relating to our business segments, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations--Earnings Before Interest and Income Taxes by Segment" in Item 7 of
this Form 10-K and note 20 to our consolidated financial statements. For
information about the risks and uncertainties relating to our business, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations--Risk Factors" in Item 7 of this Form 10-K.
Our website address is www.reliant.com. The information on our website is
not incorporated into this Form 10-K. A copy of this Form 10-K will be
available on our website. You may request a copy of this Form 10-K, at no cost,
by writing or telephoning us at 713-497-7000. Our executive offices are located
at 1111 Louisiana Street, Houston, Texas 77002.
Formation, IPO and Distribution
In June 1999, the Texas legislature adopted an electric restructuring law
that 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. In response to this legislation, CenterPoint,
formerly Reliant Energy, adopted a business separation plan in order to
separate its regulated and unregulated operations. Under the business
separation plan, we were incorporated in Delaware in August 2000, and
CenterPoint transferred substantially all of its unregulated businesses to us.
We completed an IPO of approximately 20% of our common stock in May 2001 and
received net proceeds from our IPO of $1.7 billion. We used $147 million of the
net proceeds of our IPO to repay certain indebtedness that we owed to
CenterPoint. We used the remainder of the net proceeds of our IPO for repayment
of third party borrowings, capital expenditures, repurchases of our common
stock and general corporate purposes. In September 2002, the Distribution was
completed and, as a result, we are no longer a subsidiary of CenterPoint. For
additional information regarding our IPO, see notes 1 and 10(a) to our
consolidated financial statements. For additional information regarding
agreements and transactions between us and CenterPoint, see "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.
Orion Power Acquisition
In February 2002, we acquired all of the outstanding common stock of Orion
Power for $2.9 billion and assumed debt obligations of $2.4 billion. Orion
Power is an independent electric power generating company with
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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 hydro. The Orion Power facilities constitute our
New York regional portfolio and the majority of our Midwest regional portfolio.
For additional information regarding our acquisition of Orion Power and its
operations, see "--Wholesale Energy--New York Region" and "--Midwest Region,"
in Item 1 and "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Risk Factors" in Item 7 of this Form 10-K and note 5(a)
to our consolidated financial statements.
Disposition of European Energy Operations
In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon. Upon consummation of the sale, we expect to receive
cash proceeds from the sale of approximately $1.2 billion (Euro 1.1 billion).
As additional consideration for the sale, we will also receive 90% of the
dividends and other distributions in excess of approximately $115 million (Euro
110 million) paid by NEA to REPGB following the consummation of the sale. The
purchase price payable at closing assumes that our European energy operations
will have, on the sale consummation date, net cash of at least $121 million
(Euro 115 million). If the amount of net cash is less on such date, the
purchase price will be reduced accordingly. The sale is subject to the approval
of the Dutch and German competition authorities. We anticipate that the
consummation of sale will occur in the summer of 2003. For further information
regarding the disposition of our European energy operations, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors" in Item 7 of the Form 10-K and note 21(b) to our consolidated
financial statements.
Retail Energy
We are a certified retail electric provider in Texas, which allows us to
provide electricity to residential, small commercial and large commercial,
industrial and institutional customers. In January 2002, we began to provide
retail electric service to all customers of CenterPoint that did not take
action to select another retail electric provider and to customers that
selected us to provide them electric service. All classes of customers of most
investor-owned Texas utilities can choose their retail electric provider. The
law also allows municipal utilities and electric cooperatives to participate in
the competitive marketplace, but to date, none have chosen to do so.
Our retail energy segment provides standardized electricity and related
products and services to residential and small commercial customers with an
aggregate peak demand for power up to one MW (i.e., small and mid-sized
business customers) and offers customized electric commodity and energy
management services to large commercial, industrial and institutional customers
with an aggregate peak demand for power in excess of one MW (e.g., refineries,
chemical plants, manufacturing facilities, real estate management firms,
hospitals, universities, school systems, governmental agencies, multi-site
retailers, restaurants, and other facilities under common ownership or
franchise arrangements with a single franchiser, which aggregate to one MW or
greater of peak demand).
We currently provide retail electric service only in Texas. We have no
near-term plans to provide retail electric service to residential customers
outside of Texas; however, we are taking steps to provide electricity and
related products and services to large commercial, industrial and institutional
customers in certain other states. In New Jersey, we are registered as an
"electric power supplier," and in Pennsylvania, we are registered as an
"electric generation supplier."
For information about the risks and uncertainties relating to our retail
energy segment, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Risk Factors--Risks Related to Our Retail
Energy Operations" in Item 7 of this Form 10-K.
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Residential and Small Commercial Services
We have approximately 1.5 million residential customers and over 200,000
small commercial accounts in Texas, making us the second largest retail
electric provider in Texas. The majority of our customers are in the Houston
metropolitan area, but we also have customers in other metropolitan areas,
including Dallas and Corpus Christi, Texas.
In general, the Texas regulatory structure permits retail electric providers
to procure electricity from wholesale generators at unregulated rates, sell the
electricity at generally unregulated prices to retail customers and pay the
local transmission and distribution utilities a regulated tariff rate for
delivering the electricity to the customers. By allowing retail electric
providers to provide retail electricity at any price, the Texas electric
restructuring law is designed to encourage competition among retail electric
providers. However, retail electric providers which are affiliates of, or
successors in interest to, electric utilities are restricted in the prices they
may charge to residential and small commercial customers within the affiliated
transmission and distribution utility's traditional service territory. We are
deemed to be the affiliated retail electric provider in Centerpoint's Houston
area service territory, and we are an unaffiliated retail electric provider in
all other areas. The prices that affiliated retail electric providers charge
are subject to a specified price, or "price to beat" and the affiliated retail
electric providers are not permitted to sell electricity to residential and
small commercial customers in the service territory of the affiliated
transmission and distribution utility at a price other than the price to beat
until January 2005, unless before that date 40% or more electricity consumed in
2000 by the relevant class of customers in the affiliated transmission and
distribution utility service territory is committed to be served by other
retail electric providers. Unaffiliated retail electric providers may sell
electricity to residential and small commercial customers at any price.
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 affiliated transmission and distribution
utility's traditional service territory until 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).
The PUCT's regulations allow an affiliated retail electric provider to
adjust the price to beat based on the wholesale energy supply cost component or
"fuel factor" included in its price to beat. The PUCT's current regulations
allow us to request an adjustment of our fuel factor based on the percentage
change in the forward price of natural gas or as a result of changes in the
price of purchased energy up to two times a year. In a purchased energy
request, we 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 PUCT. During 2002, we requested, and the PUCT approved
two such adjustments to our price to beat fuel factor. In January 2003, we
requested, and the PUCT approved in March 2003, an increase of our price to
beat fuel factor. We cannot estimate with any certainty the magnitude and
timing of future adjustments required, if any, or the impact of such
adjustments on our headroom. To the extent that a requested adjustment is not
received on a timely basis, our results of operations, financial condition and
cash flows may be adversely affected. For additional information regarding
adjustments to our price to beat fuel factor, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--EBIT by Business
Segment" in Item 7 of this Form 10-K.
In March 2003, the PUCT approved a revised price to beat rule. The changes
from the previous rule include an increase in the number of days used to
calculate the natural gas price average from ten to 20, and an increase in the
threshold of what constitutes a significant change in the market price of
natural gas and purchased energy from 4% to 5%, except for filings made after
November 15/th/ of a given year that must meet a 10% threshold. The revised
rule also provides that the PUCT will, after reaching a determination of
stranded costs in 2004, make downward adjustments to the price to beat fuel
factor if natural gas prices drop below the prices embedded in the then-current
price to beat fuel factor. In addition, the revised rule also specifies that
the base rate portion of the price to beat will be adjusted to account for
changes in the non-bypassable rates that result from the utilities' final
stranded cost determination in 2004. Adjustments to the price to beat will be
made following the utilities' final stranded cost determination in 2004.
7
To the extent that our price to beat for electric service to residential and
small commercial customers in CenterPoint's Houston service territory during
2002 and 2003 exceeds the market price of electricity, we may be required to
make a significant payment to CenterPoint in 2004. As of December 31, 2002, our
estimate for the payment related to residential customers is between $160
million and $190 million, with a most probable estimate of $175 million. For
additional information regarding this payment, see note 14(e) to our
consolidated financial statements.
Large Commercial, Industrial and Institutional Services
We provide electricity and energy services to large commercial, industrial
and institutional customers (i.e., customers with an aggregate peak demand of
greater than one MW) in Texas with whom we have signed contracts. As of
December 31, 2002, the average contract term for these contracts was 15 months.
In addition, we provide electricity to those large commercial, industrial and
institutional customers in CenterPoint's service territory who have not entered
into a contract with any retail electric provider. We also provide customized
energy solutions, including risk management and energy services products, and
demand side and energy information services to our large commercial, industrial
and institutional customers.
Our large commercial, industrial and institutional customers include
refineries, chemical plants, manufacturing facilities, real estate management
firms, hospitals, universities, school systems, governmental agencies,
multi-site retailers, restaurants, and other facilities under common ownership
or franchise arrangements with a single franchiser, which aggregate to one MW
or greater of peak demand. Excluding those parts of Texas not currently open to
competition, the large commercial, industrial and institutional segment in
Texas consists of approximately 2,700 buying organizations consuming an
estimated aggregate of approximately 17,000 MW of electricity at peak demand.
Our contracts with customers represent a peak demand of approximately 5,500 MW
at approximately 24,000 metered locations.
Provider of Last Resort
In Texas, a provider of last resort is required to offer a standard retail
electric service with no interruption of service, except in the event of
non-payment, to any customer requesting electric service, to any customer whose
certified retail electric provider has failed to provide electric service or to
any customer that voluntarily requests this type of service. Through a
competitive bid process administered by the PUCT, we were appointed to serve as
the provider of last resort in many regions of the state. We do not expect to
serve a large number of customers in this capacity, as many customers are
expected to subsequently select a retail electric provider. We will serve a
two-year term as the provider of last resort ending December 31, 2004. Pricing
for service provided by a provider of last resort may include a customer charge
and an energy charge, which for residential and small commercial customers is
adjustable based upon changes in the forward price of natural gas. For large
non-residential customers, the energy charge is adjusted based upon the ERCOT
market-clearing price of energy. For all customer classes, the adjustment to
the energy charge is subject to a floor amount. Non-residential customers will
be assessed a demand charge.
Retail Energy Supply
We continuously monitor and update our retail energy supply positions based
on our retail energy demand forecasts and market conditions. We enter into
bilateral contracts with third parties for electric energy, capacity and
ancillary services.
Texas Genco (currently 81% owned by CenterPoint), which owns approximately
13,900 MW of aggregate net generation capacity in Texas, is our primary source
of retail energy capacity.
The generating capacity of the Texas Genco 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. To
8
facilitate a competitive market in Texas, each power generator affiliated with
a transmission and distribution utility must sell at auction 15% of the output
of its installed generating capacity. These auction obligations will continue
until January 2007, unless at least 40% of the electricity consumed by
residential and small commercial customers in CenterPoint's service territory
is being served by retail electric providers other than us. An affiliated
retail electric provider may not purchase capacity sold by its affiliated power
generation company in the state mandated capacity auctions. Therefore, we are
prohibited from participating in the Texas Genco capacity auctions mandated by
the PUCT. We may purchase capacity from non-affiliated parties, other than
Texas Genco, in the capacity auctions mandated by the PUCT. Under an agreement
between us and CenterPoint, Texas Genco is required to auction the remaining
85% of its capacity. We have the right to purchase 50% (but not less than 50%)
of such remaining capacity at the prices established in such auctions. We also
have the right to participate directly in such auctions.
We have an option to acquire CenterPoint's ownership interest in Texas Genco
that is exercisable from January 10, 2004 until January 24, 2004. Texas Genco's
obligation to auction its capacity and our associated rights terminate (a) if
we do not exercise our option to acquire CenterPoint's ownership interest in
Texas Genco by January 24, 2004 and (b) if we exercise our option to acquire
CenterPoint's ownership interest in Texas Genco, on the earlier of (i) the
closing of the acquisition or (ii) if the closing has not occurred, the last
day of the sixteenth month after the month in which the option is exercised.
For additional information regarding our option to acquire Texas Genco, see
note 4(b) to our consolidated financial statements.
ERCOT
We are a member of ERCOT. The ERCOT ISO is responsible for maintaining
reliable operations of the bulk electric power supply system in the ERCOT
Region. 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 Region.
Unlike some independent system operators in other regions of the country, the
ERCOT ISO does not operate a centrally dispatched pool and 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. The ERCOT ISO also serves as agent for
procuring ancillary services for those who elect not to secure their own
ancillary services requirement.
Members of ERCOT include retail customers, investor and municipal owned
electric utilities, rural electric cooperatives, river authorities, independent
generators, power marketers and retail electric providers. The ERCOT Region
operates under the reliability standards set by the North American Electric
Reliability Council. The PUCT has primary jurisdictional authority over the
ERCOT Region to ensure the adequacy and reliability of electricity across the
state's main interconnected power grid.
The ERCOT Region is divided into four congestion zones: north, south, west
and Houston. While most of our retail demand and associated supply is located
in the Houston congestion zone, we serve customers and acquire supply in all
four congestion zones. In addition, ERCOT conducts annual and monthly auctions
of transmission congestion rights which provide the entity owning transmission
congestion rights the ability to financially hedge price differences between
zones (basis risk). The PUCT prohibits any single ERCOT market participant from
owning more than 25% of the available transmission congestion rights on any
congestion path.
For information regarding our generating facilities in the ERCOT Region, see
"Our Business--Wholesale Energy--ERCOT Region."
Competition
For information regarding competitive factors affecting our retail energy
segment, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Risk Factors - Risks Related to Our Retail Energy
Operations" in Item 7 of this Form 10-K.
9
Wholesale Energy
Our wholesale energy segment provides energy and energy services with a
focus on the competitive wholesale segment of the United States energy
industry. We have built a portfolio of electric power generation facilities,
through a combination of acquisitions and development, that are not subject to
traditional cost-based regulation; therefore, we can generally sell electricity
at prices determined by the market, subject to regulatory limitations. We trade
and market electricity, natural gas, natural gas transportation capacity and
other energy-related commodities. We also optimize our physical assets and
provide risk management services for our asset portfolio. In March 2003, we
decided to exit our proprietary trading activities and liquidate, to the extent
practicable, our proprietary positions. Although we are exiting the proprietary
trading business, we have existing positions, which will be closed as
economically feasible or in accordance with their terms. We will continue to
engage in hedging activities related to our electric generating facilities,
pipeline storage positions and fuel positions. For information about the risks
and uncertainties relating to our wholesale energy segment, see "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors--Risks Related to Our Wholesale Energy Operations " in Item 7 of this
Form 10-K.
Overview of Wholesale Energy Market
Over the past two years, the wholesale energy markets in the United States
have undergone dramatic changes. In late 2000 into early 2001, power markets
across most of the United States were trading at historical highs due in large
part to tight wholesale power market conditions, gas prices being at record
levels because of falling supplies and strong demand from a growing economy,
gas trading volumes continuing their rapid growth, and power trading and
generation companies having substantial access to the debt and equity markets.
However, during the summer of 2001, market conditions began to take a downward
turn when the first significant wave of nearly 200,000 MW of new generating
capacity commenced operations and began to ease the tight wholesale power
market conditions. Also, state regulators, in concert with the FERC, began to
impose price caps and other marketplace rules that resulted in power and
ancillary service prices in certain markets being at or near the variable cost
to provide them. Energy trading activity also saw a sharp reversal during 2001.
The failure of certain energy companies damaged the reputation of the entire
industry and energy trading specifically. The heightened attention on energy
trading businesses and the subsequent findings and allegations of questionable
business practices and transactions engaged in by a number of industry
participants, including us, caused a further erosion of confidence in the
industry. As a result, liquidity in the market began to decline.
The overall market conditions in the wholesale power industry continued to
worsen during 2002. With the addition of still more generation capacity and
heightened regulatory oversight, power prices continued their downward trend,
trading at or barely above the variable cost of production in many markets.
Confronted with a weaker profit outlook in both electric generation and energy
trading and significant amounts of short-term debt to be refinanced, credit
agencies began a series of downgrades of substantially all the industry's major
market participants, leaving many with below investment grade credit ratings.
These downgrades severely curtailed the access of these companies to the debt
or equity markets and triggered credit collateral requirements relating to
their trading and hedging activities. Consequently, many companies were forced
to significantly reduce their trading activities, which further reduced market
liquidity.
During the second half of 2002 and continuing into 2003, investors and
government regulators, as well as many industry participants and independent
observers urged industry reforms to provide more balanced and sustainable
long-term market conditions in both the power markets and the energy trading
markets. The most significant of these are the FERC's efforts to implement SMD
and industry efforts to develop clearing and settlement provisions at energy
exchanges that would greatly reduce collateral requirements of participating
companies.
Power Generation Operations
We own, own an interest in, or lease 128 operating electric power generation
facilities with an aggregate net generating capacity of 19,888 MW located in
six regions of the United States. The generating capacity of these
10
facilities consists of approximately 34% of base-load, 35% of intermediate and
31% of peaking capacity. We have two electric power generation facilities and
three replacement or incremental electric power generation units at existing
facilities, or 2,461 MW of net generating capacity, under construction.
The following table describes our electric power generation facilities and
net generating capacity by region:
Number of Total Net
Generation Generating
Region Facilities (1) Capacity (MW) (2) Dispatch Type (3) Fuel Type
------ -------------- ----------------- ------------------------ ------------------
Mid-Atlantic
Operating (4)................... 22 4,227 Base, Intermediate, Peak Gas/Coal/Oil/Hydro
Under Construction (6)(7)(8)(9). -- 1,120 Base, Intermediate, Peak Gas/Oil/Coal
-------------- -----------------
Combined........................ 22 5,347
New York
Operating (5)................... 77 2,952 Base, Intermediate, Peak Gas/Oil/Hydro
Midwest
Operating....................... 10 5,052 Base, Intermediate, Peak Gas/Oil/Coal
Southeast
Operating (10)(11).............. 5 2,210 Base, Intermediate, Peak Gas/Oil
Under Construction (6)(7)....... 1 800 Intermediate, Peak Gas
-------------- -----------------
Combined........................ 6 3,010
West
Operating (12)(13).............. 7 4,642 Base, Intermediate, Peak Gas/Oil
Under Construction (6).......... 1 541 Base, Intermediate, Peak Gas
-------------- -----------------
Combined........................ 8 5,183
ERCOT
Operating....................... 7 805 Base Gas/Landfill Gas
Total
Operating....................... 128 19,888
Under Construction.............. 2 2,461
-------------- -----------------
Combined........................ 130 22,349
============== =================
- --------
(1) Unless otherwise indicated, we own a 100% interest in each facility listed.
(2) Average summer and winter net generating capacity.
(3) We use the designations "Base," "Intermediate," and "Peak" to indicate
whether the facilities described are base-load, intermediate, or peaking
facilities, respectively.
(4) We lease a 100%, 16.67% and 16.45% interest in three Pennsylvania
facilities having 614 MW, 284 MW and 282 MW of net generating capacity,
respectively, through facility lease agreements having terms of 26.5 years,
33.75 years and 33.75 years, respectively.
(5) Excludes two hydro plants with a net generating capacity of 5 MW, which are
not currently operational.
(6) 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.
(7) Our two construction projects in the Mid-Atlantic region and one of our
projects in the Southeast region are owned by off-balance sheet special
purpose entities as of December 31, 2002 and are being constructed under
construction agency agreements (see note 14(b) to our consolidated
financial statements).
(8) The 1,120 MW of net generating capacity under construction is based on
1,317 MW of net generating capacity currently under construction, less 197
MW of net generating capacity that will be retired upon completion of one
of the projects.
(9) Our two construction projects in the Mid-Atlantic region are replacement or
incremental electric power generation units at existing facilities. These
units are reflected in the operating generation facilities count, but the
net generating capacity of such units will be reflected in the under
construction count until the units begin commercial operation.
(10) We own a 50% interest in one of these facilities having a net generating
capacity of 108 MW. An independent third party owns the other 50%.
(11) We lease a 100% interest in two Florida facilities having 630 MW and 474
MW of net generating capacity, respectively, through facility lease
agreements having terms of 10 years and 5 years, respectively.
(12) Beginning in January 2003, two California generation units having 264 MW
of total net generating capacity were idled due to a lack of required
environmental permits.
(13) We own a 50% interest in one Nevada facility having a total generating
capacity of 470 MW. An independent third party owns the other 50%.
11
Mid-Atlantic Region
Facilities. We own, own an interest in, or lease 22 operating electric
power generation facilities with an aggregate net generating capacity of 4,227
MW located in Pennsylvania, New Jersey and Maryland. The generating capacity of
these facilities consists of approximately 38% of base-load, 32% of
intermediate and 30% of peaking capacity.
We are constructing a 795 MW gas-fired intermediate and peaking generation
unit at an existing facility located in Pennsylvania. We expect this unit will
begin commercial operation in the third quarter of 2003. We are also
constructing a 522 MW coal-fired base-load unit that will replace two of our
generating units at an existing facility located in Pennsylvania. This new unit
will add 325 MW of additional generating capacity, net of the 197 MW of
generating capacity of the existing units that will be retired upon
commencement of commercial operations of the new unit. We expect this unit will
begin commercial operation near the end of 2004. These units are being
constructed under the terms of a construction agency agreement. For additional
information regarding the construction agency agreements, see notes 2(t), 14(b)
and 21(a) to our consolidated financial statements. Because of lower price
conditions in the PJM Market and the rising cost of operations, particularly
with respect to emission costs, we retired an 82 MW coal-fired facility located
in our Mid-Atlantic region in September 2002.
Market Framework. We currently sell the power generated by our Mid-Atlantic
facilities in the PJM Market and occasionally to buyers in adjacent power
markets, such as the ECAR Market and NY Market. We also expect to sell power in
a newly created PJM West Market. Each of the PJM, the NY and the PJM West
Markets operates as centralized power pools with open-access,
non-discriminatory transmission systems. The PJM and PJM West Markets are
administered by PJM, a FERC-approved RTO.
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 western Pennsylvania and upstate New York to eastern
Pennsylvania, New Jersey and New York City may be constrained. 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. Market prices
are generally higher in New York City than in other parts of New York due to
the transmission constraints.
In addition to managing the transmission system, PJM is responsible for
maintaining competitive wholesale markets, operating the spot wholesale
electric energy, capacity and ancillary services markets and determining the
market clearing price based on bids submitted by participating generators in
each market. PJM generally matches sellers with buyers within a particular
market that meet specified minimum credit standards. We sell electric energy,
capacity and ancillary services into the markets maintained by PJM on both a
real-time basis and a forward basis for periods of up to one year. Our
customers consist of the members of each market, including municipalities,
electric cooperatives, integrated utilities, transmission and distribution
utilities, retail electric providers and power marketers. We also sell electric
energy, capacity and ancillary services to customers in our Mid-Atlantic region
under negotiated bilateral contracts.
PJM has an internal market monitor. The internal market monitor reports on
issues relating to the operation of the PJM Market, including the determination
of transmission congestion costs or the potential of any market participation
to exercise market power within the PJM Market or PJM West Market. The internal
market monitor evaluates the operation of both spot and bilateral markets to
detect either design or structural flaws in the PJM Market and evaluates any
proposed enforcement mechanisms that are necessary to assure compliance with
the PJM Protocols.
The PJM Protocols allow energy demand to respond to price changes. The lack
of sufficient energy demand that may respond has been cited as the primary
reason for retaining the electric energy, capacity and ancillary service market
caps, which are currently set at $1,000 per MWh in the PJM Market and the
energy price mitigation measures in the PJM Market.
12
Energy market price mitigation measures are implemented for some generating
facilities when, in the opinion of PJM, transmission constraints are present.
This is commonly referred to as price capping. In such instances, PJM requires,
for purposes of system reliability, the dispatch of specific units. In the
opinion of PJM, these units are not needed to meet energy demand and are only
necessary to maintain the stability of the PJM transmission system. When price
capping is imposed, the asking price submitted by these generating facilities
is disregarded in setting the PJM market price and the subject units receive a
mitigated price that is generally equal to incremental operating costs of the
generating unit plus 10%. Historically, 11 generating facilities, representing
over 250 MW, in our Mid-Atlantic region have been consistently impacted by this
procedure. In addition, a few other generating facilities in our Mid-Atlantic
region have experienced occasional price capping during selective hours.
PJM attempts to ensure that there is sufficient generation capacity to meet
energy demand and ancillary services requirements through a capacity market.
All power retailers are required to demonstrate commitments for capacity
sufficient to meet their peak forecasted load plus a reserve above this level,
currently set at 18%. Prices for capacity are capped by PJM at approximately
$175 per MW per day.
New York Region
Facilities. We own 77 operating electric power generation facilities with
an aggregate net generating capacity of 2,952 MW located in New York. Our
generating facilities in the New York region consist of two distinct groups,
intermediate and peaking facilities located in New York City and, with the
exception of one gas-fired facility, 73 small run-of-river hydro facilities
located in central and northern New York State. The overall generating capacity
of these facilities consists of approximately 23% of base-load, 41% of
intermediate and 36% of peaking capacity. With the exception of one facility,
all of our New York facilities were acquired as a result of utility
divestitures.
Market Framework. We currently sell the power generated by our New York
regional facilities in the NY Market. In New York City, we sell electric energy
and ancillary services into both day-ahead and real-time markets and capacity
in the monthly and six month forward markets. Our customers include
municipalities, electric cooperatives, integrated utilities, transmission and
distribution utilities, retail electric providers and power marketers. Our
hydro facilities are currently under contract to sell all electric energy,
capacity and ancillary services to Niagara Mohawk under contract through
September 2004.
Our sales into markets administered by NYISO are governed by the NYISO
Protocols. The NYISO Protocols allow energy demand to respond to high prices in
emergency and non-emergency situations. The lack of sufficient energy demand
that may respond 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 MWh
in the NY Market.
The NYISO Protocols established a capacity market in order to ensure 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 additional local 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 only a few suppliers own the
existing in-city capacity, previously divested utility generation is subject to
a capacity price cap. Any generation capacity added following divestiture is
not subject to a capacity price cap.
NYISO has implemented a measure known as the "automated mitigation
procedure" under which day-ahead energy bids will be automatically reviewed. If
bids exceed certain pre-established thresholds and have a significant impact on
the market-clearing price, the bids are then reduced to a pre-established
market based or negotiated reference bid. NYISO has also adopted, at the FERC's
direction, more stringent mitigation measures for all generating facilities in
transmission-constrained New York City.
13
NYISO has an internal market monitoring organization. The market monitor
assesses the efficiency and effectiveness of the electric energy, capacity and
ancillary services. In performing these functions, the internal market monitor
develops reference price levels for each generator, oversees the operation of
NYISO's automatic mitigation procedure, investigates potential anti-competitive
behavior by market participants, recommends changes in market Protocols and
prepares periodic reports for submission to the FERC and other agencies. In
addition, NYISO also has an external market advisor that works closely with the
market monitor and has the independent authority to suggest changes in
Protocols or recommend sanctions or penalties directly to the NYISO governing
board. The NYISO market advisor issues written reports containing analyses and
recommendations, which are made available to the public.
For additional information on the NY Market, see "Business--Mid-Atlantic
Region--Market Framework" in Item 1 of this Form 10-K.
Midwest Region
Facilities. We own 10 operating electric power generation facilities with
an aggregate net generating capacity of 5,052 MW located in Illinois, Ohio,
Pennsylvania and West Virginia. The generating capacity of these facilities
consists of approximately 57% of base-load, 6% of intermediate and 37% of
peaking capacity.
Market Framework. We generally sell the electric energy, capacity and
ancillary services generated and/or provided by our Midwest region portfolio
into the PJM West Market, the ECAR Market and the MAIN Market. These markets
include all or portions of Illinois, Wisconsin, Missouri, Indiana, Ohio,
Michigan, Virginia, West Virginia, Tennessee, Maryland and Pennsylvania. The
PJM West Market operates as part of the PJM centralized power pool with
open-access, non-discriminatory transmission system administered by an
independent system operator approved by the FERC that is responsible for, among
other things, maintaining competitive wholesale markets, operating the spot
wholesale energy market and determining the market clearing price. For
additional information on the PJM Market and the PJM West Market, see
"Business--Mid-Atlantic Region--Market Framework" in Item 1 of this Form 10-K.
The ECAR and MAIN Markets continue to be in a state of transition and are in
the process of establishing RTOs that would define the rules and requirements
around which competitive wholesale markets in the region would develop. The
FERC has granted RTO status to the MISO, which administers a substantial
portion of the transmission facilities in the Midwest region. The FERC has also
approved the various RTO selections made by the members of the former Alliance
RTO. Some of the members of this group will join the MISO and others will join
PJM. The final market structure for the Midwest region remains unsettled. Some
states within the ECAR and MAIN Markets have restructured their retail electric
power markets to competitive markets from traditional utility monopoly markets,
while others have not.
The FERC has also required MISO to engage the services of an independent
market monitor. The independent market monitor's duties include monitoring the
functioning of the markets run by the MISO to ensure that they are functioning
efficiently. This includes identifying factors that might contribute to
economic inefficiency such as design flaws, inefficient market rules and
barriers to entry. The independent market monitor must also monitor the conduct
of individual market participants. MISO is currently waiting on approval by the
FERC for a market mitigation plan that resembles the automated mitigation
procedure utilized by NYISO.
Our generating facilities located in Pennsylvania, Ohio, and West Virginia
straddle the PJM West and other ECAR Markets. Currently, these generating
facilities are primarily dedicated to serving the power demands of Duquesne
Lighting Company in the greater Pittsburgh area under a contract through
December 2004. During periods when the capacity of the generating facilities in
our Midwest region exceeds the power demands of the Duquesne Lighting Company,
we sell the excess power in the day-ahead markets or to municipalities,
electric cooperatives, vertically integrated utilities, transmission and
distribution utilities and power marketers.
14
We currently sell electric energy, capacity and ancillary services from our
Illinois generating facilities under bilateral contracts that have terms and
conditions tailored to meet the customers' requirements. Our customers include
municipalities, electric cooperatives, vertically integrated utilities,
transmission and distribution utilities and power marketers.
Southeast Region
Facilities. We own, own an interest in, or lease five power generation
facilities with an aggregate net generating capacity of 2,210 MW located in
Florida and Texas. The generating capacity of these facilities consists of
approximately 2% of base-load, 27% of intermediate and 71% of peaking capacity.
We are constructing an 800 MW gas-fired intermediate and peaking facility in
Mississippi. We expect this facility will begin commercial operation in the
third quarter of 2003. This facility is being constructed under the terms of a
construction agency agreement. For additional information regarding the
construction agency agreement, see note 14(b) to our consolidated financial
statements.
Market Framework. We currently conduct the majority of our Southeast
regional operations in Florida. Florida, other than a portion of the western
panhandle, constitutes a single reliability council and contains approximately
5% of the United States population. Although dominated by incumbent utilities,
Florida is in the process of transitioning to a competitive wholesale
generation market by developing rules for new capacity procurement and
establishing the GridFlorida RTO. The FPSC has implemented new capacity
procurement rules that require utilities to seek bids to purchase electricity
from independent power producers and other utilities before embarking on
self-build options for new capacity requirements. Additionally, the FPSC has
approved a proposal to increase the level of planning reserve capacity from 15%
to 20%. This new criterion applies to the three investor-owned utilities
operating in peninsular Florida and becomes effective in the summer of 2004.
The Florida markets are expected to be administered by the GridFlorida RTO.
For the past year, the Grid Florida RTO's activities have focused on concerns
expressed by the FPSC. However, recent progress has been slow due to a legal
challenge by the state's consumer advocate division, which is disputing the
FPSC's authority to authorize the transfer of assets to an RTO. A decision on
this matter may not be reached until early 2004. At this time, the GridFlorida
RTO has not finalized its proposal for market monitoring, but it will be
obligated to establish a market monitor.
We currently sell electric energy and capacity into the Florida market
primarily under bilateral contracts that are non-standard and negotiated for
terms and conditions. An OTC trading and ancillary services market has yet to
fully develop. Customers who participate in power transactions in this region
include municipalities, electric cooperatives and integrated utilities.
In the rest of the Southeast Region, RTO formation is occurring under the
auspices of the SeTrans RTO. The SeTrans RTO will cover the area from Georgia
to eastern Texas. While the FERC has currently approved the basic formation of
this entity, significant details of this market will not be known until mid or
late 2003. Because the SeTrans RTO is still in the formative stages of
development, it has only recently begun the process of selecting the
independent entity that will become its market monitor.
West Region
Facilities. We own, or own an interest in, seven electric power generation
facilities with an aggregate net generating capacity of 4,642 MW located in
California, Nevada and Arizona. The generating capacity of these facilities
consists of approximately 18% of base-load, 75% of intermediate and 7% of
peaking capacity. We are constructing a 541 MW gas-fired, base-load,
intermediate and peaking generation facility in southern Nevada. We expect this
facility will begin commercial operation in the fourth quarter of 2003.
15
Market Framework. Our West regional market includes the states of Arizona,
California, Oregon, Nevada, New Mexico, Utah and Washington. Generally we sell
the electric energy, capacity and ancillary services generated and/or provided
by our California and Nevada facilities to customers located in the greater Los
Angeles metropolitan area and in southern Nevada. We believe that our portfolio
of intermediate and peaking facilities in southern California is important to
the reliability of the California market given its production flexibility and
close proximity to Los Angeles. Our customers in these states include power
marketers, investor-owned utilities, electric cooperatives, municipal utilities
and the Cal ISO acting on behalf of load-serving entities. We sell electric
energy, capacity 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 capacity market to ensure resource
adequacy; however, California regulatory authorities are in the process of
developing such a mechanism.
We have agreed to sell up to 100% of our 588 MW operating Arizona facility's
capacity to SRP under a long-term power purchase agreement. In addition,
although we do not own generation facilities in the states of Oregon, New
Mexico, Utah and Washington, our trading and marketing operations have
historically purchased and delivered energy commodities in these states.
Two units at our Etiwanda facility in California totaling 264 MW of
intermediate capacity, under their current configuration, do not satisfy the
more stringent emissions standards that went into effect in 2003. We will
evaluate the California capacity market in the second quarter of 2003 and
determine whether to make the investment in the necessary environmental
upgrades or retire the units.
In response to California's energy crisis of 2000 and 2001, the FERC and the
Cal ISO have instituted energy price caps, formerly set below $100 per MWh and
currently set at $250 per MWh, and must-offer requirements affecting all
merchant generators in California. Furthermore, the Western region has seen
significant new generation capacity become operational as well as a return to
more normal hydro and temperature conditions. The impact of these regulatory
and market changes has been to significantly lower power prices and spark
spreads in the West region.
The Cal ISO has a department of market analysis that acts as its internal
market monitor. The department of market analysis monitors the efficiency and
effectiveness of the ancillary services, congestion management and real-time
energy markets. In performing these functions, the department of market
analysis develops and publishes market performance indices, investigates
potential anti-competitive behavior by market participants, recommends changes
in market rules and protocols, and prepares periodic reports for submission to
the FERC and other agencies. In addition to the department of market analysis,
the Cal ISO also has a market surveillance committee that acts as its external
advisor. The market surveillance committee works closely with the department of
market analysis and has the independent authority to suggest changes in Cal ISO
Protocols or recommend sanctions or penalties directly to the Cal ISO governing
board. The market surveillance committee periodically produces written reports
containing its analyses and recommendations, which are made available to the
public subject to restrictions on confidential information. The Cal ISO has
initiated, at the FERC's direction, automated mitigation procedures when any
zonal clearing price for balancing energy exceeds $91.87 per MWh with any
resulting zonal clearing price subject to the price cap of $250 per MWh. The
automated mitigation procedures are only applied to bids that exceed certain
reference prices and that would significantly increase the market price.
However, in February 2003, the Cal ISO stated that it intends to appeal the
FERC's decision regarding the application of automated mitigation procedures to
local market power situations. While the FERC had adopted similar thresholds
for both local and system market power, the Cal ISO is seeking to have a more
restrictive procedure applied to local market power.
16
A number of initiatives currently under consideration could materially
impact our California operations. These initiatives include:
. a California law directing the CPUC to seek approval from the FERC to
allow the CPUC to enforce state-established maintenance and operation
standards of our California plants;
. implementation of a CPUC procurement process directing California
utilities to procure, on a forward basis, electricity and capacity to
serve the demand on their systems;
. efforts by the Cal ISO to redesign the spot markets in California; and
. the effect of the FERC's SMD effort, including its impact on the FERC
approved western RTOs.
For additional information regarding SMD, see "Business--Wholesale
Energy--Regulatory" in Item 1 of this Form 10-K.
In Nevada and Arizona, there is presently no RTO in place to manage the
transmission systems or to operate energy markets, although the utilities in
both states are participating in the development of RTOs. The West Connect RTO,
which includes Arizona, and the RTO West, which includes Nevada, have both been
approved by the FERC and are in process of developing operating rules and
tariffs. Both RTOs are expected to be operational and assume control over
transmission of facilities of participating utilities within the next several
years. The FERC has also approved the establishment of market monitoring
organizations as part of RTO West and West Connect RTO. The FERC is encouraging
the RTOs to coordinate in the development of a region-wide market monitoring
function. 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. Nevada also passed legislation and adopted
regulations allowing large commercial and industrial customers to seek
competitive alternatives to utility generation. In Arizona, proceedings are
pending before the Arizona Corporate Commission that would require the state's
investor owned utilities to seek competitive supply offers to serve 2,500 to
3,200 MW of local system demand.
ERCOT Region
Facilities. We own seven power generation units at two facilities with an
aggregate net generating capacity of 805 MW located in Texas. The generating
capacity of these facilities consists of 100% base-load capacity.
Market Framework. For information regarding the market framework in the
ERCOT region, see "Business--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 electric energy, capacity and
ancillary services, 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, see notes 14(f), 14(k) and 14(l) to our consolidated
financial statements. For information regarding our hedging strategy relating
to such long-term commitments, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Risk Factors--Risks Related to
Our Wholesale Energy Operations" in Item 7 of this Form 10-K.
Commercial Operations
Strategy. Our domestic commercial business optimizes our physical asset
positions consisting of our power generation asset portfolio, pipeline storage
positions and fuel positions and provides risk management services for our
asset positions. We perform these functions through trading, marketing and
hedging activities for power, fuels and other energy related commodities. With
the downturn in the industry, the decline in market liquidity, and our
liquidity capital constraints, the principal function of our commercial
activities has shifted to optimizing our assets. Previous large volume
activities primarily involving risk management to customers, gas marketing to
third parties and trading of power and gas have been significantly reduced, and
in some cases eliminated. As a result, we have reduced our trading workforce
from 264 to 160 as of December 31, 2002, which
17
include traders, originators, dispatchers and schedulers. We have also reduced
support staff, including technical staff, accountants and risk control
personnel, from 645 to 587 as of December 31, 2002. In addition to these
staffing reductions, several unfilled positions were eliminated. In March 2003,
we decided to exit our proprietary trading activities and liquidate, to the
extent practicable, our proprietary positions. Although we are exiting the
proprietary trading business, we have existing positions, which will be closed
as economically feasible or in accordance with their terms. We will continue to
engage in hedging activities related to our electric generating facilities,
pipeline storage positions and fuel positions.
Asset optimization and risk management. Our domestic commercial businesses
complement our merchant power generation business by providing a full range of
energy management services. These services focus on two core functions,
optimizing our physical asset position and providing risk management services
for our portfolio. To perform these functions, we trade, market and hedge
electric energy, capacity and ancillary services, as well as manage the
purchase and sale of fuels and emission allowances.
Asset optimization is maximizing the financial performance of an asset
position. Our commercial groups optimize our assets by employing different
products (e.g., on-peak power), geographic markets (e.g., buying from and
selling into adjacent markets), fuel types (e.g., burning oil rather than
natural gas at our fuel switching capable plants) and transaction terms (spot
to multi-year term).
Risk management services focus on managing the performance risk and price
risk (of both purchases and sales) inherent in the asset position. The ultimate
purpose of this activity is to identify the risks and reduce the volatility
they could cause in our financial performance. Our commercial groups assist our
risk control personnel and management in the identification of these risks and
execute the transactions necessary to achieve this goal. As an example of this,
we generally seek to sell a portion of the capacity of our domestic facilities
under fixed-price sale contracts (energy or capacity) or contracts to sell
energy at a predetermined multiple of fuel prices. Generally, we also seek to
hedge our fuel needs associated with our forward power sale obligations. These
power sales and fuel purchases provide us with certainty as to a portion of our
margins. With respect to performance risk, we also take into account plant
operational constraints and operating risk in making these determinations.
Physical power and services from our assets portfolios are sold in
real-time, hour-ahead, day-ahead, or multi-month or multi-year term markets.
For purposes of supplying our generation, we purchase fuel from a variety of
suppliers under daily, monthly and term, variable-load and base-load contracts
that include either market-based or fixed pricing provisions. We use derivative
instruments to execute these transactions. For additional information regarding
our financial exposure to derivative instruments, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Risk
Factors--Risks Related to Our Businesses Generally" in Item 7 of this Form 10-K
and "Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of
this Form 10-K.
In addition, as part of our efforts to commercialize our asset portfolio and
provide risk management services, we arrange for, schedule and balance the
transportation of the natural gas from the supply receipt point to our plants.
We generally obtain pipeline transportation to perform this function.
Accordingly, we use a variety of transportation arrangements 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. In the normal course of
business, it is common for us to hedge the risk of pipeline transportation
expenses through "basis swap" transactions.
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 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 support of our optimization and risk management effects, our power
origination group, working closely with our other commercial groups, focuses on
developing customized near-term products and long-term
18
contracts. These are designed and negotiated on a case-by-case basis to meet
the specific energy requirements of our customers. The target customer group
generally includes investor-owned utilities, municipalities, cooperatives and
other companies that serve end users.
Risk management services to customers. In addition to optimizing our power
asset portfolio, our trading and marketing businesses provide risk management
services to a variety of customers, which include natural gas distribution
companies, electric utilities, municipalities, cooperatives, power generators,
marketers or other retail energy providers, aggregators and large volume
industrial customers. Risk management services primarily focus on mitigating
customers' commodity price exposure and providing firm delivery services. To
provide these services to these customers, we utilize the same skills and
physical and financial instruments used to optimize and manage the risks of our
asset portfolio. See below for the discussion of our decision to exit
proprietary trading in March 2003.
Proprietary Trading. Our commercial business obtains proprietary market
knowledge and develops proprietary analysis through its efforts to manage our
asset portfolio and provide risk management services to our customers. This
enables our commercial groups to selectively take market positions, typically
on a short-term basis, in power, fuel and other energy related commodities. Our
commercial groups used derivative instruments to execute these transactions. In
March 2003, we decided to exit our proprietary trading activities and
liquidate, to the extent practicable, our proprietary positions. Although we
are exiting the proprietary trading business, we have existing positions, which
will be closed as economically feasible or in accordance with their terms. We
will continue to engage in hedging activities related to our electric
generating facilities, pipeline storage positions and fuel positions.
Risk Management Controls. For information regarding our risk management
structure and policies relating to our trading and marketing operations, see
"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.
Regulation
Electricity. 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 electric energy, capacity and ancillary services at wholesale
and are public utilities with the exception of two facilities in Texas that are
classified as qualifying facilities and not regulated as public utilities. The
FERC has authorized all of our generation 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 and exercise 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.
The FERC has issued a notice of proposed rulemaking describing its intention
to standardize electricity markets and eliminate continuing discrimination in
transmission service, with a proposed implementation date of September 2004.
The goal of SMD is to promote a more economically efficient market design that
will lower delivered energy costs, maintain reliability, mitigate market power
and increase customer choice options. SMD
19
proposes to eliminate discrimination in transmission service by requiring that
all users of the grid take service pursuant to the same rates and terms and
conditions of service, thus eliminating certain existing preferences enjoyed by
some classes of customers. In addition, transmission-owning public utilities
will be required to turn over the operation of their transmission systems to an
independent transmission provider. SMD also seeks to establish day-ahead and
real-time electric energy and ancillary service markets modeled after the
energy markets that currently exist in the Northeast. Finally, SMD proposes to
establish a capacity obligation on load serving entities and establishes
nationwide price mitigation measures.
The FERC also continues to promote the formation of large RTOs and has
issued numerous orders on the various RTO proposals. The FERC's goal is to
promote the formation of a robust wholesale market for electricity. While RTO
participation by public utilities is voluntary, the overwhelming majority of
the FERC jurisdictional utilities have indicated that they will join the
proposed RTO for their region. At this time there are approximately nine
proposed RTOs covering the vast majority of the continental United States. In
addition, large portions of the nation's transmission system are currently
operated by an independent entity. The Midwest grid is operated by the MISO and
the Northeast grid is operated by three separate independent entities: New
England ISO, NYISO and PJM. The ERCOT ISO independently operates the Texas
grid. MISO and PJM have received RTO status from the FERC.
Commercial Activities. Our domestic commercial operations are also subject
to the FERC's jurisdiction. 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.
Hydroelectric Facilities. Our hydroelectric generation facilities are
subject to the FERC's exclusive authority 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.
SEC. 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 PUHCA as an exempt wholesale generator. Our electric
generation facilities have received determinations of exempt wholesale
generator status from the FERC. If we lose our exempt wholesale generator
status or qualifying facility status, we would have to restructure our
organization or risk being subjected to further regulation by the SEC.
Competition
For a discussion of competitive factors affecting our wholesale energy
segment, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Risk Factors--Risks Related to Our Wholesale Energy
Operations" in Item 7 of this Form 10-K.
20
European Energy
In Europe, we own and operate electric generation facilities and conduct
trading and origination operations. In February 2003, we agreed to sell our
European energy operations. We expect to consummate the sale during the summer
of 2003. For additional information regarding the disposition of our European
energy operations, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations--Risk Factors--Risks Related to the Sale of
Our European Energy Operations" and note 21(b) to our consolidated financial
statements.
European Power Generation and Supply
Facilities. We own five electric power generation facilities with an
aggregate net generating capacity of 3,496 MW, of which 3,231 MW are
operational, located in the Netherlands. These facilities consist of
approximately 39% of base-load, 15% of intermediate and 46% of peaking
capacity. Our facilities are grouped in three clusters adjacent to the cities
of Amsterdam, Utrecht and Velsen. In 2002, our generation facilities produced
14.2 million MWh, an amount that represented approximately 13% of the
electricity production of the Netherlands. In addition to electricity, our
generating stations sell heated water produced as a byproduct of the generation
process for use in providing heating to the cities of Amsterdam, Nieuwegein,
Utrecht and Purmerend and provide ancillary services, including grid support
services, to transmission system owners.
In 2002, on a volumetric basis, approximately 50% of our European generation
output was natural gas-fired, 30% was coal-fired, and 20% was blast furnace
gas-fired. We purchase substantially all of our European gas fuel requirements
under an annual gas purchase contract 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. We obtain our European coal
requirements through short to medium-term forward purchase contracts on the
open market through a variety of suppliers and brokers. One of our European
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 generation plants
have the flexibility to operate using blast furnace gas. We purchase
substantially all blast furnace gas for the 144 MW facility from the adjacent
steel plant under a medium-term and a long-term contract.
Market Framework. Our European energy segment produces, buys and sells
electricity, gas and other energy-related commodities primarily in the
Netherlands wholesale market. Our energy trading and origination operations and
activities are concentrated in Northern Europe.
The primary customers in the Netherlands 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 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 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. In some cases, fuel suppliers continue to operate in
largely regulated markets not yet open to full competition.
There are 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
21
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 terminations 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.
European Trading and Origination
Our European trading and origination operations are currently centered in
the Netherlands, with an additional office in Germany. Our European trading and
origination operations will focus on hedging and optimizing our generation
assets in the Netherlands. During 2002, we traded electricity and fuel products
in the Netherlands, Germany, Austria, the United Kingdom and the Scandinavian
countries. As of December 31, 2002, we had entered into forward purchase and
sale contracts, and associated hedging transactions, covering approximately
13.6 million MWh for delivery in 2003. In September 2002, we decided to
substantially exit our proprietary trading activities in Europe and, in March
2003, we decided to exit our proprietary trading activities for the company as
a whole.
Regulation
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 based on generation
output. The remuneration included fuel cost, return of and on capital and
operation and maintenance expenses. In 2001, the wholesale energy market in the
Netherlands was opened to competition. We continue to be subject to regulation
by national and indirectly by European regulatory agencies and operate under
regulations relating to the environment, labor, tax and other matters. For
example, our operations are subject to the regulation of Dutch and European
Community anti-trust authorities, that have extensive authority to investigate
and prosecute violations by energy companies of anti-monopolistic and
price-fixing regulations. In addition, our European operations must also comply
with various national technical codes and other regulations establishing access
to transmission systems. Many of our significant suppliers and customers in
Europe are subject to continued regulation by various national energy
regulatory bodies having the authority to establish tariffs for such suppliers
and customers. The impact of regulations on these entities has an indirect
impact on our European operations.
Competition
For a discussion of competitive factors affecting our European energy
segment, see "Management's Discussion and Analysis of Financial Condition and
Operations--Risk Factors--Risks Related to Our European Energy Operations" in
Item 7 of this Form 10-K.
Other Operations
Our other operations business segment includes the following:
. our venture capital investment portfolio; and
. unallocated corporate costs.
We are currently managing our venture capital investment portfolio and do
not have plans to expand this business. As of December 31, 2002, the net book
value of these investments is $44 million. See note 2(o) to our consolidated
financial statements.
22
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. We anticipate spending approximately $208
million from 2003 through 2007 for environmental compliance.
If we do not comply with environmental requirements that apply to our
operations, regulatory agencies could seek to impose on us civil,
administrative and/or criminal liabilities as well as seek to curtail our
operations. Under some statutes, private parties could also seek to impose
civil fines or liabilities for property damage, personal injury and possibly
other costs.
Air Quality Matters
As part of the 1990 amendments to the Federal Clean Air Act, standards for
the emission of nitrogen oxide, a product of the combustion process associated
with power generation, are being developed or have been finalized. The
standards require reduction of emissions from our power generating facilities
in the United States.
The EPA has announced its determination to regulate hazardous air
pollutants, including mercury, from coal-fired and oil-fired steam electric
generating facilities under Section 112 of the Clean Air Act. The EPA plans to
develop maximum achievable control technology standards for these types of
generating facilities as well as for turbines, engines, and industrial boilers.
The rulemaking for coal and oil-fired steam electric generating facilities must
be completed by December 2004. Compliance with the rules will be required
within three years thereafter. The maximum achievable control technology
standards that will be applicable to the generating facilities cannot be
predicted at this time and may adversely impact our operations. The rulemaking
for turbines is expected to be complete in August 2003, and for engines and
industrial boilers in early 2004. Based on the rules currently proposed, we do
not anticipate a material adverse impact on our operations.
In 1998, the United States became a signatory to the United Nations
Framework Convention on Climate Change or "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 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 previously adopted
EPA ambient air quality standards for fine particulate matter and ozone. While
attaining these new standards may ultimately require
23
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.
In February 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, nitrogen oxide and mercury. If approved by the United States
Congress, this program would entail a market-based approach using emission
allowances; compliance with emission limits would be phased in over a period
from 2008 to 2018. The Clear Skies Initiative has the potential to revise or
eliminate several of the programs discussed above, including the maximum
achievable control technology standards, the coal-fired utility enforcement
initiative and fine particulate controls. In addition, a voluntary program for
reducing greenhouse gas emissions was proposed as an alternative to the Kyoto
Protocol. Fossil fuel-fired power plants in the United States would be affected
by the adoption of this program, or other legislation that may be enacted by
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.
Units 1 and 2 of our Etiwanda Generating Station in California are currently
subject to a regulatory permit variance that requires these units to be
equipped with a selective catalytic reduction system or cease operation. We
must decide by June 2003 to either surrender the permits for these units or
commence the installation of a selective catalytic reduction system by the end
of March 2004. Each unit has a rated capacity of 132 MW. Under the regulatory
permitting rules regarding peaking generation facilities, our Etiwanda Unit 5
must have the "best available control technology" installed by the end of
December 2003 or cease operation. We will evaluate the California capacity
market in the second quarter of 2003 and determine whether to make the
investment in the necessary environmental upgrades or retire the units.
Our facilities in the Netherlands were in compliance with applicable Dutch
nitrogen oxide emission standards through the year 2002. New nitrogen oxide
reduction targets have recently been adopted in the Netherlands, which will
require a 50% reduction in nitrogen oxide emissions from stationary sources
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. Regarding present emissions, we
currently believe that our European facilities will not be required to install
nitrogen oxide controls or purchase emission credits before January 2006.
Projected emission control costs are estimated to be approximately $45 million,
although this investment may be offset to some extent or delayed if a
market-based trading program develops.
The European Union, of which the Netherlands is a member, adopted the Kyoto
Protocol as the goal for greenhouse gas emission targets. 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. Pilot testing of a number of fuels classified as "non-fossil" was
initiated in 2002.
Water Quality Matters
As a result of litigation and technological improvements, state and federal
efforts toward implementing the total maximum daily load provisions of the
Clean Water Act have substantially increased in recent years. The establishment
of total maximum daily loads to restore water bodies currently designated as
impaired may result in more stringent discharge limitations for our facilities.
Compliance with such limitations may require our facilities to install
additional water treatment systems, modify operational practices or implement
other wastewater control measures, the costs of which cannot be estimated at
this time.
In April 2002, the EPA proposed rules under Section 316(b) of the Clean
Water Act relating to the design and operation of cooling water intake
structures. This proposal is the second of three current phases of
24
rulemaking dealing with Section 316(b) and generally would affect existing
facilities that use significant quantities of cooling water. Under the amended
court deadline, EPA is to issue final rules for these Phase II facilities by
February 2004. While the requirements of the final rule cannot be predicted at
this time, there are significant potential implications under the EPA proposal
for our generating facilities.
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
In connection with our acquisition of facilities, we, with a few exceptions,
assumed liability for preexisting conditions, including some ongoing
remediations. Funds for carrying out identified remediations have been included
in our planning for future funding 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 operations 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 to
remediate a coal refuse pile on the property of the facility. Under the
acquisition agreements between Sithe Energies, Inc. and GPU, Inc. relating to
some of our Mid-Atlantic 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 $6 million. We expect our remaining obligation on the coal
refuse site to be $1 million. In August 2000, we signed a modified consent
order agreement that committed us to complete the remediation no later than
November 2004. In connection with the acquisition of some of our Mid-Atlantic
facilities, we have liabilities associated with six future ash disposal site
closures. We expect to pay approximately $5 million over the next five years
toward closure of these facilities.
Under the New Jersey Industrial Site Recovery Act, owners and operators of
industrial properties are responsible for performing all necessary remediation
at a facility prior to the closing of the facility and the termination of
operations, or undertake actions that ensure that the property will be
remediated after the closing of the facility and the termination of operations.
In connection with the acquisition of our facilities from Sithe Energies, Inc.,
we have agreed to take responsibility for costs relating to the four New Jersey
properties we purchased from Sithe Energies, Inc. We estimate that the costs to
fulfill our obligations under the act will be approximately $8 million, which
we expect to pay out through 2007. 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 was received in 1999 from the Florida Department
of Environmental Protection. In response to that letter, a study to evaluate
the cause of the elevated constituents was undertaken and operational
procedures were modified. At this time, if remediation is required, the cost,
if any, is not anticipated to be material.
In connection with the acquisition of 70 hydro plants in northern and
central New York, three gas/oil-fired plants in New York City, and one
gas/oil-fired plant in central New York, Orion Power assumed the liability for
the environmental remediation at several properties. Orion Power developed
remediation plans for each of the subject properties and entered into consent
orders with the New York State Department of Environmental Conservation at the
three New York City sites and one hydro site for releases of petroleum and
other substances
25
by the prior owners. The remaining portion of the liability we assumed for
historical releases at all of these New York plants is approximately $8
million, which we expect to pay out through 2006. The consent order related to
one New York City site also contained a provision to mitigate alleged impacts
on fish populations. Activity on this issue was temporarily stayed pending the
outcome of potential repowering opportunities. However, should repowering be
considered inappropriate for this site, best technology available upgrades to
the existing water intake system will have to be negotiated with the New York
State Department of Environmental Conservation.
In connection with acquisition of Midwest assets by Orion Power, Orion Power
became responsible for the liability associated with the closure of three ash
disposal sites in Pennsylvania. The liability we assumed and recorded for these
disposal sites as of December 31, 2002 was approximately $14 million, with $1
million to be paid over the next five years.
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 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 the act that would have a material adverse effect on
our results of operations, financial position or cash flows.
Other European Environmental Matters
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 by partial
switch from coal to fuels such as biomass, which are termed "non-fossil fuels"
for purposes of compliance under the program. The environmental laws also
address public safety. Our European energy segment holds all necessary
authorizations and approvals for its current operations.
Nitrogen oxide reduction targets will require a 50% reduction in nitrogen
oxide emissions of stationary sources 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
nitrogen oxide emission standards. Based on current factors, we have determined
that our European facilities will not be required to install nitrogen oxide
controls or purchase emission credits earlier than 2006.
Our European energy operations have budgeted to spend approximately $45
million in emission control and other environmental costs associated with our
European energy segment for the period 2003 through 2007. In addition, we
expect to spend approximately $8 million in asbestos and other environmental
remediation programs during this period.
26
Employees
As of December 31, 2002, we had 6,002 full-time employees. Of these
employees, 1,930 are covered by collective bargaining agreements. The
collective bargaining agreements expire on various dates until May 14, 2007.
The following table sets forth the number of our employees by business segment
as of December 31, 2002:
Segment Number
------- ------
Retail energy.... 1,633
Wholesale energy. 3,143
European energy.. 680
Other operations. 546
-----
Total..... 6,002
=====
Executive Officers
Name Age Present Position
- ---- --- ----------------
R. Steve Letbetter. 55 Chairman and Chief Executive Officer
Stephen W. Naeve... 55 President and Chief Operating Officer
Robert W. Harvey... 47 Executive Vice President and Group President--Retail Business
Mark M. Jacobs..... 41 Executive Vice President and Chief Financial Officer
Hugh Rice Kelly.... 60 Senior Vice President, General Counsel and Corporate Secretary
Thomas C. Livengood 47 Vice President and Chief Accounting Officer
R. Steve Letbetter is our Chairman and Chief Executive Officer. Mr.
Letbetter served as Chairman of CenterPoint from January 2000 until the
Distribution and as President and Chief Executive Officer from June 1999 until
the Distribution. Since 1978, he has served in various positions as an officer
of CenterPoint and its corporate predecessors. Mr. Letbetter was a director of
CenterPoint from 1995 until the Distribution. Mr. Letbetter resigned as
Chairman, President and Chief Executive Officer of CenterPoint at the time of
the Distribution.
Stephen W. Naeve is our President and Chief Operating Officer. He has served
as Vice Chairman of CenterPoint from June 1999 until the Distribution and as
Chief Financial Officer of CenterPoint from 1997 until the Distribution. From
1997 to 1999, Mr. Naeve held the position of Executive Vice President and Chief
Financial Officer of CenterPoint. Since 1988, he served in various officer
capacities with CenterPoint, including Vice President - Strategic Planning and
Administration between 1993 and 1996. Mr. Naeve resigned as Vice Chairman of
CenterPoint at the time of the Distribution.
Robert W. Harvey is our Executive Vice President and Group President--Retail
Business. Mr. Harvey served as Vice Chairman of CenterPoint from June 1999
until the Distribution. 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 resigned as Vice Chairman of CenterPoint at the time of
the Distribution.
Mark M. Jacobs is our Executive Vice President and Chief Financial Officer.
Mr. Jacobs served as Executive Vice President and Chief Financial Officer of
CenterPoint from July 2002 until the Distribution. From 1989 to 2002, Mr.
Jacobs was employed by Goldman, Sachs & Co. He was a Managing Director in the
firm's Natural Resources Group. Mr. Jacobs resigned as Executive Vice President
and Chief Financial Officer of CenterPoint at the time of the Distribution.
Hugh Rice Kelly is our Senior Vice President, General Counsel and Corporate
Secretary. He served as Executive Vice President, General Counsel and Corporate
Secretary of CenterPoint from 1997 until the Distribution. Between 1984 and
1997, he served as Senior Vice President, General Counsel and Corporate
Secretary of CenterPoint. Mr. Kelly resigned as Executive Vice President,
General Counsel and Corporate Secretary of CenterPoint at the time of the
Distribution.
27
Thomas C. Livengood is our Vice President and Chief Accounting Officer.
Prior to joining us in August 2002, he served as Executive Vice President and
Chief Financial Officer of Carriage Services, Inc., a publicly traded consumer
services company, since 1996. From 1991 to 1996, he served as Vice President
and Chief Financial Officer of Tenneco Energy Company, a division of Tenneco,
Inc.
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 January 2004.
During 2003, we expect to relocate our corporate offices. Upon relocation, our
corporate offices will occupy approximately 520,000 square feet of leased
office space in Houston, Texas. Our new lease expires in 2018, subject to two
five-year 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" 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.
Retail Energy
For information regarding the properties of our retail energy segment, see
"Our Business--Retail Energy" in Item 1 of this Form 10-K.
Wholesale Energy
For information regarding the properties of our wholesale energy segment,
see "Our Business--Wholesale Energy" in Item 1 of this Form 10-K.
European Energy
For information regarding the properties of our European energy segment, see
"Our Business--European Energy" in Item 1 of this Form 10-K.
Other Operations
For information regarding the properties of our other operations segment,
see "Our Business--Other Operations" in Item 1 of this Form 10-K.
ITEM 3. Legal Proceedings.
For a description of certain legal and regulatory proceedings affecting us,
see note 14 to our consolidated financial statements.
ITEM 4. Submission of Matters to a Vote of Security Holders.
No matters were submitted to a vote of our security holders during the
fourth quarter of the fiscal year ended December 31, 2002.
28
PART II
ITEM 5. Market for Our Common Equity and Related Stockholder Matters.
As of March 5, 2003, our common stock was held of record by approximately
63,215 stockholders of record and approximately 132,892 beneficial owners. Our
common stock is listed on the New York Stock Exchange and is traded under the
symbol "RRI." 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) $37.50 $23.65
Third Quarter.............................. $28.60 $14.45
Fourth Quarter............................. $19.85 $13.20
2002
First Quarter.............................. $17.45 $ 9.50
Second Quarter............................. $17.16 $ 7.28
Third Quarter.............................. $ 8.95 $ 1.66
Fourth Quarter............................. $ 3.23 $ 0.99
The closing market price of our common stock on December 31, 2002 was $3.20
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.
For a discussion of our restrictions on payment of dividends, see note 21(a) to
our consolidated financial statements.
During 2001, we purchased 11 million shares of our common stock at an
average price of $17.22 per share, or an aggregate purchase price of $189
million. For additional information, see note 10(b) to our consolidated
financial statements.
On December 6, 2001, our board of directors authorized us to purchase up to
an additional 10 million shares of our common stock through June 2003. For
additional information, see note 10(b) to our consolidated financial statements.
29
ITEM 6. Selected Financial Data.
The following tables present our selected consolidated financial data for
1998 through 2002. The financial data for 1998, 1999 and 2000 are derived from
the consolidated historical financial statements of CenterPoint. 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,
------------------------------------------
1998 1999 2000 2001 2002
(1)(4) (1)(4) (1)(4)(5) (2)(4)(5) (1)(3)(4)
------ ------ --------- --------- ---------
(in millions, except per share amount)
Income Statement Data:
Revenues.......................................................... $277 $657 $3,275 $6,130 $11,248
Trading margins................................................... 33 88 200 369 310
---- ---- ------ ------ -------
Total...................................................... 310 745 3,475 6,499 11,558
---- ---- ------ ------ -------
Expenses:
Fuel and cost of gas sold...................................... 102 317 1,171 1,976 1,443
Purchased power................................................ 13 149 926 2,509 7,381
Accrual for payment to CenterPoint............................. -- -- -- -- 128
Operation and maintenance...................................... 65 136 422 494 903
General, administrative and development........................ 78 100 304 503 665
European energy goodwill impairment............................ -- -- -- -- 482
Depreciation and amortization.................................. 15 29 194 247 436
---- ---- ------ ------ -------
Total...................................................... 273 731 3,017 5,729 11,438
---- ---- ------ ------ -------
Operating income.................................................. 37 14 458 770 120
---- ---- ------ ------ -------
Other income (expense):
Gains (losses) from investments................................ -- 16 (17) 22 (24)
(Loss) income of equity investments of unconsolidated
subsidiaries................................................. (1) 21 43 57 23
Gain on sale of development project............................ -- -- 18 -- --
Other, net..................................................... 1 (6) 6 9 33
Interest expense............................................... (2) (9) (42) (63) (304)
Interest income................................................ 1 -- 18 27 35
Interest income (expense)--affiliated companies, net........... 2 (10) (173) 12 5
---- ---- ------ ------ -------
Total other income (expense)............................... 1 12 (147) 64 (232)
---- ---- ------ ------ -------
Income (loss) before income taxes, cumulative effect of accounting
change and extraordinary item................................... 38 26 311 834 (112)
Income tax expense................................................ (17) (2) (95) (274) (214)
---- ---- ------ ------ -------
Income (loss) before cumulative effect of accounting change and
extraordinary item.............................................. 21 24 216 560 (326)
Cumulative effect of accounting change, net of tax................ -- -- -- 3 (234)
Extraordinary item, net of tax.................................... -- -- 7 -- --
---- ---- ------ ------ -------
Net income (loss)................................................. $ 21 $ 24 $ 223 $ 563 $ (560)
==== ==== ====== ====== =======
Basic and Diluted Earnings per Share:
Income (loss) before cumulative effect of accounting change.... $ 2.02 $ (1.12)
Cumulative effect of accounting change, net of tax............. 0.01 (0.81)
------ -------
Net income (loss).............................................. $ 2.03 $ (1.93)
====== =======
30
Year Ended December 31,
--------------------------------------------------
1998(1) 1999(1) 2000(1)(5) 2001(2)(5) 2002(1)(3)
------- -------- ---------- ---------- ----------
(in millions, except operating data)
Statement of Cash Flow Data:
Cash flows from operating activities............... $ (2) $ 35 $ 328 $ (127) $ 611
Cash flows from investing activities............... (365) (1,406) (3,013) (838) (3,486)
Cash flows from financing activities............... 379 1,408 2,721 1,000 3,981
Other Operating Data:
Trading and marketing activity (6):
Natural gas (Bcf) (7)........................... 1,115 1,481 2,273 3,265 3,449
Power sales (thousand MWh) (7).................. 61,195 128,266 127,062 248,139 378,085
Power generation activity:
Wholesale power sales (thousand MWh) (7)........ 2,973 10,204 39,300 63,298 129,358
European power sales (thousand MWh)............. -- 2,846 11,606 16,344 17,794
Retail power sales (GWh)........................ -- -- -- -- 58,458
Net power generation capacity (MW).............. 3,800 7,945 12,707 14,585 23,384
December 31,
--------------------------------------------------
1998 1999 2000(5) 2001(5) 2002
------- -------- ---------- ---------- ----------
(in millions)
Balance Sheet Data:
Property, plant and equipment, net................. $ 270 $ 2,407 $ 4,049 $ 4,559 $ 8,941
Total assets....................................... 1,409 5,624 13,475 11,719 17,636
Short-term borrowings.............................. -- 170 126 297 1,299
Long-term debt to third parties, including current
maturities....................................... -- 460 892 892 6,196
Accounts and notes (payable) receivable--affiliated
companies, net................................... (17) (1,333) (1,969) 445 --
Stockholders' equity............................... 652 741 2,332 5,984 5,653
- --------
(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: the five generating
facilities in California substantially acquired in April 1998, a generating
facility in Florida and REPGB both acquired in October 1999, the REMA
acquisition that occurred in May 2000 and the Orion Power acquisition that
occurred in February 2002. See note 5 to our consolidated financial
statements for further information about the acquisitions occurring in 2000
and 2002.
(2) Effective January 1, 2001, we adopted SFAS No. 133 which established
accounting and reporting standards for derivative instruments. See note 7
to our consolidated financial statements for further information regarding
the impact of the adoption of SFAS No. 133.
(3) During the third quarter of 2002, we completed the transitional impairment
test for the adoption of SFAS No. 142 on our consolidated financial
statements, including the review of goodwill for impairment as of January
1, 2002. Based on this impairment test, we recorded an impairment of our
European energy segment's goodwill of $234 million, net of tax, as a
cumulative effect of accounting change. Based on our annual impairment test
(November 1, 2002), we recognized an impairment of the remaining amount of
our European energy segment's net goodwill of $482 million in the fourth
quarter of 2002. See note 6 to our consolidated financial statements for
further discussion.
(4) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis in the statements of
consolidated operations. Comparative financial statements for prior periods
have been reclassified to conform to this presentation. See note 2(t) to
our consolidated financial statements for further discussion.
(5) As described in note 1 to our consolidated financial statements, our
consolidated financial statements for 2000 and 2001 have been restated from
amounts previously reported. The restatement had no impact on previously
reported consolidated cash flows.
(6) Excludes financial transactions.
(7) Includes physical contracts not delivered.
31
ITEM 7. Management's Discussion and Analysis of Financial Condition and
Results of Operations.
Restatement
Subsequent to the issuance of our financial statements as of and for the
year ended December 31, 2001, we identified four natural gas financial swap
transactions that should not have been recorded in our records. We have
concluded, based on the offsetting nature of the transactions and manner in
which the transactions were documented, that none of the transactions should
have been given accounting recognition. We previously accounted for these
transactions in our financial statements as a reduction in revenues in December
2000 and an increase in revenues in January 2001, with the effect of decreasing
net income in the fourth quarter of 2000 and increasing net income in the first
quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million
after-tax) and the effect of increasing basic and diluted earnings per share by
$0.05 in the first quarter of 2001. There were no cash flows associated with
the transactions.
Also, subsequent to the issuance of our financial statements for 2001 and
for the first three quarters of 2002, we determined that we had incorrectly
calculated the amount of hedge ineffectiveness for 2001 and the first three
quarters of 2002 for hedging instruments entered into prior to the adoption of
SFAS No. 133. These hedging instruments included long-term forward contracts
for the sale of power in the California market through December 2006. The
amount of hedge ineffectiveness for these forward contracts was calculated
using the trade date. However, the proper date for the hedge ineffectiveness
calculation is hedge inception, which for these contracts was deemed to be
January 1, 2001, concurrent with the adoption of SFAS No. 133. These errors in
accounting for hedge ineffectiveness resulted in an understatement of revenues
of $28.7 million ($18.6 million after-tax) and earnings per share of $0.07 in
2001.
The consolidated financial statements for 2000 and 2001 have been restated
from amounts previously reported to remove the effects of the four natural gas
swap transactions from 2000 and 2001 and to correctly account for the amount of
hedge ineffectiveness in 2001. The following discussion and analysis has been
modified for the restatement. A summary of the principal effects of the
restatement on our consolidated financial statements for 2000 and 2001 are set
forth in note 1 to our consolidated financial statements.
Overview
We provide electricity and energy services with a focus on the competitive
retail and wholesale segments of the electric power industry in the United
States. We have built a portfolio of electric power generation facilities,
through a combination of acquisitions and development that are not subject to
traditional cost-based regulation; therefore, we can generally sell electricity
at prices determined by the market, subject to regulatory limitations. We trade
and market electricity, natural gas, natural gas transportation capacity and
other energy-related commodities. We also optimize our physical assets and
provide risk management services for our asset portfolio. In March 2003, we
decided to exit our proprietary trading activities and liquidate, to the extent
practicable, our proprietary positions. Although we are exiting the proprietary
trading business, we have existing positions, which will be closed as
economically feasible or in accordance with their terms. We will continue to
engage in hedging activities related to our electric generating facilities,
pipeline storage positions and fuel positions.
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. We also
discuss liquidity and capital resources. Our segments include retail energy,
wholesale energy, European energy and other operations. For segment reporting
information, see note 20 to our consolidated financial statements.
In February 2002, we acquired all of the outstanding shares of common stock
of Orion Power for an aggregate purchase price of $2.9 billion and we assumed
$2.4 billion in debt obligations. For additional information regarding our
acquisition of Orion Power, see note 5(a) to our consolidated financial
statements.
32
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 of $1.7
billion. Pursuant to a master separation agreement between CenterPoint and
Reliant Resources, we used $147 million of the net proceeds to repay certain
indebtedness owed to CenterPoint. On September 30, 2002, the Distribution was
completed. The Distribution completed our separation from CenterPoint. In
connection with our anticipated separation from CenterPoint, CenterPoint
contributed to us effective December 31, 2000, our wholesale, retail and other
operations. Through December 31, 2000, CenterPoint and its direct and indirect
subsidiaries conducted these operations. For additional information regarding
this contribution from CenterPoint and agreements with CenterPoint entered into
as a part of CenterPoint's business separation plan, see notes 3 and 4 to our
consolidated financial statements.
The financial information for the year ended December 31, 2000 discussed in
this Item 7 is derived from the consolidated historical financial statements of
CenterPoint, which include the results of operations for all of CenterPoint's
businesses, including those businesses which we do not own. Therefore, in order
to prepare our financial statements for 2000, contained in this Form 10-K and
discussed in this Item 7, we carved out the results of operations of the
businesses that we own from CenterPoint's consolidated historical financial
statements. Accordingly, the results of operations discussed in this Item 7 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 CenterPoint 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
CenterPoint. We may experience changes in our cost structure, funding and
operations as a result of our separation from CenterPoint, including increased
costs associated with reduced economies of scale, and increased costs
associated with being a publicly traded, independent company. We cannot
predict, with any certainty, the actual amount of increased costs we may incur,
if any.
During 2002, the following factors, among others, negatively impacted our
business:
. weaker pricing for electric energy, capacity and ancillary services;
. narrowing of the spark spread in most regions of the United States in
which we operate generation facilities;
. market contraction;
. reduced liquidity in the United States and Northwest Europe power
markets; and
. downgrades in our credit ratings to below investment grade by each of the
major rating agencies.
We expect these weak conditions to persist through 2003. However, in the
next few years we anticipate that supply surpluses will begin to tighten,
regulatory intervention will become more balanced and as a result prices will
improve for electric energy, capacity and ancillary services. This view is
consistent with our fundamental belief that long run market prices must reach
levels sufficient to support an adequate rate of return on the construction of
new generation. However, if in the long term the current weak environment
persists, we could have significant impairments of our property, plant and
equipment and goodwill which, in turn, could have a material adverse effect on
our results of operations.
In addition, our operations are impacted by changes in commodities other
than electric energy, in particular by changes in natural gas prices. During
the first quarter of 2003, there was significant volatility in the natural gas
market. As a result, we realized a trading loss related to certain of our
natural gas trading positions of approximately $80 million pre-tax in the first
quarter of 2003. Our wholesale energy segment's results from its unhedged
coal-fired generation capacity in the Mid-Atlantic region are impacted by
natural gas prices as electric energy prices are affected by changes in natural
gas prices and coal prices are substantially uncorrelated to gas prices. In
addition, we can optimize the fuel costs of our dual fuel generating assets by
running the most cost-efficient fuel. Our retail energy segment can also be
impacted by changes in natural gas prices. The PUCT's regulations allow an
affiliated retail electric provider to adjust the wholesale energy supply cost
component or
33
"fuel factor," included in its price to beat based on a percentage change in
the forward price of natural gas. An affiliated retail electric provider may
request that its price to beat fuel factor be adjusted twice a year. We cannot
estimate with any certainty the magnitude and timing of future adjustments
required, if any, or the impact of such adjustments on our headroom. For
additional information regarding adjustments to our price to beat fuel factor,
see "Management's Discussion and Analysis of Financial Condition and Results of
Operations --EBIT by Business Segment." To the extent there are future changes
in natural gas prices, our results of operations, financial condition and cash
flows will be affected.
In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon, a Netherlands-based electricity distributor. We
recognized a loss of approximately $0.4 billion in the first quarter of 2003 in
connection with the anticipated sale. We do not anticipate that there will be a
Dutch or United States income tax benefit realized by us as a result of this
loss. We will recognize contingent payments, if any, in earnings upon receipt.
In the first quarter of 2003, we began to report the results of our European
energy operations as discontinued operations in accordance with SFAS No. 144.
For further discussion of the sale, see note 21(b) to our consolidated
financial statements.
Consolidated Results of Operations
The following table provides summary data regarding our consolidated results
of operations for 2000, 2001 and 2002:
Year Ended December 31,
----------------------
2000 2001 2002
------ ------ -------
(in millions)
Operating revenues (1)....................................................... $3,475 $6,499 $11,558
Operating expenses........................................................... 3,017 5,729 11,438
------ ------ -------
Operating income............................................................. 458 770 120
Other (expense) income, net.................................................. (147) 64 (232)
Income tax expense........................................................... 95 274 214
------ ------ -------
Income (loss) before cumulative effect of accounting change and extraordinary
gain....................................................................... 216 560 (326)
Cumulative effect of accounting change, net of tax........................... -- 3 (234)
Extraordinary gain........................................................... 7 -- --
------ ------ -------
Net income (loss)............................................................ $ 223 $ 563 $ (560)
====== ====== =======
- --------
(1) Operating revenues reflect trading activities on a net basis as described
in note 2(d) to our consolidated financial statements.
2002 Compared to 2001
Net Income. We reported a $(560) million consolidated net loss, or $(1.93)
loss per share, for 2002 compared to $563 million in consolidated net income,
or $2.03 earnings per diluted share, for 2001. The 2001 results included a
cumulative effect of accounting change of $3 million, net of tax, related to
the adoption of SFAS No. 133. For additional discussion of the adoption of SFAS
No. 133, see note 7 to our consolidated financial statements. The 2002 results
included a cumulative effect of accounting change of $(234) million, net of
tax, related to the adoption of SFAS No. 142. For additional discussion of the
adoption of SFAS No. 142, see note 6 to our consolidated financial statements.
Our consolidated (loss) income, before cumulative effect of accounting change,
was $(326) million for 2002 compared to $560 million for 2001. The $886 million
decrease was primarily due to the following:
. a $848 million decrease in EBIT from our wholesale energy segment;
. a $469 million decrease in EBIT from our European energy segment which
includes a $482 million goodwill impairment recorded in the fourth
quarter of 2002;
34
. a $240 million increase in net interest expense, including interest
related to advances to affiliated companies;
. a total of $32 million pre-tax impairment losses ($30 million after-tax)
on venture capital investments in 2002 coupled with a $14 million
decrease in gains on investments from $23 million in 2001 to $9 million
in 2002 of our other operations segment; and
. changes in our effective tax rate, which are further discussed below.
The above items were partially offset by:
. a $533 million increase in EBIT from our retail energy segment;
. $54 million in pre-tax disposal charges and impairments of goodwill and
fixed assets related to exiting our communications business recorded in
2001 by our other operations segment; and
. a $53 million decrease in charges incurred relating to the redesign and
settlement of some of CenterPoint's benefit plans related to our
separation from CenterPoint.
EBIT. For an explanation of changes in EBIT, see "--EBIT by Business
Segment."
Interest Expense. We incurred $264 million of net interest expense in 2002
compared to $24 million for 2001. The $240 million increase in net interest
expense in 2002 as compared to 2001 resulted primarily from a $241 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 the acquisition of Orion Power in February 2002 and to a lesser
extent, an increase in interest rates due to downgrades in our credit ratings.
The decrease of $7 million in interest income on net advances to affiliated
companies in 2002 as compared to 2001 resulted primarily from decreased net
advances of excess cash to a subsidiary of CenterPoint during 2002. This was
partially offset by interest expense incurred prior to the conversion into
equity of $1.7 billion of debt owed to CenterPoint and its subsidiaries in
connection with the completion of our IPO in 2001.
Income Tax Expense. Our deferred income taxes are calculated using the
liability method of accounting, which measures deferred income taxes for all
significant income tax temporary differences. Prior to the Distribution, we
calculated our income tax provision on a separate return basis under a tax
sharing agreement with CenterPoint. Our current federal and some state income
taxes were payable to or receivable from CenterPoint prior to the Distribution.
During 2001, our effective tax rate was 32.9%. During 2002, our effective tax
rate was not meaningful as we had a $112 million pre-tax loss and $214 million
in income tax expense. Our reconciling items from the federal statutory rate of
35% to the effective tax rate totaled $253 million and $18 million for 2002 and
2001, respectively. The change in the reconciling items from 2002 to 2001
primarily related to the following:
. a $482 million goodwill impairment related to our European energy segment
which is not deductible for tax purposes;
. a $45 million United States federal tax provision for future cash
distributions from our equity investment in NEA in which our European
energy segment holds a 22.5% economic interest (see note 13 to our
consolidated financial statements);
. an increase in valuation allowances primarily due to losses incurred by
our European energy trading and origination operations in 2002 and the
impairment of certain venture capital investments in 2002;
. an increase in state income taxes primarily resulting from our retail
energy segment's operations in 2002 and the impact of the Orion Power
acquisition in February 2002, partially offset by New York state income
tax credits; and
. the end of the Dutch tax holiday in January 2002 related to the Dutch
electricity sector.
35
The above items were partially offset by the impact of the cessation of
goodwill amortization in 2002 (see note 6 to our consolidated financial
statements).
In 2001, the earnings of REPGB were subject to a zero percent Dutch
corporate income tax rate as a result of the tax holiday related to the Dutch
electricity industry. In 2002, European energy's earnings in the Netherlands
are subject to the standard Dutch corporate income tax rate, which is currently
34.5%.
Subsequent to the Distribution, we ceased being a member of the CenterPoint
consolidated tax group. This separation could have future income tax
implications for us. Our separation from the CenterPoint consolidated tax group
changed 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 CenterPoint 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
CenterPoint consolidated tax group subject to CenterPoint's consent and any
existing statutory carryback limitations. CenterPoint has agreed not to
unreasonably withhold such consent.
2001 Compared to 2000
Net Income. We reported $563 million of consolidated net income, or $2.03
earnings per share, for 2001 compared to $223 million for 2000. The 2001
results included a cumulative effect of accounting change of $3 million, net of
tax, related to the adoption of SFAS No. 133. 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,
see note 9(c) to our consolidated financial statements. Our consolidated income
before cumulative effect of accounting change and extraordinary item was $560
million for 2001 compared to $216 million for 2000. The increase of $344
million was primarily due to the following:
. a $344 million increase in EBIT from our wholesale energy segment;
. a $173 million decrease in net interest expense primarily related to debt
with affiliated companies;
. a $57 million decrease in loss before interest and taxes from our retail
energy segment;
. a $27 million pre-tax impairment loss on marketable equity securities
classified as "available-for-sale" in 2000 coupled with an increase in
gains on investments from $1 million in 2000 to $23 million in 2001 of
our other operations segment; and
. a $24 million increase in EBIT from our European energy segment;
The above items were partially offset by the following:
. a $100 million pre-tax, non-cash charge relating to the redesign of some
of CenterPoint's benefit plans in anticipation of our separation from
CenterPoint;
. $54 million in pre-tax disposal charges and impairments of goodwill and
fixed assets related to the exiting of our communications business in
2001; and
. an increase in our effective tax rate, as further discussed below.
EBIT. For an explanation of changes in EBIT, see "--EBIT by Business
Segment."
Interest Expense. We incurred $24 million of net interest expense during
2001 compared to $197 million in 2000. The $173 million decrease in net
interest expense in 2001 as compared to 2000 resulted primarily from the
following:
. the conversion into equity of $1.7 billion of debt owed to CenterPoint
and its subsidiaries in connection with the completion of our IPO in May
2001;
36
. the $1.0 billion repayment in August 2000 of debt owed to CenterPoint
related to our acquisition of REMA, which is included in our Mid-Atlantic
region operations, from proceeds received from the generating facilities'
sale-leaseback transactions; and
. the advancing of excess cash primarily resulting from our IPO to a
subsidiary of CenterPoint.
These decreases were slightly 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.
Income Tax Expense. During 2001 and 2000, our effective tax rate was 32.9%
and 30.8%, 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.
EBIT by Business Segment
The following tables present operating income (loss) and EBIT for each of
our business segments for the years ended December 31, 2000, 2001 and 2002.
EBIT is the primary measure we use to evaluate the performance of our business
segments. We believe EBIT is a good indicator of each business segment's
operating performance. EBIT is not defined under GAAP, should not be considered
in isolation or as a substitute for a measure of performance prepared in
accordance with GAAP and is not indicative of operating income from operations
as determined under GAAP. Additionally, our computation of EBIT may not be
comparable to other similarly titled measures computed by other companies,
because all companies do not calculate it in the same fashion. For a
reconciliation of our operating income (loss) to EBIT and EBIT to net income
(loss), see note 20 to our consolidated financial statements. For a
reconciliation of our operating income (loss) to EBIT by segment, see the
related discussion by segment below.
The following table sets forth our operating income (loss) by segment for
2000, 2001 and 2002:
Year Ended December 31,
----------------------
2000 2001 2002
---- ----- -----
(in millions)
Retail energy.... $(70) $ (13) $ 524
Wholesale energy. 505 907 24
European energy.. 84 56 (371)
Other operations. (61) (180) (57)
---- ----- -----
Total..... $458 $ 770 $ 120
==== ===== =====
The following table sets forth our EBIT by segment for 2000, 2001, 2002:
Year Ended December 31,
----------------------
2000 2001 2002
---- ----- -----
(in millions)
Retail energy.... $(70) $ (13) $ 520
Wholesale energy. 572 916 68
European energy.. 89 113 (356)
Other operations. (83) (158) (80)
---- ----- -----
Total..... $508 $ 858 $ 152
==== ===== =====
37
Retail Energy
Our retail energy segment provides electricity products and services to
end-use customers, ranging from residential and small commercial customers to
large commercial, industrial and institutional customers. Our retail energy
segment acquires and manages the electric energy, capacity and ancillary
services associated with supplying these retail customers. We began serving
approximately 1.7 million electric customers in the Houston metropolitan area
when the Texas market opened to full competition in January 2002. At the end of
2002, our customer count remained substantially the same; however, we lost
market share in the Houston market and added customers in other areas of Texas.
During 2002, our retail energy segments' operational efforts were largely
focused on the extensive efforts necessary to transition customers from the
electric utilities to the affiliated retail electric providers. We participated
in preliminary marketing programs in mid-2001 to gain customers outside of the
Houston metropolitan area, primarily in the Dallas/Fort Worth area. In
addition, this segment manages the procurement of electricity supply for these
customers. For further information regarding our contract to purchase supply
from Texas Genco, see note 4(b) to our consolidated financial statements.
We record our electricity sales and services to residential, small
commercial and large commercial, industrial and institutional customers who
have not signed a contract under the accrual method and these revenues
generally are recognized upon delivery. Contracted electricity sales to large
commercial, industrial and institutional customers were accounted for under the
mark-to-market method of accounting and presented net for contracts entered
into prior to October 25, 2002. Effective January 1, 2003, we will no longer
mark to market in earnings a substantial portion of these contracts and the
related energy supply contracts. Contracted sales by our retail energy segment
to large commercial, industrial and institutional customers and the related
supply contracts entered into after October 25, 2002, will, for the most part,
no longer be marked to market through earnings, in connection with the
implementation of EITF No. 02-03 which rescinded EITF No. 98-10. The earnings
from these contracts will generally be recognized as the related volumes are
delivered. Historically, these energy contracts were recorded at fair value in
trading margins upon contract execution. The net changes in their market values
were recognized in the statement of consolidated operations in trading margins
in the period of the change.
Electricity sales and services related to retail customers not billed are
recognized based upon estimated electricity and services delivered. At December
31, 2002, the amount not billed is $216 million, including approximately $25
million related to delayed billings. Problems or delays in the flow of
information between the ERCOT ISO, the transmission and distribution utility
and the retail electric providers and operational problems with our new systems
and processes could impact our ability to accurately estimate the amount not
billed at December 31, 2002. In addition, for certain customers that did not
receive an electric bill, we cannot bill or collect for a period beyond six
months from when an error is discovered except in the instance of theft. As of
December 31, 2002, the amount of electricity that could not be billed did not
have a significant impact on our results of operations or cash flows.
We depend on the transmission and distribution utilities to read our
customers' electric meters. We are required to rely on the transmission and
distribution utility or, in some cases, the ERCOT ISO, to provide us with our
customers' information regarding electricity usage, such as historical usage
patterns, 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 transmission and distribution utilities or the ERCOT
ISO could have a material negative impact on our business, results of
operations and cash flows.
We record our transmission and distribution charges using the same method
detailed above for our electricity sales and services to retail customers. At
December 31, 2002, the transmission and distribution charges not billed by the
transmission and distribution utilities to us totaled $59 million. Delays or
inaccurate billings from the transmission and distribution utilities could
impact our ability to accurately reflect our transmission and distribution
costs.
The ERCOT ISO is responsible for maintaining reliable operations of the
electric power supply system in the ERCOT Region. The ERCOT ISO is also
responsible for handling scheduling and settlement for all
38
electricity volumes in the Texas deregulated electricity market. As part of
settlement, the ERCOT ISO communicates the actual volumes compared to the
scheduled volumes. The ERCOT ISO calculates an additional charge or credit
based on the difference between the actual and scheduled volumes, based on a
market-clearing price. Settlement charges also include allocated costs such as
unaccounted for energy. Preliminary settlement information is due from the
ERCOT ISO within two months after electricity is delivered. Final settlement
information is due from the ERCOT ISO within twelve months after electricity is
delivered. As a result, we record our estimated supply costs using estimated
supply volumes and adjust those costs upon receipt of settlement and
consumption information. The ERCOT ISO settlement process was delayed due to
operational problems between the ERCOT ISO, the transmission and distribution
utilities and the retail electric providers. During the third quarter of 2002,
the ERCOT ISO began issuing final settlements for the pilot time period of July
31, 2001 to December 31, 2001. The final settlements have been suspended until
a market synchronization of all customers between the market participants takes
place. The market synchronization will validate which retail electric provider
served each customer, for each day, beginning as of January 1, 2002, which was
the date the market opened to retail competition. This information will be
confirmed by the ERCOT ISO, the retail electric providers and the transmission
and distribution utilities. Once this market synchronization is complete, the
ERCOT ISO will resume the final settlement process beginning with January 1,
2002. The delay in the ERCOT ISO settlement process could impact our ability to
accurately reflect our energy supply costs.
We believe that the estimates and assumptions utilized for the above items
to recognize revenues and supply costs, as applicable, are reasonable and
represent our best estimates. However, actual results could differ from those
estimates.
We also provided billing, customer service, credit and collection and
remittance services to CenterPoint's regulated electric utility and two of its
natural gas distribution divisions. The service agreement governing these
services terminated on December 31, 2001. We charged the regulated electric and
natural gas utilities for these services at cost.
We expect to continue to lose residential and small commercial market share
in the Houston market during 2003, as competition increases. We expect to gain
residential and small commercial market share in other areas of the state. The
efforts to seek such gains will require us to increase our spending for
marketing and advertising. We expect to continue to increase our market share
of large commercial, industrial and institutional customers in the ERCOT
Region. We also expect to see a reduction in margin attributable to certain
large commercial, industrial and institutional customers who have not signed
contracts, as these customers sign contracts with us or other competitors at
more favorable rates. When the market opened to competition, large commercial,
industrial and institutional customers who did not sign contracts were assigned
to be served by the affiliated residential electric provider at a designated
rate. This designated rate may be higher than the rate available in the
competitive market.
During 2002, we filed two requests with the PUCT to increase the price to
beat fuel factor for residential and small commercial customers based on
increases in the price of natural gas. The August 2002 increase was based on an
increase in the natural gas price from $3.11 per MMbtu to $3.73 per MMbtu. The
December 2002 increase was based on a natural gas price of $4.02 per MMbtu. In
March 2003, the PUCT approved our request to increase the price to beat fuel
factor for residential and small commercial customers based on a 23.4% increase
in the price of natural gas from our previous increase in December 2002. The
approved increase was based on natural gas prices of $4.956 per MMbtu. The
increase represents an 8.2% increase in the total bill of a residential
customer using, on average, 12,000 KWh per year. For additional information
regarding the price to beat fuel factor, see notes 14(e) and 21(d) to our
consolidated financial statements.
For additional information regarding factors that may affect the future
results of operations of our retail energy segment, see "--Risk Factors--Risk
Related to Our Retail Energy Operations."
39
The following table provides summary data, including EBIT, of our retail
energy segment for 2000, 2001 and 2002:
Retail Energy Segment
----------------------
Year Ended December 31,
----------------------
2000 2001 2002
---- ---- -------
(in millions, except
operating data)
Retail electricity sales and services revenues............................... $ 64 $114 $ 3,017
Supply management revenues................................................... -- -- 1,184
Contracted commercial, industrial and institutional margins (trading margins) -- 74 152
---- ---- -------
Total operating revenues.............................................. 64 188 4,353
Operating expenses:
Purchased power........................................................... -- 4 3,225
Accrual for payment to CenterPoint........................................ -- -- 128
Operation and maintenance................................................. 101 110 204
General and administrative................................................ 29 76 246
Depreciation and amortization............................................. 4 11 26
---- ---- -------
Total operating expenses.............................................. 134 201 3,829
---- ---- -------
Operating (loss) income...................................................... (70) (13) 524
---- ---- -------
Other loss, net.............................................................. -- -- (4)
---- ---- -------
(Loss) earnings before interest and income taxes............................. $(70) $(13) $ 520
==== ==== =======
Margins:
Retail electricity sales and services margins............................. $ 64 $110 $ 976
Contracted commercial, industrial and institutional margins (trading
margins)................................................................ -- 74 152
---- ---- -------
Total................................................................. $ 64 $184 $ 1,128
==== ==== =======
Operations Data:
Energy sales (GWh):
Residential.......................................................................... 20,932
Small commercial..................................................................... 12,708
Large commercial, industrial and institutional....................................... 24,818
-------
Total........................................................................ 58,458
=======
Customers as of December 31, 2002 (in thousands, metered locations):
Residential.......................................................................... 1,478
Small commercial..................................................................... 214
Large commercial, industrial and institutional....................................... 24
-------
Total........................................................................ 1,716
=======
2002 Compared to 2001
EBIT. Our retail energy segment's EBIT increased $533 million for 2002
compared to 2001. The increase in EBIT was primarily due to increased margins
(revenues less purchased power) related to retail electric sales to
residential, small commercial and large commercial, industrial and
institutional customers resulting from full competition, which began on January
1, 2002. The increase in margins was partially offset by increased operating
expenses as further discussed below.
Operating revenues. Retail electricity sales and services revenues
increased $2.9 billion in 2002 compared to 2001 primarily due to retail
electric sales in the Texas retail market to residential and small commercial
40
customers and to the large commercial, industrial and institutional customers
in the Houston area that did not sign contracts. Supply management revenues
related to the hedging, managing and optimizing of our electric energy supply
contributed approximately $1.2 billion of the increase in revenues for 2002.
In addition, $53 million of revenues for 2001 were recorded for billing,
customer service, credit and collection and remittance services charged to
CenterPoint's regulated electric utility and two of its natural gas
distribution divisions. The associated costs are included in operation and
maintenance expenses and general and administrative expenses. The retail energy
segment charged the regulated electric and gas utilities for the services
provided to these utilities at our cost. The service agreement governing these
services terminated on December 31, 2001.
Purchased power. Purchased power expense increased $3.2 billion for 2002
due to costs associated with retail electric sales and supply management
activity.
Margins. Our retail energy segment's margins increased $944 million for
2002 compared to 2001 due to the opening of the Texas market to full
competition in January 2002, as discussed above. During 2002, the retail energy
segment recognized $152 million of margins related to commercial, industrial
and institutional electricity contracts, including $6 million of unrealized
losses, compared to $74 million of margins related to commercial, industrial
and institutional electricity contracts, including $73 million of unrealized
gains, in 2001. For information regarding the accounting for contracted
electricity sales to large commercial, industrial and institutional customers,
see notes 2(d) and 2(t) to our consolidated financial statements.
Accrual for payment to CenterPoint. To the extent that our price to beat
for electric service to residential and small commercial customers in
CenterPoint's Houston service territory during 2002 and 2003 exceeds the market
price of electricity, we may be required to make a payment to CenterPoint in
2004. As of December 31, 2002, our estimate for the payment related to
residential customers is between $160 million and $190 million, with a most
probable estimate of $175 million. For additional information regarding this
payment, see note 14(e) to our consolidated financial statements.
Operation and maintenance and general and administrative. Operation and
maintenance expenses and general and administrative expenses increased $264
million in 2002 as compared to 2001 primarily due to the following:
. a $59 million increase in gross receipts taxes related to increased
retail electric sales;
. a $152 million increase in employee related costs and other
administrative costs (including allocated corporate overhead), primarily
due to the Texas retail market opening to full competition in January
2002;
. a $77 million increase in bad debt expense associated with the start-up
of the retail electric market and regulations which, until September
2002, did not allow us to disconnect customers for non-payment of their
electric bills;
. a $23 million increase in marketing costs primarily due to the Texas
retail market opening to full competition; and
. a $3 million increase in rent expense as a result of additional staffing.
These increases were partially offset by a decrease of $53 million for
billing, customer service, credit and collection and remittance costs, which
were charged to CenterPoint's regulated electric utility and two of its natural
gas distribution divisions, as discussed above.
Depreciation and amortization. Depreciation and amortization expense
increased $15 million in 2002 as compared to 2001 primarily due to depreciation
of $17 million related to the information systems developed and placed in
service to meet the needs of our retail businesses, offset by lower
amortization expense of $2 million.
41
Retail energy recorded $2 million in 2001 for amortization expense related to
goodwill. For information regarding the cessation of goodwill amortization, see
note 6 to our consolidated financial statements.
2001 Compared to 2000
EBIT. Our retail energy segment's EBIT loss decreased by $57 million for
2001 compared to 2000. The loss reduction was primarily due to contracts for
energy and energy services to large commercial, industrial and institutional
customers in 2001, 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 were accounted for under the mark-to-market method of
accounting. These energy contracts were recorded at fair value in revenue upon
contract execution. The net changes in their market values were 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. Operating revenues increased by $124 million for 2001
compared to 2000 largely due to increased margins from sales of electricity
products and services to large commercial, industrial and institutional
customers, as well as increased revenues for the billing and remittance
services provided to CenterPoint.
Purchased power. Purchased power expense increased by $4 million in 2001
primarily due to costs related to the Texas retail pilot program during the
last half of 2001.
Margins. Margins increased $120 million for 2001 compared to 2000 due to
the various factors discussed above.
Operation and maintenance and general and administrative. Operation and
maintenance costs increased by $9 million and general and administrative
expenses increased $47 million in 2001 as compared to 2000, primarily due to
$35 million in 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 and $31 million in increased costs incurred in
performing billing, customer service, credit and collections and remittance
service for CenterPoint.
Wholesale Energy
Our wholesale energy segment includes our non-regulated power generation
operations in the United States, which includes acquisition and development of
generation facilities, and our wholesale energy trading, marketing, origination
and risk management operations in North America. The wholesale energy segment's
commercial activities include purchasing fuel to supply existing generation
assets, selling electricity and related services produced by these assets,
dispatching of the generation portfolios, scheduling of power and natural gas
and managing the day-to-day trading and marketing activities.
As of December 31, 2002, we owned or leased electric power generation
facilities with an aggregate net operating generating capacity of 19,888 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, 2002, we had 2,461
MW (2,658 MW, net of 197 MW to be retired upon completion of one facility) of
additional net generating capacity under construction, including facilities
having 1,920 MW (2,117 MW, net of 197 MW to be retired upon completion of one
facility) that are being constructed by off-balance sheet special purpose
entities under construction agency agreements. We expect these facilities to
achieve commercial operation in late 2003 or 2004. Effective January 1, 2003,
upon adoption of FIN No. 46, we consolidated these special purposes entities,
see notes 2(t), 14(b) and 21(a) to our consolidated financial statements.
42
On May 12, 2000, we purchased entities owning electric power generating
assets and development sites located in the PJM Market having an aggregate net
generating capacity of approximately 4,262 MW at the acquisition date. For
additional information regarding this acquisition of our Mid-Atlantic
generating assets, including the accounting treatment of this acquisition, see
note 5(b) to our consolidated financial statements.
In February 2002, we acquired all of the outstanding shares of common stock
of Orion Power for $2.9 billion and assumed debt obligations of $2.4 billion.
Orion Power is an independent electric power generating company with 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 2002, Orion Power had
81 generating facilities in operation with a total generating capacity of 5,644
MW and two projects under construction with a total generating capacity of 804
MW, which were completed in the second quarter of 2002.
Given the downturn in the industry and downgrades of our credit ratings, in
the first half of 2002 we reviewed our trading, marketing, power origination
and risk management services strategies and activities. By the third quarter of
2002, we began decreasing the level of these commercial activities in order to
significantly reduce collateral usage and focus on the highest return
transactions, which are primarily derived from our physical asset positions. In
response to declining prices for electric energy, capacity and ancillary
services across much of the United States, we also significantly reduced
development activities beginning in the second quarter of 2002. Development is
now limited only to the completion of projects already under construction. The
restructuring of all of our associated commercial, development and support
groups resulted in $17 million of severance costs in 2002.
As a result of these restructurings, general and administrative costs are
expected to be lower than 2002 levels in the near term.
Starting in late December 2002, our financial gas trading desk carried a
spread position, which involved a short position for March 2003 natural gas
deliveries and a long position for April 2003 natural gas deliveries. The
position was within our authorized value at risk and positional limits.
However, there was significant and unanticipated volatility in the natural gas
market over a few days in February 2003. As a result, we realized a trading
loss of approximately $80 million pre-tax in the first quarter of 2003 related
to these positions. These positions have been closed.
In March 2003, we decided to exit our proprietary trading activities and
liquidate, to the extent practicable, our proprietary positions. Although we
are exiting the proprietary trading business, we have existing positions, which
will be closed as economically feasible or in accordance with their terms. We
will engage in hedging activities related to our electric generating
facilities, pipeline storage positions and fuel positions.
During 2002, the following factors negatively impacted our wholesale energy
segment:
. weaker pricing for electric energy, capacity and ancillary services, as a
result of increased capacity brought into the markets and more active
regulatory intervention designed to constrain prices in many regions,
especially in the western United States;
. a narrowing of the spark spread;
. the effects of market participant contraction;
. reduced liquidity in the United States power markets; and
. our lower credit ratings.
We expect these weak conditions to persist through 2003. However, over the
next few years, we anticipate that supply surpluses will begin to tighten,
regulatory intervention will become more balanced and as a result, prices for
electric energy, capacity and ancillary services will improve.
43
SFAS No.142 requires goodwill to be tested annually and between annual tests
if events occur or circumstances change that would more likely than not reduce
the fair value of a reporting unit below its carrying amount. We have elected
to perform our annual test for indications of goodwill impairment as of
November 1, in conjunction with our annual planning process. Based on our
annual impairment test, there was no impairment of our wholesale energy
segment's goodwill. Our impairment analysis includes numerous assumptions,
including but not limited to:
. increases in demand for power that will result in the tightening of
supply surpluses and additional capacity requirements over the next three
to eight years, depending on the region;
. improving prices in electric energy, ancillary services and existing
capacity markets as the power supply surplus is absorbed; and
. our expectation that more balanced, fair market rules will be
implemented, which provide for the efficient operations of unregulated
power markets, including capacity markets or mechanisms in regions where
they currently do not exist.
These assumptions are consistent with our fundamental belief that long run
market prices must reach levels sufficient to support an adequate rate of
return on the construction of new power generation. However, if in the long
term the current weak environment persists, our wholesale energy segment could
have significant impairments of its property and equipment and goodwill. As of
December 31, 2002, the wholesale energy segment has $1.5 billion of goodwill.
It is likely that, in order to exercise the Texas Genco option as permitted
under our credit facilities, we may sell some of our assets. We have identified
certain non-strategic domestic generating assets for potential sale. To date,
we have not reached an agreement to dispose of any significant assets of our
wholesale energy segment nor have we included or assumed any proceeds from
asset sales in our current liquidity plan. Due to unfavorable market conditions
in the wholesale power markets, there can be no assurance that we will be
successful in disposing of domestic generating assets at reasonable prices or
on a timely basis. Specific plans to dispose of assets could result in
impairment losses in property, plant and equipment.
In December 2002, we evaluated the Liberty station and the related tolling
agreement for impairment. There were no impairments based on our analyses.
However, in the future we could incur a pre-tax loss of an amount up to our
recorded net book value. For information regarding issues and contingencies
related to our Liberty power generation station and the related tolling
agreement, see note 14(l) to our consolidated financial statements.
For additional information regarding factors that may affect the future
results of operations of our wholesale energy segment, see "--Risk
Factors--Risk Related to Our Wholesale Energy Operations."
44
The following table provides summary data, including EBIT, of our wholesale
energy segment for 2000, 2001 and 2002:
Wholesale Energy Segment
------------------------------------
Year Ended December 31,
------------------------------------
2000 2001 2002
-------- -------- --------
(in millions, except operating data)
Revenues...................................................... $ 2,661 $ 5,382 $ 6,433
Trading margins............................................... 198 304 137
-------- -------- --------
Total operating revenues............................... 2,859 5,686 6,570
Operating expenses:........................................
Fuel and cost of gas sold.................................. 911 1,576 1,086
Purchased power............................................ 926 2,494 4,196
Operation and maintenance.................................. 225 332 579
General, administrative and development.................... 184 259 348
Depreciation and amortization.............................. 108 118 337
-------- -------- --------
Total operating expenses............................... 2,354 4,779 6,546
-------- -------- --------
Operating income.............................................. 505 907 24
Other income:
Income of equity investment of unconsolidated subsidiaries. 43 6 18
Other, net................................................. 24 3 26
-------- -------- --------
Earnings before interest and income taxes.................. $ 572 $ 916 $ 68
======== ======== ========
Margins:
Power generation (1)....................................... $ 824 $ 1,312 $ 1,151
Trading.................................................... 198 304 137
-------- -------- --------
Total.................................................. $ 1,022 $ 1,616 $ 1,288
======== ======== ========
Operations Data (2):
Wholesale power generation sales volumes (in thousand MWh). 39,300 63,298 129,358
Trading power sales volumes (in thousand MWh).............. 125,971 222,907 306,425
Trading natural gas sales volumes (Bcf).................... 2,273 3,265 3,449
- --------
(1) Revenues less fuel and cost of gas sold and purchased power.
(2) Includes physically delivered volumes, physical transactions that are
settled prior to delivery and hedge activity related to our power
generation portfolio.
2002 Compared to 2001
EBIT. The wholesale energy segment's EBIT decreased by $848 million in 2002
compared to 2001. The decline in EBIT is primarily due to the following:
. decreases in our margins from our power generation operations;
. decreases in trading margins; and
. increases in general and administrative expenses.
The decline in EBIT was partially offset by the effect of the acquisition of
Orion Power, which closed in February 2002. During 2002, the Orion Power assets
contributed $611 million to margins and $222 million to EBIT.
One of the more significant impacts to our wholesale energy segment's EBIT
was caused by the FERC staff interpretations of a May 15, 2002 FERC order
revising the methodology for calculating refunds of California
45
energy sales and a March 26, 2003 FERC order on proposed findings on refund
liability. During 2002, we recorded a reserve of $176 million for potential
refunds, which may be owed by us, which excludes the settlement of $14 million
reached with the FERC in January 2003 relating to two days of trading in 2000
(see note 14(i) to our consolidated financial statements). Our
inception-to-date reserve for such refunds totals $191 million as of December
31, 2002, excluding the $14 million refund related to the FERC settlement. We
estimate the range of our refund obligations for California energy sales to be
approximately $191 million to $240 million (excluding the $14 million refund
related to the FERC settlement in January 2003). Wholesale energy's EBIT was
also impacted by changes to the credit reserve for California receivable
balances. The changes in the credit reserves resulted from the FERC refunds
described above, collections during the period as well as a determination that
credit risk had been reduced on certain outstanding receivables following
payments made by one creditor to the California Power Exchange. Accordingly,
the credit reserve was reduced by $62 million during 2002. The credit reserve
increased by $29 million in 2001. For information regarding the reserves
against receivables, the FERC refund methodology and uncertainties in the
California wholesale energy market, see notes 14(h) and 14(i) to our
consolidated financial statements.
Revenues. Our wholesale energy segment's revenues increased by $1.1 billion
or 20% in 2002 compared to 2001. The major components of this increase are:
$2.2 billion in revenues in the Mid-Atlantic region as a result of increased
hedging, marketing and operating activities and $1.1 billion in revenues
contributed by Orion Power, which was acquired in February 2002. These
increased revenues were offset by $2.2 billion in lower generation volumes and
reduced hedging and marketing activities in regions other than the Mid-Atlantic
and lower prices for electric energy and ancillary services.
Fuel and cost of gas sold and purchased power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power increased by $1.2
billion in 2002 due primarily to $2.3 billion in the Mid-Atlantic region as a
result of hedging and marketing activities and an increase of $444 million due
to Orion Power. This was partially offset by a $1.7 billion reduction of
generation volumes, reduced hedging and marketing activities and lower prices
for fuel in the California region.
Trading margins. Trading margins, excluding a $5 million provision related
to Enron recorded in 2001, decreased $172 million primarily as a result of
lower commodity volatility in the power markets, reduced market liquidity
driven by the industry's restructuring and the reduction of our trading
activities as a result of our restructuring, as discussed above.
Power generation margins. Our wholesale energy segment's power generation
margins decreased $161 million in 2002 compared to 2001. Power generation
margins in the wholesale energy segment were negatively impacted by the
following:
. a $751 million decrease in power generation margins in the West region
due to (a) the loosening of tight supply and demand conditions that
existed in the first six months of 2001, (b) increased refund
requirements discussed above, (c) a full year of energy price caps which
were initially implemented in June 2001 and (d) other regulatory
provisions that suppressed ancillary services revenues;
. a $76 million decrease in power generation margins in the Mid-Atlantic
Region in 2002 due to a decline in power prices and reduced capacity
revenues as a result of the expiration of a large capacity contract and
lower capacity market conditions, which were primarily a result of
increased generation supply in the region as well as regulatory
intervention;
. a $68 million decrease in our other smaller regions mainly due to
decreases in power prices, losses on our tolling contracts and increased
gas transportation costs in 2002;
. increased fuel transportation costs for new projects; and
. a $33 million decrease due to the ineffectiveness of cash flow hedges
from a $31 million gain in 2001 primarily related to the California
market (see note 1 to our consolidated financial statements) to a $2
million loss in 2002.
46
These unfavorable variances were partially offset by the following:
. $611 million in power generation margins from the Orion Power acquisition
that closed in February 2002 and
. $93 million in power generation margins from new plants that became
commercially operational in the second half of 2001 and throughout the
first half of 2002.
In addition, the results for 2001 included a $63 million provision against
net receivables, trading and marketing assets and non-trading derivative
balances related to Enron.
Operation and maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $247 million in 2002 compared to 2001. This
was primarily due to $254 million of operation and maintenance expenses of our
Orion plants acquired in February 2002 and $21 million from new plants that
became commercially operational in the second half of 2001 and throughout the
first half of 2002, slightly offset by reduced expenses of $27 million as a
result of lower maintenance and outage costs in the West and Mid-Atlantic
regions.
General, administrative and development. General, administrative and
development expenses increased $89 million in 2002 compared to 2001, primarily
due to the following:
. $26 million of higher corporate overhead allocations to support wholesale
commercial activities, including the integration of Orion Power;
. $20 million of severance expense primarily related to our restructuring
discussed above;
. $11 million of consulting costs incurred in connection with our
restructuring of plant operations and commercial activities and support
groups; and
. $9 million of general bad debt expense due to the financial deterioration
of counterparties in the wholesale energy industry in 2002.
In addition, during 2002, our wholesale energy segment incurred $14 million
in increased expenses related to development activities, which includes $27
million of write-offs in 2002 in previously capitalized costs related to
projects that have been terminated partially offset by $9 million of
development cost write-offs in 2001.
Depreciation and amortization. Depreciation and amortization expense
increased by $219 million in 2002 compared to 2001 primarily as a result of the
following:
. $110 million in depreciation expense related to our Orion Power plants;
. $23 million in depreciation expense for other generating plants placed
into service during the second half of 2001 and throughout the first half
of 2002;
. a $37 million equipment impairment charge related to turbines and
generators;
. $16 million in depreciation expense associated with new information
technology systems placed into service in 2002; and
. a $15 million write-off for the closure of our Warren power plant in
Pennsylvania.
In addition, during 2002, emission credit amortization increased $10 million
due to increased amortization of $25 million resulting from the Orion
acquisition in February 2002. These were partially offset by $19 million of
lower amortization of air emission allowances primarily related to our
California power generation operations. For 2001, wholesale energy recorded $4
million in goodwill amortization expense. For information regarding the
cessation of goodwill amortization, see note 6 to our consolidated financial
statements.
47
Income of equity investment of unconsolidated subsidiaries. Our wholesale
energy segment reported $18 million in income from equity investments for 2002
compared to $6 million in 2001. The equity income in both years primarily
resulted from an investment in an electric generation plant in Boulder City,
Nevada. The equity income related to this investment increased during 2002
compared to 2001, primarily due to receipts of $22 million from business
interruption and property/casualty insurance settlements, partially offset by
decreases in margins due to lower prices realized in 2002.
Other income, net. Other non-operating income increased $23 million in 2002
compared to 2001 primarily due to billings for software services, engineering
and technical support services, and other services to support operations and
maintenance of generating facilities of Texas Genco.
2001 Compared to 2000
EBIT. Our wholesale energy segment's EBIT increased $344 million in 2001
compared to 2000. The increase in EBIT was primarily due to increased power
generation margins from our generation facilities and increased trading
margins. The increases in power generation margins and trading margins were
partially offset by increased operating expenses and a decrease in other income
as further discussed below. 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 credit provision and a
$15 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.
Revenues. Our wholesale energy segment's revenues increased by $2.7 billion
(102%) in 2001 compared to 2000. The major components of this increase were
$1.6 billion from our California operations due to hedging and marketing
activities and the factors discussed above, and $1.0 billion from our
Mid-Atlantic region assets as a result of favorable hedging and marketing and
operating results.
Fuel and cost of gas sold and purchased power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power increased by $2.2
billion in 2001 compared to 2000 due primarily to $1.3 billion from the
California operations and $928 million from our Mid-Atlantic assets as a result
of hedging and marketing activities.
Trading margins. Trading and marketing margins, excluding a $5 million
provision related to Enron, increased $111 million primarily as a result of
increased natural gas trading volumes.
Power generation margins. Power generation margins for our wholesale energy
segment increased by $488 million primarily due to increased volumes on power
sales from our generation facilities, and the addition of our Mid-Atlantic
assets in May 2000 and strong commercial and operational performance in other
regions. Margins on power sales from our generation facilities increased by the
following amounts by region in 2001 compared to 2000 (and exclude a $63 million
provision related to Enron):
. $389 million in the West region;
. $85 million in the Mid-Atlantic region;
. $29 million in other regions; and
. $31 million due to the ineffectiveness of cash flow hedges in 2001
primarily related to the California market.
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.
These favorable market conditions did not exist in the second half of 2001.
48
Operation and maintenance. Operation and maintenance expenses for wholesale
energy increased $107 million in 2001 compared to 2000, primarily due to $50
million of costs associated with the operation and maintenance of generating
plants acquired in the Mid-Atlantic region and $38 million higher lease expense
associated with the Mid-Atlantic generation facilities' sale-leaseback
transactions that were entered into in August 2000.
General, administrative and development. General, administrative and
development expenses increased $75 million in 2001 compared to 2000, primarily
due to $69 million of higher administrative costs to support growing wholesale
commercial activities and $25 million of higher legal and regulatory expenses
related to the West region, partially offset by a $12 million decrease in
development expenses.
Depreciation and amortization. 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 an $8 million decrease in amortization of our
air emissions regulatory allowances.
Income of equity investment of unconsolidated subsidiaries. Our wholesale
energy segment reported income from equity investments for 2001 of $6 million
as 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.
Other income, net. Other income, net, decreased by $21 million in 2001
compared to 2000 primarily as a result of an $18 million pre-tax gain in 2000
on the sale of our interest in one of our development-stage electric generation
projects.
European Energy
Our European energy segment generates and sells power from its generation
facilities in the Netherlands and participates in the wholesale energy trading
and origination industry in Northwest Europe.
In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon, a Netherlands-based electricity distributor. Upon
consummation of the sale, we expect to receive cash proceeds from the sale of
approximately $1.2 billion (Euro 1.1 billion). We intend to use the cash
proceeds from the sale first to prepay the Euro 600 million bank term loan
borrowed by Reliant Energy Capital (Europe), Inc. to finance a portion of the
acquisition costs of our European energy operations. The maturity date of the
credit facility, which originally was scheduled to mature in March 2003, has
been extended (see notes 9(a) and 21(c) to our consolidated financial
statements). We intend to use the remaining cash proceeds of approximately $0.5
billion (Euro 0.5 billion) to partially fund our option to acquire Texas Genco
in 2004 (see note 4(b) to our consolidated financial statements). However, if
we do not exercise the option, we will use the remaining cash proceeds to
prepay debt.
We recognized a loss of approximately $0.4 billion in the first quarter of
2003 in connection with the anticipated sale. We do not anticipate that there
will be a Dutch or United States income tax benefit realized by us as a result
of the $0.4 billion loss. In addition, we recognized an impairment of the full
amount of our European energy segment's net goodwill of $482 million in the
fourth quarter of 2002, as further discussed below. We will recognize
contingent payments, if any, in earnings upon receipt. In the first quarter of
2003, we began to report the results of our European energy operations as
discontinued operations in accordance with SFAS No. 144. For further discussion
of the sale, see note 21(b) to our consolidated financial statements.
Based on our annual impairment test as of November 1, 2002, we recognized an
impairment of the full amount of our European energy segment's net goodwill of
$482 million in the fourth quarter of 2002. As we
49
signed a share purchase agreement to sell our European energy operations in
February 2003 (as discussed above), the sales price reflects the best estimate
of fair value of our European energy segment as of November 1, 2002, to use in
our annual impairment test. For additional information regarding this goodwill
impairment and this transaction and the related impacts, see notes 6 and 21(b)
to our consolidated financial statements.
During the third quarter of 2002, we completed the transitional impairment
test for the adoption of SFAS No. 142, including the review of goodwill for
impairment. Based on this impairment test, we recorded an impairment of the
European energy segment's goodwill of $234 million, net of tax. This impairment
loss was recorded retroactively as a cumulative effect of a change in
accounting principle for the quarter ended March 31, 2002. The circumstances
leading to this impairment of our European energy segment's goodwill included a
significant decline in electric margins attributable to the deregulation of the
European electricity market in 2001, lack of growth in the wholesale energy
trading markets in Northwest Europe, continued regulation of certain European
fuels markets, and the reduction of proprietary trading in our European
operations. For further discussion of the impairment, see note 6 to our
consolidated financial statements.
In September 2002, we concluded a comprehensive evaluation of our European
energy segment's businesses and it was decided that proprietary trading would
be significantly reduced in order to focus on commercial activities around our
power generation assets and wholesale customers in the Netherlands.
Accordingly, in the third quarter of 2002, we announced the closure of our
London-based natural gas and electricity trading operations. In addition, we
have consolidated facilities, centralized activities and reduced personnel in
Amsterdam and Frankfurt. As a result, our European energy segment recorded an
$8 million reorganization charge in 2002, primarily related to severance, in
operating and maintenance and general and administrative expenses.
For additional information regarding factors that may affect the future
results of operations of our European energy segment, see "--Risk
Factors--Risks Related to Our European Energy Operations."
50
The following table provides summary data, including EBIT of our European
energy segment for 2000, 2001 and 2002:
European Energy Segment
-----------------------------
Year Ended December 31,
-----------------------------
2000 2001 2002
------- ------- -------
(in millions, except operating
data)
Revenues...................................................... $ 544 $ 623 $ 611
Trading margins............................................... 2 (9) 21
------- ------- -------
Total operating revenues............................... 546 614 632
Operating expenses:
Fuel....................................................... 260 400 357
Purchased power............................................ -- 11 (40)
Operation and maintenance.................................. 87 30 117
General and administrative................................. 39 41 29
Goodwill impairment........................................ -- -- 482
Depreciation and amortization.............................. 76 76 58
------- ------- -------
Total operating expenses............................... 462 558 1,003
------- ------- -------
Operating income (loss)....................................... 84 56 (371)
------- ------- -------
Other income:
Income of equity investment of unconsolidated subsidiaries. -- 51 5
Other, net................................................. 5 6 10
------- ------- -------
Earnings (loss) before interest and income taxes........... $ 89 $ 113 $ (356)
======= ======= =======
Margins:
Power generation (1)....................................... $ 284 $ 212 $ 294
Trading.................................................... 2 (9) 21
------- ------- -------
Total.................................................. $ 286 $ 203 $ 315
======= ======= =======
Electricity (in thousand MWh):
Power generation sales..................................... 11,606 16,344 17,794
Trading sales.............................................. 1,091 25,232 71,660
- --------
(1) Revenues less fuel and purchased power.
2002 Compared to 2001
EBIT. Our European energy segment's EBIT decreased $469 million during 2002
as compared to 2001 due to a $482 million goodwill impairment in the fourth
quarter of 2002, as discussed above, and to a lesser extent increased operation
and maintenance and general and administrative expenses and decreased equity
investment income, as explained below. These decreases were partially offset by
increased margins of $112 million. During the second quarter of 2002, our
European energy segment recognized a one-time $109 million gain resulting from
the amendment of our stranded cost electricity supply contracts which is
recorded as a reduction in purchased power expense and is included in power
generation margins. For additional discussion regarding the amendment of these
contracts, see note 14(j) to our consolidated financial statements.
Revenues. Our European energy segment's revenues decreased $12 million for
2002 compared to 2001. Contributing to the decline from 2001 was a
non-recurring efficiency and energy payment of $30 million received during the
second quarter of 2001 from NEA, which was the coordinating body for the Dutch
electric generating sector prior to wholesale competition. In addition,
ancillary services and district heating revenues decreased by a combined total
of $12 million and during the fourth quarter of 2002 we recognized a $6 million
51
reduction in revenues related to the bankruptcy of an European subsidiary of
TXU Corp. Partially offsetting these decreases in revenues was $21 million in
increased electricity sales and an $11 million favorable foreign exchange
effect.
Trading margins. Trading margins increased $30 million for 2002 compared to
2001 primarily due to a $14 million increase in green power origination
transactions and a $17 million provision recorded in 2001 against receivable
and trading and marketing asset balances related to Enron. During the third
quarter of 2002, we ceased, in all material respects, trading on a proprietary
basis. In addition, overall market liquidity has reduced in the European power
markets from prior years.
Fuel and purchased power. Fuel and purchased power costs decreased $94
million for 2002 compared to 2001 primarily due to a one-time $109 million gain
as discussed above and a net $19 million gain related to changes in the
mark-to-market valuation of certain out-of-market contracts in 2002, partially
offset by $9 million of unfavorable foreign exchange effect. In addition,
higher electricity sales levels have driven comparatively higher levels of fuel
consumption and purchased power during 2002 as compared to 2001.
Power generation margins. Power generation margins increased $82 million
for 2002 compared to 2001 due to the various factors discussed above. In
addition, we estimate unplanned plant outages had a $10 million negative power
generation margins impact during 2002 compared to an $11 million negative
impact during 2001.
Operation and maintenance and general and administrative. Operation and
maintenance and general and administrative expenses increased by $75 million
for 2002 compared to 2001 primarily due to the following:
. a $37 million net gain recorded in operation and maintenance expense
related to the settlement, during December 2001, of the former
shareholder's indemnity obligation related to out-of-market contracts
(see note 14(j) to our consolidated financial statements);
. $8 million in reorganization and severance charges associated with our
business restructuring in 2002 as discussed above;
. $8 million reversal of a reserve for environmental tax subsidies
receivable in 2001;
. $6 million increase in employee benefit expenses in 2002;
. $6 million increase in legal, consulting and environmental fees in 2002;
and
. $9 million unfavorable foreign exchange effect.
These items were partially offset by a $6 million decrease in corporate
overhead allocations.
Goodwill impairment. As further described above, during the fourth quarter
of 2002, our European energy segment recognized a $482 million impairment of
the full amount of its net goodwill.
Depreciation and amortization. Depreciation and amortization expense
decreased $18 million for 2002 compared to 2001 primarily due to the cessation
of goodwill amortization effective January 1, 2002. During 2001, European
energy recorded $26 million in goodwill amortization expense. This decrease was
partially offset by a $5 million increase in depreciation expense as a result
of capital expenditures in late 2001 associated with our trading business and a
$3 million favorable foreign exchange effect.
Other income, net. Other non-operating income decreased $42 million during
2002 compared to 2001 primarily due to a $51 million gain recorded in the
second quarter of 2001, as equity income for the preacquisition gain
contingency related to the acquisition of REPGB for the value of its equity
investment in NEA. For further discussion of this gain, see note 14(j) to our
consolidated financial statements. This decrease in equity income was partially
offset by equity income for 2002 of $5 million.
52
2001 Compared to 2000
EBIT. Our European energy segment's EBIT increased by $24 million for 2001
compared to 2000. This increase was primarily due to a $51 million gain
recorded in the second quarter of 2001, within income of equity investments of
unconsolidated subsidiaries, as described above, and a decrease of operation
and maintenance expenses, as discussed below. This increase in EBIT was
partially offset by an $83 million decrease in margins, as discussed below.
Revenues. Our European energy segment's revenues increased $79 million
during 2001 as compared to 2000. This increase was primarily due to the
following:
. a $30 million efficiency and energy payment from NEA in 2001, as
described above;
. $33 million increase in ancillary services due to the imbalance market
created by the liberalization of the wholesale energy market;
. $23 million in higher district heating revenues due to colder weather as
well as growth in certain districts; and
. $9 million increase in electric generation sales.
Partially offsetting these increases in revenues was a $16 million
unfavorable foreign exchange effect.
Trading margins. Trading margins decreased $11 million from $2 million in
margins in 2000 to $9 million in margins loss in 2001 primarily as a result of
a $17 million provision against receivable and trading and marketing asset
balances related to Enron, as discussed above. Excluding this provision,
trading margins increased $6 million primarily due to a significant increase in
trading revenues in the Dutch, German and Austrian power markets, power trading
volumes, trading origination transactions and increased volatility in the Dutch
and German markets.
Fuel and purchased power. Fuel and purchased power costs increased $151
million for 2001 compared to 2000 primarily due to higher natural gas prices,
increased output from our generating facilities and increased transmission and
grid charges as a result of a change in the tariff structure. Partially
offsetting this increase in fuel and purchased power costs was a $14 million
favorable foreign exchange effect.
Power generation margins. Power generation margins decreased $72 million
for 2001 compared to 2000 due to the various factors discussed above. 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 in 2001.
Operation and maintenance and general and administrative. Operation and
maintenance and general and administrative expenses decreased by $55 million
for 2001 compared to 2000. These expenses declined primarily due to the
following:
. the net gain of $37 million recorded in operation and maintenance
expenses related to the settlement of the former shareholders' indemnity
obligation;
. 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
. a $6 million decrease in provisions for environmental liabilities,
employee benefits and other accruals.
This decrease was partially offset by an increase in personnel and operating
expenses related to our trading operations, facilities costs and systems
upgrades.
53
Other income, net. Other non-operating income increased $52 million during
2001 compared to 2000 primarily due to a $51 million gain recorded in the
second quarter of 2001, within income of equity investments of unconsolidated
subsidiaries, as described above.
Other Operations
Our other operations segment includes the operations of our venture capital
business 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 owned network operations centers and
managed data centers in Houston and Austin. Our exit plan was substantially
completed in the first quarter of 2002.
The following table provides summary data regarding the results of
operations for our other operations segment for 2000, 2001 and 2002:
Other Operations
Segment
----------------------
Year Ended December 31,
----------------------
2000 2001 2002
---- ----- ----
(in millions)
Operating revenues................... $ 6 $ 11 $ 3
Operating expenses:
Operation and maintenance......... 9 21 3
General and administrative........ 52 128 42
Depreciation and amortization..... 6 42 15
---- ----- ----
Total operating expenses...... 67 191 60
---- ----- ----
Operating loss....................... (61) (180) (57)
---- ----- ----
Other income (expenses):.............
(Loss) gain from investments...... (26) 23 (23)
Other, net........................ 4 (1) --
---- ----- ----
Loss before interest and income taxes $(83) $(158) $(80)
==== ===== ====
2002 Compared to 2001
Other operations' loss before interest and income taxes declined by $78
million for 2002 compared to 2001. The decline in loss before interest and
income taxes is primarily due to the following:
. a $100 million pre-tax, non-cash charge recorded in the first quarter of
2001 relating to the redesign of some of CenterPoint's benefit plans in
anticipation of our separation from CenterPoint;
. $35 million in restructuring charges and $19 million of goodwill
impairment related to the exiting of our communications business
recognized during the third quarter of 2001; and
. $18 million in decreased operating losses related to our communications
business.
Partially offsetting these items are a $47 million net pre-tax, non-cash
accounting settlement charge recognized during the third quarter of 2002 for
certain benefit obligations associated with our separation from CenterPoint,
and a $12 million increase in depreciation expense related to corporate assets.
In addition, other income decreased $45 million during 2002 compared to 2001,
primarily due to $14 million in decreased gains
54
from investments coupled with a $32 million impairment of certain venture
capital investments. For further discussion on these investments and the
related impairments, see note 2(o) 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 $13 million in severance accruals, lease cancellation costs and
other incremental costs associated with exiting the communications business.
The goodwill and fixed asset impairments are included in depreciation and
amortization expense.
For additional information about the benefit charges noted above, see notes
12(b) and 12(d) to our consolidated financial statements.
2001 Compared to 2000
Other operation's loss before interest and income taxes increased by $75
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 $100 million non-cash charge during
2001 relating to the redesign of some of CenterPoint's benefit plans in
anticipation of our separation from CenterPoint. These items were partially
offset by a $44 million increase in other income primarily due to a $27 million
impairment loss incurred in 2000 on marketable equity securities, classified as
"available-for-sale", as a result of various factors which caused our
management to believe the declines in fair value to be other than temporary,
and a $22 million increase in gains from equity and debt securities. A decrease
of $12 million in corporate operating expenses and a decrease of $15 million in
charitable contributions of equity securities also slightly offset the increase
in the loss before interest and income taxes. For information regarding the $27
million impairment loss incurred in 2000, see note 2(o) to our consolidated
financial statements.
Trading and Marketing Operations
Trading and marketing activities include (a) transactions establishing open
positions in the energy markets, primarily on a short-term basis, (b)
transactions intended to optimize our power generation portfolio, but which do
not qualify for hedge accounting and (c) energy price risk management services
to customers primarily related to natural gas, electric power and other
energy-related commodities. We provide these services by utilizing a variety of
derivative instruments (trading energy derivatives). We account for these
transactions under mark-to-market accounting. For information regarding
mark-to-market accounting, see notes 2(t) and 7 to our consolidated financial
statements. Specifically, these trading and marketing activities consist of the
following:
. the large contracted commercial, industrial and institutional customers
under retail electricity contracts and the related energy supply
contracts of our retail energy segment entered into prior to October 25,
2002;
. the domestic energy trading, marketing, risk management services to our
customers and certain power origination activities of our wholesale
energy segment; and
. the European energy trading and origination operations of our European
energy segment.
During 2002, we evaluated our trading, marketing, power origination and risk
management services strategies and activities. During the second half of 2002,
we began to reduce our wholesale energy segment's trading, marketing and power
origination activities due to liquidity concerns and in order to significantly
reduce collateral usage and focus on the highest return transactions, which
primarily relate to our physical asset positions. In March 2003, we decided to
exit our proprietary trading activities and liquidate, to the extent
55
practicable, our proprietary positions. Although we are exiting the proprietary
trading business, we have existing positions, which will be closed as
economically feasible or in accordance with their terms. We will continue to
engage in hedging activities related to our electric generating facilities,
pipeline storage positions and fuel positions.
In October 2002, the EITF rescinded EITF No. 98-10. For further discussion
of the impact on our consolidated financial statements, see "--EBIT by Business
Segment--Retail Energy" and "EBIT by Business Segment--Wholesale Energy" in
Item 7 of this Form 10-K and notes 2(t) and 7 to our consolidated financial
statements.
For additional information regarding the types of contracts and activities
of our trading and marketing operations, see "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this Form 10-K and note 7 to our
consolidated financial statements.
The following table sets forth our net trading and marketing assets
(liabilities) by segment as of December 31, 2001 and 2002:
As of December 31,
-----------------
2001 2002
---- ----
(in millions)
Retail energy....................................... $ 73 $ 94
Wholesale energy.................................... 154 105
European energy..................................... (9) (9)
---- ----
Net trading and marketing assets and liabilities. $218 $190
==== ====
The following table sets forth our realized and unrealized trading,
marketing and risk management services margins for 2000, 2001 and 2002:
Year Ended December 31,
----------------------
2000 2001 2002
---- ---- ----
(in millions)
Realized.. $202 $184 $334
Unrealized (2) 186 (24)
---- ---- ----
Total.. $200 $370 $310
==== ==== ====
Below is an analysis to our consolidated net trading and marketing assets
and liabilities for 2001 and 2002:
Year Ended
December 31,
------------
2001 2002
(in millions)
Fair value of contracts outstanding, beginning of the year.................. $ 32 $ 218
Fair value of new contracts when entered into during the year............... 119 57
Contracts realized or settled during the year............................... (184) (334)
Changes in fair values attributable to changes in valuation techniques and
assumptions............................................................... (23) 31
Changes in fair values attributable to market price and other market changes 274 218
----- -----
Fair value of contracts outstanding, end of the year..................... $ 218 $ 190
===== =====
During 2001 and 2002, our retail energy segment entered into electric sales
contracts with large commercial, industrial and institutional customers ranging
from one-half to four years in duration. These contracts had an
56
aggregate fair value of $97 million in 2001 at the contract inception dates.
Subsequent to the inception dates, the fair values of these contracts were
adjusted to $74 million during 2001 due to changes in assumptions used in the
valuation models, as described below. During 2002, we recognized total fair
value of $43 million for these contracts at the inception dates. We have
entered into energy supply contracts to substantially hedge the economics of
these contracts. The fair value of these retail energy segment electric sales
contracts with large commercial, industrial and institutional customers was
determined by comparing the contract price to an estimate of the market cost of
delivered retail energy and applying the estimated volumes under the provisions
of these contracts. The calculation of the estimated cost of energy involves
estimating the customer's anticipated load volume, and using forward ERCOT OTC
commodity prices, adjusted for the customer's anticipated load characteristics.
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. The delivery
costs are estimated at the time sales contracts are executed. These costs are
based on published rates and our experience of actual delivery costs. Examples
of these delivery costs include electric line losses and unaccounted for
energy, ERCOT ISO administrative fees, market interaction charges, and may
include transmission and distribution fees. The remaining weighted-average
duration of these contracts is approximately sixteen months as of December 31,
2002.
Our retail energy segment also enters into supply contracts to substantially
hedge the economics of the sales contracts entered into with large commercial,
industrial and institutional customers. During 2001 and 2002, we recognized
total fair value of $5 million and $8 million, respectively, related to these
contracts at the inception dates. The fair values of these contracts are
estimated using ERCOT OTC forward price and volatility curves and correlations
among power and fuel prices specific to the ERCOT Region, net of credit risk.
For the contracts extending beyond December 31, 2002, the remaining
weighted-average duration of these contracts, based on volumes, is one year.
During 2001 and 2002, the fair value of new contracts recorded at inception
of $17 million and $6 million, respectively, primarily relates to power
purchases and sales and natural gas transportation contracts entered into by
the wholesale energy segment. 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. For the contracts extending beyond December 31, 2002, the remaining
weighted-average duration of these contracts, based on volumes, is four years.
During 2002, our retail energy segment eliminated one valuation factor
adjustment and added another to its fair value calculation. Our retail energy
segment eliminated a valuation factor for potential claims for delays in
switching under the liquidated damage clauses in contracts. Retail energy
eliminated this valuation factor because there is now enough data to
substantiate that these claims will not be submitted. This change in
methodology reduced credit reserves by $5 million. Our retail energy segment
added a valuation factor adjustment to capture the potential earnings loss
associated with customers terminating contracts due to a provision in some of
its contracts that allows customers to terminate their contracts if our
unsecured debt ratings fall below investment grade or if our ratings are
withdrawn entirely by a rating agency. During the third quarter of 2002, each
of the major rating agencies downgraded our credit ratings to sub-investment
grade. We performed an analysis at the customer level to estimate our exposure
for these provisions. To date, no customers have terminated according to this
provision. This change in methodology increased credit reserves by $1 million.
Our retail energy segment also changed the methodology related to recording its
estimate of unaccounted for energy. Our retail energy segment changed its
estimate of unaccounted for energy factor from 1.6% to zero. The reason for the
change is that the retail energy segment believes the estimate of unaccounted
for energy is included in its volatility valuation factor and its results from
energy sales in 2001 were not negatively impacted by the estimate of
unaccounted for energy. This change in methodology reduced credit reserves by
$9 million.
57
In addition, during 2002, we changed our methodology for allocating credit
reserves between our trading and non-trading portfolios. Total credit reserves
calculated for both the trading and non-trading portfolios, which are less than
the sum of the independently calculated credit reserves for each portfolio due
to common counterparties between the portfolios, are allocated to the trading
and non-trading portfolios based upon the independently calculated trading and
non-trading credit reserves. Previously, credit reserves were independently
calculated for the trading portfolio while credit reserves for the non-trading
portfolio were calculated by deducting the trading credit reserves from the
total credit reserves calculated for both portfolios. This change in
methodology reduced credit reserves relating to the trading portfolio by $18
million.
The following table sets forth the fair values of the contracts related to
our trading and marketing assets and liabilities as of December 31, 2002:
Fair Value of Contracts at December 31, 2002
-----------------------------------------------
2008 and Total fair
Source of Fair Value 2003 2004 2005 2006 2007 thereafter value
- -------------------- ---- ---- ---- ---- ---- ---------- ----------
(in millions)
Prices actively quoted.................... $ 4 $(16) $-- $-- $-- $-- $(12)
Prices provided by other external sources. 147 40 4 -- -- -- 191
Prices based on models and other valuation
methods................................. (33) 2 3 9 13 17 11
---- ---- --- --- --- --- ----
Total.................................. $118 $ 26 $ 7 $ 9 $13 $17 $190
==== ==== === === === === ====
The following table sets forth the fair values of the contracts recognized
as derivatives under SFAS No. 133 which were previously recorded as trading and
marketing assets and liabilities as of January 1, 2003, after the effect of the
adoption of EITF No. 02-03 has been recorded as a cumulative effective of a
change in accounting principle (see notes 2(d) and 2(t) to our consolidated
financial statements):
Fair Value of Contracts at January 1, 2003
-----------------------------------------------
2008 and Total fair
Source of Fair Value 2003 2004 2005 2006 2007 thereafter value
- -------------------- ---- ---- ---- ---- ---- ---------- ----------
(in millions)
Prices actively quoted.................... $ 4 $(16) $-- $-- $-- $-- $(12)
Prices provided by other external sources. 131 40 4 -- -- -- 175
Prices based on models and other valuation
methods................................. (44) (9) (5) 2 9 10 (37)
---- ---- --- --- --- --- ----
Total.................................. $ 91 $ 15 $(1) $ 2 $ 9 $10 $126
==== ==== === === === === ====
The "prices actively quoted" category represents our New York Mercantile
Exchange (NYMEX) futures positions in natural gas and crude oil. NYMEX has
quoted prices for natural gas and crude oil for the next 72 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
36 and 24 months into the future, respectively. We value these positions
against internally developed forward market price curves that are frequently
validated 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 which are actively
quoted. Options are typically valued using Black-Scholes option valuation
models. Although the valuation of the simple structures might not be different
58
from 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 has 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 segment 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.
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. We have broad credit policies and parameters set
by our risk oversight committee. The credit risk control organizations prepare
daily analyses of credit exposures. We seek to enter into contracts that permit
us to net receivables and payables with a given counterparty. We also enter
into contracts that enable us to obtain collateral from a counterparty as well
as to terminate upon the occurrence of certain events of default.
It is our policy that all transactions must be within approved counterparty
or customer credit limits. For each business segment, the credit risk control
organization establishes counterparty credit limits. We employ tiered levels of
approval authority for counterparty credit limits, with authority increasing
from the credit risk control organization through senior management and the
risk oversight committee. The credit risk control organization monitors credit
exposure daily. We periodically review the financial condition of our
counterparties.
We assess our credit risk and exposure by counterparty taking into
consideration both our trading and marketing assets and non-trading derivatives
with each counterparty.
The following table sets forth the distribution by credit ratings of our
trading and marketing assets and non-trading derivative assets as of December
31, 2002, after taking into consideration netting within each contract and any
master netting contracts with counterparties :
Percentage of
Exposure Exposure
Collateral Net of Net of
Credit Rating Equivalent Exposure Held (1) Collateral Collateral
------------------------ -------- ---------- ---------- -------------
(in millions)
AAA/Aaa........................ $ 1 $ -- $ 1 -- %
AA-/Aa3 or above............... 139 (70) 69 10%
A-/A3 or above................. 118 -- 118 17%
BBB-/Baa3 or above............. 315 (53) 262 38%
BB+/Ba1 or below............... 276 (64) 212 30%
Unrated (2)(3)................. 32 (1) 31 5%
---- ----- ---- ---
881 (188) 693 100%
Less: Credit and other reserves (68) -- (68)
---- ----- ----
Total....................... $813 $(188) $625
==== ===== ====
59
- --------
(1) Collateral consists of cash and standby letters of credit.
(2) For unrated counterparties, we perform financial statement analyses,
considering contractual rights and restrictions, and collateral, to create
an internal credit rating.
(3) 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.
The following table sets forth the credit exposure by maturity for total
trading and marketing assets and non-trading derivative assets as of December
31, 2002:
Exposure
1 Year Net of
0-12 or Collateral
Credit Rating Equivalent Months Greater (1)
------------------------ ------ ------- ----------
(in millions)
AAA/Aaa........................ $ 1 $ -- $ 1
AA-/Aa3 or above............... 110 29 69
A-/A3 or above................. 100 18 118
BBB-/Baa3 or above............. 281 34 262
BB+/Ba1 or below............... 148 128 212
Unrated (2)(3)................. 29 3 31
---- ---- ----
669 212 693
Less: Credit and other reserves (30) (38) (68)
---- ---- ----
Total....................... $639 $174 $625
==== ==== ====
- --------
(1) Collateral consists of cash and standby letters of credit.
(2) For unrated counterparties, we perform credit analyses, considering
contractual rights and restrictions, and credit support such as parent
company guarantees to create an internal credit rating.
(3) 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.
Trading and marketing assets and liabilities and non-trading derivative
assets and liabilities are presented separately in our consolidated balance
sheets. The trading and non-trading derivative asset and trading and
non-trading derivative liability balances were offset separately for trading
and non-trading activities although in certain cases contracts permit the
offset of trading and non-trading derivative assets and liabilities with a
given counterparty. For the purpose of disclosing credit risk, trading and
non-trading derivative assets and liabilities with a given counterparty were
offset if the counterparty has entered into a contract with us which permits
netting.
The credit distribution as of December 31, 2002 includes a larger percentage
of non-investment grade counterparties compared to our credit exposure as of
December 31, 2001. This is primarily attributable to the credit rating
downgrades that took place within the energy sector during 2002. As of December
31, 2001, no individual counterparty accounted for more than 10% of our total
credit exposure, net of collateral. As of December 31, 2002, one counterparty
with a BB credit rating represented 12% of our total credit exposure, net of
collateral.
Other. For additional information about price volatility and our hedging
strategy, see "--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 a description of accounting policies for our trading and marketing
activities, see notes 2(d), 2(t) and 7 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, see "Quantitative and
Qualitative Disclosures About Market Risk--Risk Management Structure" in Item
7A of this Form 10-K.
60
Related-Party Transactions
In the normal course of operations, we have entered into transactions and
agreements with related parties, including CenterPoint. For a discussion of
historical related party transactions, see note 3 to our consolidated financial
statements. Below are details of significant current related party
transactions, arrangements and agreements.
Agreements With CenterPoint
Master Separation Agreement. Shortly before our IPO, we entered into a
master separation agreement with CenterPoint. The agreement provided for the
separation of our assets and businesses from those of CenterPoint. It also
contains agreements governing the relationship between CenterPoint and us after
our IPO, and in some cases after the Distribution, and specifies the related
ancillary agreements that we have signed with CenterPoint, some of which are
described in further detail below.
The agreement provides for cross-indemnities intended to place sole
financial responsibility on us and our subsidiaries for all liabilities (except
for certain possible tax 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 CenterPoint's other
businesses with CenterPoint 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.
The agreement also requires us to indemnify CenterPoint for any untrue
statement of a material fact, or omission of a material fact necessary to make
any statement not misleading, in the registration statement or prospectus that
we filed with the SEC in connection with our IPO.
Texas Genco Option. In connection with the separation of our businesses
from those of CenterPoint, CenterPoint granted us an option to purchase all of
the shares of capital stock owned by CenterPoint in January 2004 of Texas
Genco, which holds the Texas generating assets of CenterPoint's electric
utility division. For additional information regarding the Texas Genco option
and various agreements between CenterPoint and us related to the Texas Genco
option, see note 4(b) to our consolidated financial statements.
Service Agreements. We have entered into agreements with CenterPoint under
which CenterPoint 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, remittance processing and payroll, office support
services and purchasing and logistics. The charges we will pay CenterPoint for
these services are generally intended to allow CenterPoint to recover its fully
allocated costs of providing the services, plus out-of-pocket costs and
expenses. In addition, pursuant to lease agreements, CenterPoint 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, see note 4(a) to our consolidated financial statements.
Payment to CenterPoint. To the extent that our price to beat for electric
service to residential and small commercial customers in CenterPoint's Houston
service territory during 2002 and 2003 exceeds the market price of electricity,
we may be required to make a significant payment to CenterPoint in 2004. As of
December 31, 2002, our estimate for the payment related to residential
customers is between $160 million and $190 million, with a most probable
estimate of $175 million. For additional information regarding this payment,
see note 14(e) to our consolidated financial statements.
Guarantee of Certain Benefit Payments. We have guaranteed, in the event
CenterPoint becomes insolvent, certain non-qualified benefits of CenterPoint's
and its subsidiaries' existing retirees at the Distribution totaling
approximately $58 million.
61
Transportation Agreement. Prior to the IPO, Reliant Energy Services (our
wholly-owned trading subsidiary) entered into an agreement whereby a subsidiary
of CenterPoint 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, see note 14(f) to our consolidated financial statements.
Generating Capacity Auction Line of Credit. On October 1, 2002, our retail
energy segment, through a subsidiary, entered into a master power purchasing
contract with Texas Genco covering, among other things, our purchase of
capacity and/or energy from Texas Genco's generating facilities. In connection
with the March 2003 refinancing, this contract has been amended to grant Texas
Genco a security interest in the accounts receivable and related assets of
certain retail energy segment subsidiaries, the priority of which is subject to
certain permitted prior financing arrangements, and the junior liens granted to
the lenders under the March 2003 refinancing. In addition, many of the covenant
restrictions contained in the contract were removed in the amendment.
Various Other Agreements. In connection with the separation of our
businesses from those of CenterPoint, 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
CenterPoint 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, see notes 3 and 4 to our consolidated
financial statements.
Risk Factors
Set forth below, elsewhere in the Form 10-K and in other documents we file
with the SEC are risks and uncertainties that could cause our actual results to
differ materially from the results contemplated by our forward-looking
statements contained in the Form 10-K.
Risks Related to Our Retail Energy Operations
We may lose a significant number of our retail residential and small commercial
customers in the Houston metropolitan area.
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 electric 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 CenterPoint who did not take action to select
another retail electric provider. 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, or price to beat, whereas
other retail electric providers will be allowed to sell electricity to these
customers at any price. We are not permitted to offer electricity to these
customers at a price other than the price to beat until January 2005, unless
before that date the PUCT 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 are not 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 providers.
62
We may lose a significant portion of our market share of large commercial,
industrial and institutional customers in Texas.
We are providing commodity services to the large commercial, industrial and
institutional customers previously served by CenterPoint who did not take
action to contract with another retail electric provider. In addition, we have
signed contracts to provide electricity and energy efficiency services to large
commercial, industrial and institutional customers, both in the Houston area,
as well as in other parts of the ERCOT Region. 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
selects us to be their provider may subsequently decide to switch to another
provider at the conclusion of the term of their contract with us.
The results of our retail electric operations in Texas are largely dependent
upon the amount of headroom available in our price to beat. Future adjustments
to the price to beat may be inadequate to cover our costs to purchase power to
serve our residential and small commercial customers.
The results of our residential and small commercial retail electric
operations in Texas are largely dependent upon the amount of headroom available
in our price to beat. Headroom may be a positive or negative number. Our
current price is based on a wholesale energy supply cost component, or "fuel
factor," based on the ten trading-day average forward 12-month natural gas
price of $4.956 per MMbtu. The PUCT's current regulations allow us to request
an adjustment of our fuel factor based on the percentage change in the forward
price of natural gas or as a result of changes in the price of purchased energy
up to twice a year. In a purchased energy request, we 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 PUCT. We
cannot estimate with any certainty the magnitude and frequency of the
adjustments required, if any, and the eventual impact of such adjustments on
the amount of headroom available in our price to beat. If this adjustment and
any future adjustments to our price to beat are inadequate to cover future
increases in our costs to purchase power to serve our price to beat customers
or are delayed by the PUCT, our business, results of operations, financial
condition and cash flows could be materially adversely affected. In March 2003,
the PUCT approved a revised price to beat rule. The changes from the previous
rule include an increase in the number of days used to calculate the natural
gas price average from ten to 20, and an increase in the threshold of what
constitutes a significant change in the market price of natural gas and
purchased energy from 4% to 5%, except for filings made after November 15th of
a given year that must meet a 10% threshold. The revised rule also provides
that the PUCT will, after reaching a determination of stranded costs in 2004,
make downward adjustments to the price to beat fuel factor if natural gas
prices drop below the prices embedded in the then-current price to beat fuel
factor. In addition, the revised rule also specifies that the base rate portion
of the price to beat will be adjusted to account for changes in the
non-bypassable rates that result from the utilities' final stranded cost
determination in 2004. Adjustments to the price to beat will be made following
the utilities' final stranded cost determination in 2004. At this time, we
cannot predict the impact of the changes on our financial condition or results
of operations.
We face strong competition from affiliated retail electric providers of
incumbent electric utilities and other competitors.
In most retail electric markets outside the Houston area, our principal
competitor is the local incumbent electric 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 electric
utilities' affiliates, we face competition from a number of other retail
electric providers, including affiliates of other non-incumbent electric
utilities, independent retail electric providers and, with respect to sales to
large commercial, industrial and institutional customers, independent power
producers and wholesale power providers acting as retail electric providers.
Some of these competitors are larger and better capitalized than we are.
63
Our retail energy supply activity is subject to extensive market oversight.
Changes to market protocols or new regulation could have a material adverse
effect on our business, results of operations, financial condition and cash
flows.
The ERCOT ISO, which oversees the ERCOT Region, has and may continue to
modify the market structure and other market mechanisms in an attempt to
improve market efficiency. Moreover, existing regulations may be revised or
reinterpreted and new laws and regulations may be adopted or become applicable
to our commercial activities. These actions could have a material adverse
effect on our results of operations, financial condition and cash flows.
Payment defaults by other retail electric providers to ERCOT could have a
material adverse effect on our business, results of operations, financial
condition and cash flows.
In the event of a default by a retail electric provider of its payment
obligations to ERCOT, the portion of the obligation that is unrecoverable by
ERCOT from the defaulting retail electric provider is assumed by the remaining
market participants in proportion to each participants load ratio share. As a
retail electric provider and market participant in ERCOT, we would pay a
portion of the amount owed to ERCOT should such a default occur, and ERCOT is
not successful in recovering such amounts. The default of a retail electric
provider in its obligations to ERCOT could have a material adverse effect on
our business, results of operations, financial condition and cash flows.
In March 2003, TCE filed for bankruptcy protection. TCE has filed a request
that the bankruptcy court pay pre-petition amounts owed to ERCOT. The
bankruptcy court approved such request; however, no assurance can be given that
TCE will be able to satisfy its obligations to ERCOT.
We are heavily dependant upon third party providers of capacity and energy to
supply our retail obligations.
We do not own sufficient generating resources in Texas to supply our retail
business. The capacity and energy to supply our retail business is purchased at
market prices from a variety of suppliers under contracts with varying terms.
Our retail customers are concentrated in the Houston metropolitan area and
there is limited ability to serve these customers with generation located
outside the Houston metropolitan area. Texas Genco, located in the Houston
congestion zone, is the largest supplier of capacity and energy for our retail
business and is likely to remain our largest supplier for the foreseeable
future. There is a significant risk that our business, results of operations,
financial condition and cash flows could be materially adversely affected if we
are not able to purchase the capacity and energy from Texas Genco or otherwise
obtain sufficient capacity and energy required to serve our customers. The
failure of any of our third party suppliers to perform under the terms of
existing or future contracts could have a material adverse effect on our
results of operations, financial condition and cash flows.
We may be required to make a substantial payment to CenterPoint in 2004.
To the extent that our price to beat for electric service to residential and
small commercial customers in CenterPoint's Houston service territory during
2002 and 2003 exceeds the market price of electricity, we may be required to
make a significant payment to CenterPoint in 2004. As of December 31, 2002, our
estimate for the payment related to residential customers is between $160
million and $190 million, with a most probable estimate of $175 million. For
additional information regarding this payment, see note 14(e) to our
consolidated financial statements.
64
We rely on the infrastructure of transmission and distribution utilities and
the ERCOT ISO to transmit and deliver electricity to our retail customers and
to obtain information about our retail customers. In addition, we rely on the
reliability of our own infrastructure and systems to perform enrollment and
billing functions. Any infrastructure failure could negatively impact our
customers' satisfaction and could have a material negative impact on our
earnings.
We are dependent on 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 and could have a material adverse effect on our
results of operations, financial condition and cash flow. Additionally, we are
dependent on the transmission and distribution utilities for performing service
initiations and changes, and for reading our customers' energy meters. We are
required to rely on the transmission and distribution utility or, in some
cases, the ERCOT ISO, 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 transmission and distribution utilities or the ERCOT
ISO could have a material adverse effect on our business, results of
operations, financial condition and cash flow. In addition, any operational
problems with our new systems and processes could similarly have a material
adverse effect on our business, results of operations, financial condition and
cash flow. For additional information, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Retail Energy" in
Item 7 of this Form 10-K.
The ERCOT ISO has experienced a number of problems with its information systems
since the advent of competition in the Texas market that have resulted in
delays in switching customers and receiving final settlement information for
customer accounts. While performance is improving, if these problems do not
continue to improve, our operating results may be adversely affected.
The ERCOT ISO is the independent system operator responsible for maintaining
reliable operations of the bulk electric power supply system in the ERCOT
Region and for acting as a central agent for the registration of customers with
their chosen retail electric supplier. Its responsibilities include ensuring
that information relating to a customer's choice of retail electric provider,
including data needed for on-going servicing of customer accounts, is conveyed
in a timely manner to the appropriate parties. Problems in the flow of
information between the ERCOT ISO, the transmission and distribution utilities
and the retail electric providers have resulted in delays and other problems in
enrolling and billing customers. While the flow of information has improved
materially over the course of the first year of full market choice operations,
remaining system and process problems are still being addressed. When customer
enrollment transactions are not successfully processed by all involved parties,
ownership records in the various systems supporting the market are not
synchronized properly and subsequent transactions for billing and settlement
are adversely affected. The impact can include us not being the electric
provider-of-record for intended or agreed upon time periods, delays in
receiving customer consumption data that is necessary for billing and
settlement either through the ERCOT ISO or directly with transmission and
distribution utilities, as well as the incorrect application of rates or prices
and imbalances in our electricity supply forecast and actual sales.
The ERCOT ISO is also responsible for handling, scheduling and settlement
for all electricity supply volumes in the ERCOT Region. 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, which
are based, in part, on information supplied by the ERCOT ISO. For additional
information regarding settlement issues, see "Management's Discussion and
Analysis of Financial Condition and Results of Operations--Retail Energy" in
Item 7 of this Form 10-K.
65
Risks Related to Our Wholesale Energy Operations
Our results of operations, financial condition and cash flows are subject to
market risks, the impact of which we cannot fully mitigate.
As part of our merchant generation business, we sell electric energy,
capacity and ancillary services and purchase fuel under short and long-term
contractual obligations and through various spot markets. We are not guaranteed
any rate of return on our capital investments through cost of service rates,
and our results of operations, financial condition and cash flows from these
businesses are subject to market risks, which can be partially mitigated by
hedging long-term sales agreements and other management actions. However, a
substantial portion of market risk remains beyond our control. These market
risks include commodity price risk, counterparty, credit risk, transmission
risk and competitor actions.
We rely on market liquidity and the establishment of valid pricing to properly
manage our risks.
Our commercial businesses depend on sufficient market participation to
establish market liquidity and valid pricing to properly manage the risks
inherent in our businesses. A reduction in the number of market participants
may impair our ability to manage business risks. In addition, such a reduction
may increase our management's reliance on internal models for decision-making.
Our internal models may not adequately represent the markets in which we
participate, potentially causing us to make incorrect decisions. These factors
could have a material adverse effect on our results of operations, financial
condition and cash flows.
We may not be able to satisfy the guarantees and indemnification obligations
relating to our commercial activities if they become due at the same time.
In connection with our commercial businesses, we guarantee or indemnify the
performance of a significant portion of the obligations of certain of our
subsidiaries. For example, we routinely guarantee the obligations of Reliant
Energy Services and other subsidiaries under substantially all of their gas and
electricity trading, marketing and origination contracts. In addition, we have,
from time to time, executed guarantees of the obligations of our subsidiaries
under leases of real property, financing documents and certain other
miscellaneous contracts such as long-term turbine maintenance contracts. Some
of these guarantees and indemnities are for fixed amounts, others have a fixed
maximum amount and others do not specify a maximum amount. The obligations
underlying these guarantees and indemnities are recorded on our consolidated
balance sheet as price risk management liabilities. These obligations make up a
significant portion of these line items. If we were unable to successfully
negotiate lower amounts or alternative arrangements, we would not be able to
satisfy all of these guarantees and indemnification obligations if they were to
come due at the same time. For additional information regarding our guarantees
and indemnification obligations, see note 14(g) to our consolidated financial
statements.
We rely on power transmission and natural gas transportation facilities that we
do not own or control. If these facilities fail to provide us with adequate
transmission capacity, we may not be able to deliver our wholesale power to our
customers or receive natural gas products at our facilities.
We depend on power transmission and distribution and natural gas
transportation facilities owned and operated by utilities and others to deliver
energy products to our customers. Our customers in turn either consume these
products or deliver them to the ultimate consumer. If transmission or
transportation is disrupted, or the capacity is inadequate, our ability to sell
and deliver our products may be hindered.
Increasing competition in wholesale power markets may adversely affect our
results of operations, financial condition, cash flows and may require
additional liquidity to remain competitive .
Our wholesale energy 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
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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. If price information becomes increasingly
available in the energy marketing and trading business, we anticipate that our
operations will experience greater competition and downward pressure on
per-unit profit margins. In addition, our merchant asset business is
constrained by our liquidity, our access to credit and the reduction in market
liquidity. Other companies with which we compete may not have similar
constraints.
Our wholesale energy segment is subject to extensive market regulation. Changes
in these regulations could have a material adverse effect on our business,
results of operations, financial condition and cash flows.
The FERC, which has jurisdiction over wholesale power rates, as well as
independent system operators that oversee some of these markets, has and may
likely continue to impose price limitations, bidding rules and other mechanisms
in an attempt to address some of the price volatility in these markets and
mitigate market price fluctuations. These actions, along with potential changes
to existing mechanisms, could have a materially adverse effect on our results
of operations, financial condition and cash flows.
We operate in a regulatory environment that is undergoing significant
changes as a result of varying restructuring initiatives at both the state and
federal levels. New regulatory policies, which may have a significant impact on
our industry, are now being developed and we cannot predict the future
direction of these changes or the ultimate effect that this changing regulatory
environment will have on our business.
Moreover, existing regulations may be revised or reinterpreted and new laws
and regulations may be adopted or become applicable to our facilities or our
commercial activities. Such future changes in laws and regulations may have a
detrimental effect on our business. In this connection, state officials, the
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 to
force entities with market-based rates to return to cost-based rates, some of
these proceedings are ongoing and we cannot predict what actions the FERC may
take in the future. The impact of receiving cost-based rates on our California
portfolio is also not predictable given that the numerous details of any such
implementation are unknown at this time.
In addition to the FERC investigations, several state and other federal
regulatory investigations are ongoing in connection with wholesale electricity
prices to determine the causes of the high prices and potentially to recommend
remedial action. As these investigations proceed, additional matters could be
discovered that could result in the imposition of restrictions on our business,
fines, penalties or other adverse actions.
The Cal ISO has undertaken, at the FERC's direction, a market redesign
process that includes an ongoing obligation to offer available capacity in Cal
ISO markets, a $250 per MWh price cap, as well as "automated" mitigation of all
bids when any zonal clearing price for balancing energy exceeds $91.87 per MWh.
The automated mitigation is only applied to bids that exceed certain reference
prices and that would significantly increase the market price. However, in
February 2003, the Cal ISO stated that it intends to appeal in federal court
the FERC's decision regarding the application of automated mitigation to local
market power situations. While the FERC has adopted similar thresholds for both
local and system market power, Cal ISO is seeking to have a more restrictive
procedure applied to local market power. Additional features of the California
market redesign to be implemented in the future 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. A new California state statute purports to give the CPUC new power to
regulate the operations and maintenance practices of our California generating
subsidiaries, beyond the existing state regulation, regarding environmental and
other health and safety matters. The CPUC has recently initiated the process of
establishing the methods through which these new requirements will be
administered.
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The NY Market is subject to significant regulatory oversight and control.
The results of our operations in the NY Market are dependent on the continuance
of the current regulatory structure. 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
financial condition, results of operations and cash flows. The primary
regulatory risk in this market is associated with the oversight activity of the
New York Public Service Commission, the 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 electric
energy and ancillary services. The NYISO may in some cases, subject to the FERC
approval, also impose cost-based pricing and/or price caps. The NYISO has
implemented automated mitigation procedures under which day- ahead energy bids
will be automatically reviewed. If bids exceed certain pre-established
thresholds and have a significant impact on the market-clearing price, the bids
are then reduced to a pre-established market-based or negotiated reference bid.
The NYISO has also adopted, at the FERC's direction, more stringent mitigation
measures for all generating facilities in transmission-constrained New York
City.
The FERC has also undertaken a generic review of the terms and conditions of
market-based rates for all sellers. Specifically, in November 2001, the FERC
instituted an investigation regarding the tariffs of all sellers with
market-based rate authority, including us. If the FERC adopts its proposed
approach for addressing anti-competitive behavior, our future earnings may be
adversely affected by an open-ended refund obligation on sales at market-based
rates.
The FERC also instituted a SMD rulemaking proceeding that proposes to
eliminate discrimination in transmission service and to standardize electricity
market design. The FERC's SMD proceeding would 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. Further, this proceeding is also expected to provide
all RTOs specifications regarding the entities that administer these markets
and how these entities perform market monitoring and mitigation. While SMD is a
positive development for our business, significant opposition to SMD has been
voiced, and we cannot predict at this time whether standard market design will
be adopted as proposed or what effect standard market design would have on our
business growth prospects and financial results.
The FERC's RTO initiative, which began in May 1999, is making progress in
all areas of the country. If RTOs are established as envisioned by the FERC,
"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 regions of the
United States to the development of RTOs as envisioned by the FERC, and the
timing for completion of the developing RTOs is uncertain.
Additionally, federal legislative initiatives have been introduced and
discussed to address the problems being experienced in some power markets and
to enhance or limit the FERC authority. We cannot predict whether such
proposals will be adopted or their impact on industry restructuring. 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.
Our costs of compliance with environmental laws are significant and the cost of
compliance with new environmental laws could adversely impact our profitability.
Our wholesale energy segment 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
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numerous governmental permits, in operating our facilities, a number of which
are coal-fired and subject to particularly intense regulatory oversight. 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, results of operations and financial condition and cash flows could be
materially adversely affected. For more information regarding compliance with
environmental laws, see "Business--Environmental Matters" in Item 1 of the Form
10-K.
The majority of our hydroelectric facilities are required to be licensed under
the Federal Power Act. Any failure to obtain or maintain a required license for
one or more of our hydroelectric facilities could have an adverse impact on us.
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.
As a result of events in California over the past few years, our wholesale
power operations in our West region have experienced delays in the collection
of receivables and are subject to uncertainty relating to ongoing litigation
and governmental proceedings.
We are defendants in several class action lawsuits and other lawsuits filed
against us and a number of other companies that either owned generation plants
in California or sold electricity in California markets. These lawsuits
challenge the prices for wholesale electricity in California during parts of
2000 and 2001. The FERC is also continuing its staff investigation into
potential manipulation of electric and natural gas prices in the West region
for the period from January 2000 to June 2001. Some counterparties have
challenged long-term bilateral contracts based on the alleged market
dysfunction in Western power markets in 2000 and 2001.
In addition to the FERC investigations, several state and other federal
regulatory investigations are on-going in connection with the wholesale
electricity prices in California and neighboring Western states to determine
the causes of the high prices and potentially to recommend remedial action.
Finally, a new California state statute purports to give the CPUC new powers to
regulate the operations of our California generating subsidiaries, beyond the
existing state regulation regarding environmental and other health and safety
matters. The CPUC has recently initiated the process of establishing the
methods through which these new requirements will be administered. For
information regarding our receivables for sales in the California market and
uncertainty relating to ongoing legal litigation and investigations, see notes
14(h) and 14(i) to our consolidated financial statements.
As these investigations proceed, additional matters could be discovered that
could result in the imposition of restrictions on our businesses, fines,
penalties or other adverse events.
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Our business operations and hedging activities expose us to the risk of
non-performance by counterparties.
Our trading, marketing and risk management services operations are exposed
to the risk that counterparties who owe us money or physical commodities and
services, 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.
As a result of recent events, including the credit crisis in the merchant
energy sector, decreasing liquidity in our trading markets and the related
downgrading of our credit ratings and the credit ratings of many of our trading
counterparties to below investment grade, we have been required to enter into
trading and other commercial arrangements with higher risk counterparties than
those with whom we have typically contracted in the past. These arrangements,
coupled with the credit crisis in our sector, have increased our exposure to
the risk of non-performance by counterparties who owe us money or physical
commodities.
Operation of power generation facilities involves significant risks that could
negatively affect our results of operations and cash flows.
Our wholesale energy segment and our European energy segment 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. Significant portions
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 to 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 our
operating costs. Any unexpected failure to produce power, including failure
caused by breakdown or forced outage, could have a material adverse effect on
our results of operations, financial condition and cash flows.
Construction of power generation facilities involves significant schedule and
cost risks that could negatively affect our results of operations, financial
condition and cash flows.
Currently, we have four power generation facilities under development or
construction. Our successful completion of these facilities is subject to the
following:
. power prices;
. shortages and inconsistent qualities of equipment, material and labor;
. availability of financing;
. failure of key contractors and vendors to fulfill their obligations;
. 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.
Any of these factors could give rise to delays, cost overruns or the
termination of the plant expansion or construction. 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
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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 governmental permits and approvals is complicated, expensive, lengthy
and subject to significant uncertainties. Transmission interconnection, fuel
supply and cooling water arrangements 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.
The loss of the tolling agreement for our Liberty electric generating station
could have a material adverse impact on our results of operations, financial
condition and cash flows.
The output of our Liberty electric generating station is contracted under a
long-term tolling agreement between LEP and PGET. We have several disputes with
PGET that could result in the termination of the tolling agreement. If the
tolling agreement is terminated, it is possible that Liberty's lenders would
initiate foreclosure proceedings against LEP and Liberty and both Liberty and
LEP may seek other alternatives, including reorganization under the bankruptcy
laws. Such a termination may also result in PGET drawing on the $35 million
letter of credit posted by Reliant Resources on behalf of LEP under the tolling
agreement. For more information regarding this matter, see note 14(l) to our
consolidated financial statements.
Risks Related to Our European Energy Operations
Increasing competition in the Dutch wholesale energy market may adversely
affect our results of operations, financial condition and cash flows.
We expect over the long-run competition for energy customers in the markets
in which our European energy segment operates to be 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, cogenerators, various producers of alternate
sources of power and non-Dutch generators of electric power, primarily from
France and Germany. As of December 31, 2002, 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. 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.
The timing and pace of the deregulation of other sectors of the European energy
markets may have a material adverse effect on our business, results of
operations, financial condition and cash flows.
Commercial markets in the Netherlands 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,
2004. 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
71
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.
There is mark-to-market price risk exposure associated with our stranded cost
gas supply contract.
The stranded cost gas supply contract is indexed to a combination of coal
and inflation and has a foreign exchange exposure. A significant change in the
contract index could have a material adverse effect on our results of
operations, financial condition and cash flows. For additional information
regarding this contract, see note 14(j) to our consolidated financial
statements.
We have exposure to the disposition of certain contingent stranded cost
liabilities pursuant to our ownership interest in NEA.
NEA entered into commitments with certain Norwegian counterparties for the
construction of a grid interconnector cable between the Netherlands and Norway,
subject to the operation of a long-term power exchange agreement (25 years in
duration). For additional information regarding NEA, see note 14(j) to our
consolidated financial statements.
Many of the risks related to our wholesale energy operations equally apply to
our European energy operations.
Our European energy segment is subject to many of the same risks and
uncertainties that confront our wholesale energy segment. In particular, our
European energy segment is subject to similar market risks, hedging risks,
non-performance by counterparties risks, transmission risks, environmental
compliance risks, power generation risks, debt facility compliance risks and
guarantee and indemnification risks related to our trading and marketing
activities. For additional information concerning these risks and
uncertainties, see "Risks Related to Our Wholesale Energy Operations."
Risks Related to Our Businesses Generally
We do not attempt to fully hedge our assets or positions against changes in
commodity prices, and our risk management policies and procedures may not be
effective.
Commodity price risk is an inherent component of our retail and wholesale
energy operations. Our results of operations, financial condition and cash
flows depend, in large part, upon prevailing market prices for electricity and
fuel in our markets. Market prices may fluctuate substantially over relatively
short periods of time, potentially adversely impacting our results of
operations, financial condition and cash flows. Changes in market prices for
electricity and fuel may result from the following:
. weather conditions;
. seasonality;
. demand for energy commodities and general economic conditions;
. forced or unscheduled plant outages;
. disruption of electricity or gas transmission or transportation,
infrastructure or other constraints or inefficiencies;
. addition of generating capacity;
. availability of competitively priced alternative energy sources;
. availability and levels of storage and inventory for fuel stocks;
. natural gas, crude oil and refined products, and coal production levels;
. the creditworthiness or bankruptcy or other financial distress of market
participants;
72
. changes in market liquidity;
. natural disasters, wars, embargoes, acts of terrorism and other
catastrophic events; and
. federal, state and foreign governmental regulation and legislation.
To mitigate our financial exposure related to commodity price fluctuations,
we 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, refined products, and other commodities and
services. As part of this strategy, we routinely utilize derivative instruments
(e.g., fixed-price forward physical purchase and sales contracts, futures,
financial swaps and option contracts). However, we do not expect to cover the
entire exposure of our assets or positions to market price and volatility
changes, 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, the availability of liquidity resources and our view of
market prices.
Our risk management procedures and our hedging strategies are constrained by
our liquidity, our access to credit and the reduction in market liquidity, and
may not be followed or work as planned. These and other factors may adversely
impact our results of operations, financial condition and cash flows.
At times we have open positions in the market (required to be within
established corporate risk management guidelines), resulting from optimizing
our power generation portfolio and eliminating our remaining trading positions.
If we have open positions, changes in commodity prices could negatively impact
our results of operations, financial condition and cash flows. We have measures
and controls in place that are designed to mitigate the impact of commodity
price changes on our positions. These measures and controls are based on
statistical analyses and estimates. Consequently, no assurance can be given
that these controls and measures will be effective in the event that anomalous
commodity price changes occur.
For additional information, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations--Trading and Marketing
Operations," "Quantitative and Qualitative Disclosures About Market Risk" in
Item 7A of this Form 10-K and note 7 to our consolidated financial statements.
The ultimate outcome of the numerous lawsuits and regulatory proceedings to
which we are a party cannot be predicted at this time.
We are party to numerous lawsuits and regulatory proceedings relating to our
trading and marketing activities, including the following:
. certain same-day commodity trading transactions in which we engaged in
1999, 2000 and 2001 involving purchases and sales with the same
counterparty for the same volume at substantially the same price,
referred to as "round trip trades;"
. a series of four structured transactions entered into during the period
May 2001 through September 2001, referred to as "structured
transactions;" and
. our activities in the California wholesale market from January 2000 to
June 2001.
In addition, various state and federal governmental agencies have commenced
investigations relating to these activities. These lawsuits, proceedings and
investigations are currently the subject of intense, highly charged media and
political attention. Their ultimate outcome cannot be predicted at this time.
In addition, these lawsuits, proceedings and investigations could lead to the
discovery of additional conduct or transactions not known at this time that
could result in additional litigation or regulatory action. For additional
information regarding these legal proceedings and investigations, see note
14(h) to our consolidated financial statements.
Our strategic plans may not be successful.
Our future results of operations are dependent on the success of our
strategic plans. Our strategic plans with respect to our wholesale energy
segment indicate a shift in emphasis from identifying and pursuing acquisition
73
and development candidates to completing facilities currently under
construction and integrating recently acquired generation facilities. This
change reflects our current focus on integrating the Orion Power assets with
our other domestic wholesale energy operations, the completion of our
construction projects and our judgments regarding the current state of the
wholesale electricity and capital markets. Our strategy could change to respond
to market conditions or other circumstances. Additionally, our strategic plans
include the evaluation of our option to acquire 81% of Texas Genco from
CenterPoint. Our decision will be based on many factors including the option
price and our ability to finance this acquisition. Our inability to consummate
the acquisition could adversely affect our future results of operations.
If we fail to obtain or maintain any necessary governmental permit or approval,
our results of operations may be adversely affected.
Our operations are subject to complex and stringent energy, environmental
and other governmental laws and regulations. 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 wholesale
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
regulatory commissions regarding environmental and other health and safety
matters. The FERC has authorized us to sell electricity produced 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. Any
reduction by the FERC of the rates we may receive for our generation activities
may materially adversely effect our business, results of operations, financial
condition and cash flows.
Changes in technology may impair the value of our power plants and may
significantly impact our business in other ways as well.
Research and development activities are ongoing to improve alternative
technologies to produce electricity, including fuel cells, microturbines and
photovoltaic (solar) cells. It is possible that advances in these or other
alternative technologies will reduce the costs of electricity production from
these technologies to a level below that which we have forecasted. In addition,
increased conservation efforts and advances in technology could reduce
electricity demand and significantly reduce the value of our power generation
assets. Changes in technology could also alter the channels through which
retail electric customers buy electricity.
Our results of operations, our ability to access capital and insurance and our
future growth prospects could be adversely affected by the occurrence or risk
of occurrence of future terrorist attacks or related 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 military activity 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 cash flows 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 on terms and conditions acceptable to us.
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Our insurance coverage may not be sufficient and our insurance costs may
increase.
We have insurance coverages, subject to various limits and deductibles,
covering our generation facilities, including property damage insurance and
general liability insurance in amounts that we consider appropriate. However,
we cannot assure you that insurance coverage will be available in the future on
commercially reasonable terms or that the insurance proceeds received for any
loss of or any damage to any of our generation facilities will be sufficient to
restore the loss or damage without negative impact on our financial condition
and results of operations. The costs of our insurance coverage have increased
significantly during recent periods and may continue to increase in the future.
The value of our foreign generating facilities and businesses may be reduced by
risks related to laws of other countries, taxes, economic conditions,
fluctuations in currency rates, political conditions, policies of foreign
governments and labor supply and relations.
We have generation facilities in the Netherlands and trading operations in
Northwest Europe. Operations outside the United States entail the following
significant political and financial risks, which vary by country:
. changes in laws or regulations;
. changes in foreign tax and environmental laws and regulations;
. changes in United States laws, including tax laws, related to foreign
operations;
. changes in general economic conditions affecting each country;
. fluctuations in inflation and currency exchange rates;
. changes in government policies or personnel; and
. changes in labor relations in operations outside the United States.
Our actual results may be affected by the occurrence of any of these events.
The occurrence of any of these events could substantially reduce the value of
the impacted generating facilities or businesses.
Risks Related to Our Corporate and Financial Structure
We have significant debt that could negatively impact our business.
We have significant debt outstanding. As of March 31, 2003, we had total
consolidated debt outstanding of $8.6 billion. Our high level of debt could:
. make it difficult for us to satisfy our obligations;
. limit our ability to obtain additional financing to operate our business;
. limit our financial flexibility in planning for and reacting to industry
changes;
. place us at a competitive disadvantage as compared to less leveraged
companies;
. increase our vulnerability to general adverse economic and industry
conditions, including changes in interest rates and volatility in
commodity prices; and
. require us to dedicate a substantial portion of our cash flows to
payments on our debt.
The incurrence of additional debt could make it more likely that we will
experience some or all of the above-described risks. For more information
regarding our outstanding debt, see notes 9 and 21(a) to our consolidated
financial statements.
75
If we do not generate sufficient positive cash flows, we may be unable to
service our debt.
Our ability to pay principal and interest on our debt depends on our future
operating performance. Future operating performance is subject to market
conditions and business factors that often are beyond our control. If our cash
flows and capital resources are insufficient to allow us to make scheduled
payments on our debt, we may have to reduce or delay capital expenditures, sell
assets, seek additional capital or restructure or refinance our debt. We cannot
assure you that the terms of our debt will allow these alternative measures or
that such measures would satisfy our scheduled debt service obligations.
No assurance can be given that we will have sufficient cash flows to pay the
principal, premium, if any, and interest on our debt. If we cannot make
scheduled payments on our debt, we will be in default and, as a result:
. our debt holders could declare all outstanding principal and interest to
be due and payable;
. our senior debt lenders could terminate their commitments and commence
foreclosure proceedings against our assets; and
. we could be forced into bankruptcy or liquidation.
The terms of our debt may severely limit our ability to plan for or respond to
changes in our businesses.
Our March 2003 credit facilities restrict our ability to take specific
actions in planning for and responding to changes in our business without the
consent of our lenders, even if such actions may be in our best interest. Our
March 2003 credit facilities also require us to maintain specified financial
ratios and meet specific financial tests. For more information regarding these
restrictions, see "Management's Discussion and Analysis of Financial Condition
and Result of Operations--Liquidity and Capital Resources--Consolidated Future
Uses and Sources of Cash and Certain Factors Impacting Future Uses and Sources
of Cash" in Item 7 of this Form 10-K and notes 9 and 21(a) to our consolidated
financial statements.
Our failure to comply with these covenants could result in an event of
default that, if not cured or waived, could result in our being required to
repay these borrowings before their due date. If we were unable to make this
repayment or otherwise refinance these borrowings, our lenders could foreclose
on our assets. If we were unable to refinance these borrowings on favorable
terms, our businesses could be adversely impacted.
An increase in short-term interest rates could adversely affect our cash flows.
As of March 31, 2003, we had $7.8 billion of outstanding floating-rate debt.
Because of capital constraints impacting our business at the time some of this
floating-rate debt was entered into, the interest rate margins are
substantially above our historical borrowing margins. In addition, any
floating-rate debt issued by us in the future could be at interest rate margins
substantially above our historical borrowing margins. While we may seek to use
interest rate swaps or other derivative instruments to hedge portions of our
floating-rate debt exposure, we may not be successful in obtaining hedges on
acceptable terms. Any increase in short-term interest rates would result in
higher interest costs and could adversely affect our results of operations,
financial condition and cash flows.
Our non-investment grade credit ratings could adversely impact our ability to
access capital on acceptable terms, optimize our assets and operate our risk
management activities.
Our credit rating has been downgraded to below investment grade. The
downgrading of our credit rating has limited, and will likely continue to
limit, our ability to refinance our debt obligations and access the capital
markets. A number of our commercial contracts and guarantees associated with
our asset optimization and risk management operations require us to satisfy
collateral margin requirements that vary depending on energy market prices and
contract prices. In addition, certain of our contracts with commercial,
industrial and institutional electricity customers give the customer the right
to terminate the contract based on our receiving a below-investment-grade
credit rating from certain ratings agencies. Through March 28, 2003, we have not
76
experienced any contract terminations in our retail energy segment as a result
of downgrades of our credit ratings to below investment grade. As a result of
the downgrading of our credit rating, we may not be able to satisfy future
collateral margin requirements under these contracts and guarantees. For
information regarding our current credit ratings by the major credit agencies
and related future adverse impacts, see "Management's Discussion and Analysis
of Financial Condition and Results of Operations--Liquidity and Capital
Resources--Consolidated Future Uses and Sources of Cash and Certain Factors
Impacting Future Uses and Sources of Cash" in Item 7 of this Form 10-K.
Reliant Resources is a holding company with no operations of its own. As a
result, we depend on distributions from our subsidiaries to make payments on
our debt obligations and meet our other cash requirements. Applicable laws or
contractual restrictions could limit the amount of distributions made to us by
our subsidiaries.
We derive substantially all our operating income from, and hold
substantially all of our assets through, our subsidiaries. As a result, we
depend on distributions of cash flows and earnings of our subsidiaries in order
to meet our payment obligations under our credit facilities and other
obligations. These subsidiaries are separate and distinct legal entities and
have no obligation, unless specifically contracted, to pay any amounts due on
our debts or other obligations, whether by dividends, distributions, loans or
otherwise. Many of our subsidiaries have guaranteed our obligations under our
March 2003 credit facilities to the extent legally and contractually permitted
and are co-borrowers under the new $300 million senior priority revolving
credit facility. The terms of some of our subsidiaries' indebtedness restrict
their ability to pay dividends or make payments to us in some circumstances.
The terms of any new or amended subsidiary indebtedness could further restrict
payments from these subsidiaries. In addition, provisions of applicable law,
such as those limiting the legal sources of dividends, could limit their
ability to make payments or other distributions to us. For additional
information regarding these restrictions, see notes 9 and 21(a) to our
consolidated financial statements.
Our right to receive any assets of any subsidiary will be effectively
subordinated to the claims of that subsidiary's creditors, including trade
creditors. In addition, even if we are a creditor of any subsidiary, our rights
as a creditor are subordinated to the indebtedness of the subsidiary under our
March 2003 credit facilities.
Our historical financial results as a subsidiary of CenterPoint may not be
representative of our results as a separate company.
The historical financial information relating to periods prior to the
Distribution that we have included in this Form 10-K does not necessarily
reflect what our results of operations, financial condition and cash flows
would have been had we been a separate, stand-alone entity during such periods.
Our costs and expenses during such periods reflect charges from CenterPoint for
centralized corporate services and infrastructure costs. These allocations have
been determined based on assumptions that we and CenterPoint considered to be
reasonable under the circumstances. This historical financial information is
not necessarily indicative of what our results of operations, financial
condition and cash flows will be in the future. We may experience significant
changes in our cost structure, funding and operations as a result of our
separation from CenterPoint, including increased costs associated with reduced
economies of scale, and increased costs associated with being a publicly
traded, stand-alone company.
Risks Related to the Sale of Our European Energy Operations
We signed an agreement to sell our European energy operations to Nuon. As in
any sale transaction with regulatory approval as a condition precedent, there
is risk that the sale may be substantially delayed or may not be consummated.
In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon. The sale is subject to the approval of the Dutch and
German competition authorities. We anticipate that the
77
consummation of the sale will occur in the summer of 2003. No assurance can be
given that we will obtain the approval of the Dutch and German competition
authorities or that such approvals can be obtained in a timely manner. For
further information regarding the sale of our European energy operations, see
notes 21(b) and 21(c) to our consolidated financial statements.
There is significant operational, commercial and financial risk to our European
energy operations if the sale to Nuon is not consummated.
If the sale of our European energy operations is not consummated, we may be
significantly impacted by negative market perception regarding an entity with a
sub-investment grade credit rating, which has, directly and indirectly, three
credit facilities that mature during 2003 with an aggregate face value of
approximately $1.3 billion. Key commercial counterparties and vendors may limit
their transactions and exposures with us. No assurance can be given regarding
our ability to successfully or adequately mitigate these risks.
Liquidity and Capital Resources
Historical Cash Flows
The net cash provided by or used in operating, investing and financing
activities for 2000, 2001 and 2002 is as follows:
Year Ended December 31,
------------------------
2000 2001 2002
------- ------ -------
(in millions)
Cash provided by (used in):
Operating activities.... $ 328 $ (127) $ 611
Investing activities.... (3,013) (838) (3,486)
Financing activities.... 2,721 1,000 3,981
Cash Provided by (Used in) Operating Activities
2002 Compared to 2001. Net cash provided by operating activities during
2002 increased $738 million compared to 2001. This increase was primarily due
to $562 million of changes in working capital and other changes in assets and
liabilities and to a lesser extent due to $176 million of changes from cash
flows from operations, excluding changes in working capital and other changes
in assets and liabilities.
Net cash provided by operating activities increased by $562 million from
$825 million in net cash outflows in 2001 to $263 million in net cash outflows
in 2002 due to changes in working capital and other changes in assets and
liabilities due to the following:
. $95 million of net proceeds related to an arrangement with a financial
institution to sell an undivided interest in accounts receivable from
residential and small commercial retail electric customers (see note 15
to our consolidated financial statements);
. $136 million of net collateral deposits related to an operating lease
returned to us in 2002 coupled with net collateral deposits paid in 2001
of $145 million (see note 14(c) to our consolidated financial statements);
. $79 million of reduced lease prepayments in 2002 compared to $181 million
in 2001, related to the REMA sale-leaseback agreements (see note 14(a) to
our consolidated financial statements);
. $121 million related to the settlement of two structured transactions in
2002 coupled with $117 million of related cash outflows due to the
execution of the two structured transactions in 2001 (see note 7(b) to
our consolidated financial statements);
78
. $145 million decrease in restricted cash resulting from Orion Power
utilizing restricted cash to repay certain outstanding borrowings in
connection with the restructuring of the Orion MidWest and Orion NY
facilities in October 2002 (see note 9(a) to our consolidated financial
statements);
. $200 million of cash proceeds received in 2002, excluding $2 million
remaining in escrow, resulting from the settlement of the indemnification
with former shareholders of REPGB of certain stranded costs contracts in
December 2001 (see note 14(j) to our consolidated financial statements);
. $167 million decrease in restricted cash in 2002 coupled with increased
restricted cash of $117 million in 2001 related to our REMA operations
(see notes 2(l) and 14(a) to our consolidated financial statements); and
. $391 million decrease in net cash outflows due to a decrease in cash
outflows associated with accounts payable of $950 million due to the
timing of cash payments, offset by a net decrease in cash inflows
associated with net intercompany accounts receivable of $66 million and
with accounts receivable of $493 million primarily due to our retail
energy segment beginning operations in 2002.
These items were partially offset by the following:
. a $100 million settlement payment made in 2002 related to certain
stranded costs contracts (see note 14(j) to our consolidated financial
statements);
. $125 million in net settlements of hedges of our net investment in
foreign subsidiaries;
. $55 million loss settlement of forward-starting swaps during May and
November of 2002;
. $220 million of cash outflows for margin deposits related to our trading
and hedging activities primarily to provide credit support as a result of
our downgrades to sub-investment grade coupled with cash inflows of $167
million for margin deposits in 2001; and
. other changes in working capital.
Net cash flows from operations, excluding changes in working capital and
other changes in assets and liabilities increased $176 million in 2002 with net
cash inflows of approximately $874 million in 2002, compared to $698 million in
2001, primarily due to the following:
. cash flows provided by our retail energy segment for retail sales during
2002 due to the Texas retail market opening to full competition in
January 2002, partially offset by
. decreased operating cash flows from our wholesale energy segment
primarily due to a $328 million decline in operating margins in 2002
compared to 2001.
2001 Compared to 2000. Net cash provided by operating activities during
2001 decreased by $455 million compared to 2000. This decrease was primarily
due to changes of $779 million in working capital and other changes in assets
and liabilities, offset by changes of $324 million from cash flows from
operations excluding these items. Changes in working capital and other assets
and liabilities in 2001 resulted in net cash outflows of approximately $825
million compared to $46 million in 2000, primarily due to the following:
. a $511 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 our wholesale energy segment in 2001
which was accrued in 2000;
. a $181 million lease prepayment related to the REMA sale-leaseback
agreements (see note 14(a) to our consolidated financial statements);
. $117 million increase in restricted cash related to our REMA operations
(see notes 2(l) and 14(a) to our consolidated financial statements);
79
. $145 million increase in deposits in a collateral account related to an
equipment financing structure (see note 14(b) to our consolidated
financial statements);
. $117 million of net cash outflows related to the execution of two
structured transactions in 2001 (see note 7(b) to our consolidated
financial statements); and
. 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.
Cash flows from operations, excluding changes in working capital and other
changes in assets and liabilities, were approximately $698 million in 2001
compared to approximately $374 million in 2000. This increase was primarily due
to a $488 million increase in operating margins from our wholesale energy
segment's power generation operations in 2001 compared to 2000. This increase
was partially offset by increased costs related to our retail energy segment'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 margins
as the Dutch electric market was completely opened to wholesale competition on
January 1, 2001.
Cash Used in Investing Activities
2002 Compared to 2001. Net cash used in investing activities increased by
$2.6 billion during 2002 compared to 2001. This increase was primarily due to
funding the acquisition of Orion Power for $2.9 billion, partially offset by
reduced capital expenditures of $179 million related to decreased construction
of domestic power generation projects and capital expenditures by our retail
energy segment related to acquiring and developing information technology
systems during 2002 as compared to 2001 and a $137 million cash dividend
received in 2002 from our European energy segment's equity investment in NEA
(see note 8 to our consolidated financial statements).
2001 Compared to 2000. 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.
Acquisition of Orion Power Holdings, Inc. On February 19, 2002, we acquired
all of the outstanding shares of common stock of Orion Power for an aggregate
purchase price of $2.9 billion and assumed debt obligations of $2.4 billion. As
of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of restricted cash pursuant to debt covenants). We funded the
purchase of Orion Power with a $2.9 billion credit facility and $41 million of
cash on hand. For further discussion, see note 5(a) to our consolidated
financial statements.
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 through bridge
loans from CenterPoint, of which $1.0 billion was converted to equity. In
August 2000, we entered into three separate sale-leaseback transactions with
each of the three owner-lessors for our interests in three generating stations,
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 CenterPoint. For
additional information about the acquisition and these transactions, see notes
5(b) and 14(a) to our consolidated financial statements.
Acquisition of REPGB. 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)
80
three-year term loan facility established in February 2000. For more
information about the acquisition of REPGB, see note 5(c) to our consolidated
financial statements.
Cash Provided by Financing Activities
2002 Compared to 2001. Cash flows provided by financing activities
increased $3.0 billion in 2002 compared to 2001, primarily due to an increase
in short-term borrowings used to fund the acquisition of Orion Power and other
working capital requirements as well as to fund increased working capital in
order to meet future obligations. In addition, we had decreased investments of
excess cash in an affiliate of CenterPoint and decreases in purchases of
treasury stock. These items were partially offset by $1.7 billion in net
proceeds from our IPO in 2001 and $238 million increase in long-term debt
repayments in 2002 compared to 2001.
2001 Compared to 2000. Cash flows provided by financing activities
decreased by $1.7 billion in 2001 compared to 2000, primarily due to a decrease
in borrowings from CenterPoint coupled with advancing excess cash on a
short-term basis to a subsidiary of CenterPoint which provides a cash
management function for CenterPoint, reduced contributions from CenterPoint,
and 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 the wholesale
energy segment's capital expenditures and for general corporate purposes, and
by $1.7 billion in net proceeds from the IPO.
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 CenterPoint, we used $147 million of the net proceeds
to repay certain indebtedness owed to CenterPoint. Proceeds not initially
utilized from the IPO during 2001 were advanced on a short-term basis to
CenterPoint, which provided a cash management function. As of December 31,
2001, we had $390 million of outstanding advances to CenterPoint. During 2001
and 2002, the IPO proceeds were used for repayment of third party borrowings,
repurchase of our common stock, capital expenditures and payment of taxes,
interest and other payables. In May 2001, prior to the closing of the IPO,
CenterPoint converted to equity or contributed to us an aggregate of $1.7
billion of indebtedness owed by us to CenterPoint of which $35 million was
related to accrued intercompany interest expense. Following the IPO,
CenterPoint no longer provided financing or credit support for us, except for
specified transactions or for a limited period of time. For additional
information, see note 3 to our consolidated financial statements.
Orion Power's Subsidiaries Amended and Restated Credit Facilities. During
October 2002, we terminated the Orion Power revolving senior credit facility
and, as part of the same transaction, we refinanced the Orion MidWest credit
facility and the Orion NY credit facility and extended their maturities until
October 2005. In connection with this refinancing, we paid $145 million of
outstanding borrowings under the related facilities. For further discussion
regarding this refinancing, see note 9(a) to our consolidated financial
statements.
Convertible Senior Notes. As of the Orion Power acquisition date, Orion
Power had outstanding $200 million of aggregate principal amount of 4.5%
convertible senior notes, due on June 1, 2008. Pursuant to certain change of
control provisions, Orion Power commenced an offer to repurchase the
convertible senior notes on March 1, 2002, which expired on April 10, 2002.
During the second quarter of 2002, we repurchased $189 million in principal
amount under the offer to repurchase. During the fourth quarter of 2002, the
remaining $11 million aggregate principal amount of these notes were
repurchased for $8 million. For additional information, see note 9(c) 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 a $189 million
aggregate purchase price. For additional information, see note 10(b) to our
consolidated financial statements.
81
Consolidated Capital Requirements
Our liquidity and capital requirements are affected primarily by our results
of operations, capital expenditures, debt service requirements, working capital
needs and collateral requirements. We expect to complete the construction of
new generation facilities that are in progress; however, the refinanced and new
credit facilities entered into in March 2003 restrict the construction of any
new generation facilities in the future. Subject to restrictions in our March
2003 credit facilities, maintenance of plants will continue to include costs
necessary to operate the plants safely, including necessary environmental
expenditures. We will evaluate opportunities to enter retail electric markets
for large commercial, industrial and institutional customers, in particular, in
regions in which we have electric generating facilities and capacity. Subject
to restrictions in our March 2003 credit facilities, we may buy or acquire mass
market customers in ERCOT. We expect our capital requirements to be met with
cash flows from operations, borrowings under our senior secured revolving
credit facility and proceeds from one or more debt and equity offerings,
securitization of assets and other borrowings. We believe that our current
level of cash and borrowing capability, along with our future anticipated cash
flows from operations, will be sufficient to meet the existing operational and
collateral needs of our business for the next 12 months. Subject to
restrictions in our March 2003 credit facilities, if cash generated from
operations is insufficient to satisfy our liquidity requirements, we may seek
to sell assets, obtain additional credit facilities or other financings and/or
issue additional equity or convertible instruments. For additional discussion
regarding our capital commitments, see note 14(f) to our consolidated financial
statements.
The following table sets forth our consolidated capital and operational and
major maintenance expense requirements for 2002, and estimates of our
consolidated capital and operational and major maintenance expense requirements
for 2003 through 2007, excluding the purchase of Texas Genco (in millions):
2002 2003 2004 2005 2006 2007
---- ---- ---- ---- ---- ----
Retail energy................. $ 33 $ 21 $ 21 $ 20 $ 20 $ 20
Wholesale energy (1)(2)....... 532 680 174 70 108 98
European energy (3)........... 19 34 11 16 56 16
Other operations.............. 77 43 24 17 17 17
Major maintenance cash outlays 80 116 139 177 100 156
---- ---- ---- ---- ---- ----
Total......................... $741 $894 $369 $300 $301 $307
==== ==== ==== ==== ==== ====
- --------
(1) In connection with our separation from CenterPoint, CenterPoint granted us
an option to purchase all of the shares of capital stock of Texas Genco
owned by CenterPoint in January 2004. Texas Genco holds the Texas
generating assets of CenterPoint's electric utility division. The purchase
of Texas Genco has been excluded from the above table. For additional
information regarding this option to purchase Texas Genco, see note 4(b) to
our consolidated financial statements.
(2) We currently estimate the capital expenditures by off-balance sheet special
purpose entities to be $349 million and $45 million in 2003 and 2004,
respectively. Estimated capital expenditures for 2003 and 2004 for these
projects have been included in the table above as we consolidated these
special purpose entities effective January 1, 2003 upon the adoption of FIN
No. 46. See note 14(b) to our consolidated financial statements for
additional information regarding these transactions.
(3) In February 2003, we signed an agreement to sell our European energy
operations. For further information, see "Consolidated Future Uses and
Sources of Cash and Certain Factors Impacting Future Uses and Sources of
Cash" within this section and note 21(b) to our consolidated financial
statements.
Generating Projects. As of December 31, 2002, we had one generating
facility under construction on our consolidated balance sheet. Total estimated
cost of constructing this facility is $486 million. As of December 31, 2002, we
had incurred $332 million of the total projected costs of this project, which
was funded from equity and corporate debt. In addition to this generating
facility, we are constructing three facilities under construction agency
agreements through off-balance sheet special purpose entities to be completed
in 2003 and 2004. As of December 31, 2002, the off-balance sheet special
purpose entities had incurred $1.3 billion in construction costs, property,
plant and equipment and spare parts inventory. We consolidated these special
purpose entities effective January 1, 2003 upon the adoption of FIN No. 46. We
expect to spend approximately an additional $420 million in order to complete
these facilities. For more information regarding the construction agency
agreements, see notes 2(t), 14(b) and 21(a) to our consolidated financial
statements.
82
Environmental Expenditures. We anticipate spending up to $178 million in
capital and other special project expenditures from 2003 through 2007 for
environmental compliance, totaling approximately $36 million, $37 million, $16
million, $63 million and $26 million in 2003, 2004, 2005, 2006 and 2007,
respectively, which is included in the above table. In addition, we expect to
spend $30 million (which is not included in the table above) from 2003 through
2007 for pre-existing conditions and remediations, which are recorded as
liabilities in our consolidated balance sheet.
Texas Genco Option. In connection with the separation of our businesses
from those of CenterPoint, CenterPoint granted us an option to purchase all of
the shares of capital stock of Texas Genco owned by CenterPoint in January
2004. If we exercise our purchase option, our March 2003 credit facilities
would require us to fund the purchase obligation solely with proceeds from
permitted asset sales, including our European energy operations, proceeds from
subordinated debt and equity offerings, a limited recourse acquisition
financing and/or borrowings at Texas Genco (or its intermediate holding
company). If we are not able to realize such proceeds, we do not expect that we
will be able to exercise the option. If we do not exercise the option, we will
need to continue to contract with Texas Genco or others to meet some of our
retail supply obligations. For additional information regarding this option to
purchase CenterPoint's interest in Texas Genco, see note 4(b) to our
consolidated financial statements.
The following table sets forth estimates to our consolidated contractual
obligations as of December 31, 2002 to make future payments for 2003 through
2008 and thereafter:
2008 and
Contractual Obligations Total 2003 2004 2005 2006 2007 thereafter
----------------------- ------- ------ ------ ------ ------ ------ ----------
(in millions)
Debt, including credit facilities....... $ 7,356 $1,423 $ 170 $1,096 $ 515 $3,432 $ 720
Mid-Atlantic generating assets operating
lease payments........................ 1,424 77 84 75 64 65 1,059
Other operating lease payments.......... 804 85 91 89 87 62 390
Trading and marketing liabilities....... 782 542 159 49 19 5 8
Non-trading derivative liabilities...... 658 343 138 40 24 13 100
Other commodity commitments............. 3,607 1,073 410 381 302 110 1,331
Payment to CenterPoint.................. 175 -- 175 -- -- -- --
Stadium naming rights................... 276 10 10 10 10 10 226
Other................................... 5 5 -- -- -- -- --
------- ------ ------ ------ ------ ------ ------
Total contractual cash obligations...... $15,087 $3,558 $1,237 $1,740 $1,021 $3,697 $3,834
======= ====== ====== ====== ====== ====== ======
For discussion of the refinancing of certain facilities in March 2003, the
effects of which are reflected above, see note 21(a) to our consolidated
financial statements and discussions below. During October 2005, the Orion
MidWest and Orion NY credit facilities will mature. Included in the above table
for debt contractual obligations in 2005 is $1.1 billion of Orion MidWest and
Orion NY credit maturities. We believe that Orion MidWest's and Orion NY's
future anticipated cash flows from operations will be sufficient to prepay a
substantial portion of the outstanding borrowings under these credit
facilities. Upon maturity of these facilities, we anticipate refinancing any
remaining outstanding borrowings.
Mid-Atlantic Assets Lease Obligation. In August 2000, we entered into
separate sale-leaseback transactions with each of the three owner-lessors for
our applicable interests in three generating stations, which we acquired as
part of the REMA acquisition. For additional discussion of these lease
transactions, see notes 5(b) and 14(a) to our consolidated financial statements.
Other Operating Lease Commitments. For a discussion of other operating
leases, see note 14(a) to our consolidated financial statements.
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Other Commodity Commitments. For a discussion of other commodity
commitments, see note 14(f) to our consolidated financial statements.
Payment to CenterPoint. To the extent that our price to beat for electric
service to residential and small commercial customers in CenterPoint's Houston
service territory during 2002 and 2003 exceeds the market price of electricity,
we may be required to make a payment to CenterPoint in 2004. As of December 31,
2002, our estimate for the payment related to residential customers is between
$160 million and $190 million, with a most probable estimate of $175 million.
For additional information regarding this payment, see note 14(e) to our
consolidated financial statements.
Naming Rights to Houston Sports Complex. In October 2000, we acquired the
naming rights for a football stadium and other convention and entertainment
facilities included in the stadium complex. Starting in 2002 and continuing
through 2032, we pay $10 million each year for annual advertising under this
agreement. For additional information on the naming rights agreement, see note
14(f) to our consolidated financial statements.
Consolidated Future Uses and Sources of Cash and Certain Factors Impacting
Future Uses and Sources of Cash
During 2002, many factors negatively impacted us. These factors included
weaker pricing for electric energy, capacity and ancillary services, coupled
with a narrowing of the spark spread in the United States; market contraction,
reduced volatility and reduced liquidity in the power trading markets in the
United States and Northwest Europe; downgrades in our credit ratings to below
investment grade by each of the major rating agencies; various legal and
regulatory investigations and proceedings (see notes 14(h) and 14(i) to our
consolidated financial statements); reduced market confidence in our financial
reporting in light of our restatements and amendments; reduced access to
capital and increased demands for collateral in connection with our trading,
hedging and commercial obligations; the decline in market prices of our common
stock; and continued weakness in the United States economy generally. Certain
of these factors are discussed in more detail below.
Future acquisitions and development projects are restricted under our credit
facilities. Although we are required to dedicate a substantial portion of our
cash flows to payments on our debt, we currently expect to be able to complete
the generation facilities currently under construction, as well as meet our
currently anticipated capital expenditure and working capital needs without
additional funding; however, we do have the ability to borrow additional funds,
subject to certain restrictions in our March 2003 credit facilities, to fund
our future capital expenditure and working capital needs.
We may 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 under restrictions in our March 2003 credit
facilities or 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 (subject to restrictions in our credit
facilities) or we may need to issue equity or convertible instruments, thereby
diluting the interests of current shareholders. Increases in our debt levels
may further adversely affect our credit ratings thereby further increasing the
cost of our debt. In addition, the capital constraints currently impacting our
industry may require additional future indebtedness to include terms and/or
pricing that is more restrictive or burdensome than those of our current
indebtedness and refinancings in March 2003. This may negatively impact our
ability to operate our business, or severely restrict or prohibit distributions
from our subsidiaries.
As a result of our March 2003 refinancing, our interest expense will
increase substantially. The exact amount of the increase is difficult to
estimate and will depend on a variety of factors, some of which are not within
our control, such as prevailing interest rates. However, a comparison of the
LIBOR interest rate margins
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under our Orion acquisition term loan (which was included in our March 2003
refinancing) and our March 2003 senior secured term loans illustrates the
possible magnitude of the interest expense increase. The interest rate margin
over LIBOR was 2% for the Orion acquisition term loan and is 4% for the March
2003 senior secured term loans, equivalent to an interest expense difference of
$20 million annually for each $1 billion of principal amount. For additional
information concerning our March 2003 refinancing and the facilities that were
refinanced, including applicable principal amounts and interest rates, see
notes 9 and 21(a) to our consolidated financial statements.
Our March 2003 credit facilities are payable as follows:
Date Payment required
- ---- ----------------
Earlier of our acquisition of Texas Genco or
December 15, 2004......................... Senior priority revolving credit facility must be repaid
May 15, 2006................................ $500 million of senior secured term loans must be
repaid
March 15, 2007.............................. Remaining senior secured term loans and senior
secured revolving credit facility must be repaid
In addition, under our March 2003 credit facilities, certain warrants issued
to our lenders would vest, and we would be required to pay our lenders certain
fees, if we do not, on or before the dates set forth below, repay our senior
secured term loans and/or permanently reduce the commitment under our senior
secured revolving credit facility in the aggregate paydown/reduction amounts
set forth below. The fees set forth below are a percentage of the unpaid senior
secured term loans and the commitment in effect under the senior secured
revolving credit facility, in each case as of the date indicated. The warrants
set forth below are exercisable for shares of our common stock representing the
indicated percentage of our outstanding common stock on a fully-diluted basis
as of the closing of the refinancing (after giving effect to all warrants
issued to our lenders on that date).
Aggregate
Date paydown/reduction Fees Warrants
---- ----------------- ---- --------
March 31, 2003 -- -- 2.5%(1)
May 14, 2004.. $0.5 billion 0.50% --
May 16, 2005.. $1.0 billion 0.75% 2.0%(2)
May 15 , 2006. $2.0 billion 1.00% 2.0%(2)
- --------
(1) These warrants vested upon closing of our March 2003 credit facilities.
(2) These warrants vest only if we fail to satisfy the indicated aggregate
paydown/reduction amount on or before the indicated date.
The exercise prices of the warrants are based on average market prices of
our common stock during specified periods in proximity to the paydown/reduction
dates. The warrants are exercisable for a period of five years from the date
they become vested.
Our ability to arrange debt and equity financing and our cost of capital are
dependent on the following factors, without limitation:
. general economic and capital market conditions;
. acceptable credit ratings;
. credit availability and access to liquidity from banks and access to the
capital markets;
. the success of our retail energy and wholesale energy segments'
operations;
. investor, supplier and customer 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;
. provisions of relevant tax and securities laws; and
. impact of lawsuits, investigations and other proceedings.
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Our March 2003 credit facilities restrict our ability to take specific
actions without the consent of our lenders, even if such actions may be in our
best interest. Subject to certain exceptions, these restrictions limit our
ability to, among other things:
. incur additional liens or make additional negative pledges on our assets;
. merge, consolidate or sell our assets;
. issue additional debt or engage in sale and leaseback transactions;
. pay dividends, repurchase capital stock or prepay other debt;
. make investments or acquisitions;
. engage in construction development activities in respect of power plants;
. enter into transactions with affiliates, except on an arm's length basis;
. make capital expenditures;
. materially change our business;
. amend our debt and other material agreements in certain respects;
. issue and sell capital stock; and
. engage in certain types of trading activities.
Credit Facilities.
As of December 31, 2002, we had $7.9 billion in committed credit facilities
of which $315 million was unused. As of December 31, 2002, letters of credit
outstanding under these facilities aggregated $677 million and borrowings
aggregated $6.9 billion. As of December 31, 2002, $5.1 billion of our committed
credit facilities were to expire by December 31, 2003. For a discussion of the
refinancing and amendments of certain of these committed credit facilities in
March 2003, see note 21(a) to our consolidated financial statements.
Currently, we are satisfying our capital requirements and other commitments
primarily with cash from operations, cash on hand and borrowings available
under our credit facilities. The following table summarizes our credit capacity
and liquidity position at December 31, 2002.
Reliant Orion European
Total Resources Power Energy(2) Other
------ --------- ------ --------- -----
(in millions)
Total committed credit....... $7,900 $4,508 $1,715 $1,244 $433
Outstanding borrowings....... 6,908 4,266 1,639 630 373
Outstanding letters of credit 677 235 31 373 38
------ ------ ------ ------ ----
Unused borrowing capacity.... 315 7 45 241 22
Cash and cash equivalents.... 1,227 657 7 112 451
Current restricted cash (1).. 219 -- 200 6 13
------ ------ ------ ------ ----
Total available liquidity.... $1,761 $ 664 $ 252 $ 359 $486
====== ====== ====== ====== ====
- --------
(1) Current restricted cash includes cash at certain subsidiaries that is
restricted by financing agreements, but is available to the applicable
subsidiary to use to satisfy certain of its obligations.
(2) The results of our European energy segment are consolidated on a one-month
lag basis.
Refinancings of Credit Facilities in March 2003.
During March 2003, we refinanced our (a) $1.6 billion senior revolving
credit facilities (see note 9(a) to our consolidated financial statements), (b)
$2.9 billion 364-day Orion acquisition term loan (see note 9(a) to our
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consolidated financial statements), and (c) $1.425 billion construction agency
financing commitment (see note 14(b) to our consolidated financial statements),
and we obtained a new $300 million senior priority revolving credit facility.
The refinancing combined the existing credit facilities into a $2.1 billion
senior secured revolving credit facility, a $921 million senior secured term
loan, and a $2.91 billion senior secured term loan. The refinanced credit
facilities mature in March 2007. The $300 million senior priority revolving
credit facility matures on the earlier of our acquisition of Texas Genco or
December 15, 2004. For further discussion of this refinancing, see note 21(a)
to our consolidated financial statements.
Restricted Cash.
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. For information regarding restricted cash and the related credit
facilities, see notes 2(l) and 9(a) to our consolidated financial statements.
Credit Ratings.
As of April 2, 2003 our credit ratings for our senior unsecured debt are as
follows:
Date Assigned Rating Agency Rating Rating Description
------------- ------------- ------ ------------------
November 25, 2002 Moody's B3 Review for possible downgrade
April 2, 2003.... Standard & Poor's (1) B CreditWatch Developing
April 1, 2003.... Fitch CCC+ Rating Watch Positive
- --------
(1) Standard & Poor's did not issue a credit rating on our senior unsecured
debt; this credit rating is a corporate credit rating for Reliant Resources.
The credit ratings of our subsidiaries have been affected as well. As of
April 2, 2003, the REMA lease certificates were rated B by Standard & Poor's
and B3 by Moody's. The ratings remain on "CreditWatch Developing" and "review
for possible downgrade", respectively. As of April 2, 2003, the RECE long-term
issuer was rated B3 by Moody's. The rating remains on "review for possible
downgrade." The Standard & Poor's corporate rating was B and remains on
"CreditWatch Developing." As of April 2, 2003, the long-term issuer rating
assigned by Moody's to REPGB was B1. The senior unsecured bank loan rating
assigned by Standard & Poor's was B+ and remains on "CreditWatch Positive." As
of April 2, 2003, the Moody's senior unsecured debt rating for Orion Power was
B3. The rating remains on "review for possible downgrade." Standard & Poor's
senior unsecured debt and corporate ratings for Orion Power were CCC+ and B,
respectively. These ratings remain on "CreditWatch Developing."
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 the rating agencies. 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 been adversely impacted by our previous downgrade to sub-investment
grade in connection with certain commercial agreements and certain bank
facilities. The commercial arrangements primarily include: (a) commercial
contracts and/or guarantees related to our wholesale and retail trading,
marketing, risk management and hedging activities and (b) surety bonds and
contractual obligations related to the development and construction or
refurbishment of power plants and related facilities. Certain bank facilities
contain provisions whereby our interest rate margins are affected by our credit
ratings. Due to the various downgrades, we have incurred additional interest
expense.
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In most cases, the consequences of rating downgrades are limited to the
requirement by our counterparties that we provide credit support to them in the
form of a pledge of cash collateral, a letter of credit or other similar credit
support. In addition, certain of our retail electricity contracts with large
commercial, industrial and institutional customers in the retail energy segment
permit the customers to terminate their contracts once our unsecured debt
ratings fall below investment grade or if our ratings are withdrawn entirely by
a rating agency. As of March 20, 2003, no retail contracts have been terminated
pursuant to these terms. In light of the credit rating downgrades, we are
working with our various commercial counterparties to minimize the disruption
to our normal commercial activities and to reduce the magnitude of the
collateral we must post in support of our obligations to such counterparties.
In connection with our domestic commercial operations, as of March 20, 2003,
we have posted cash collateral of $500 million and letters of credit of $286
million from Reliant Resources' facilities. Of these letters of credit, $134
million are drawn on a cash-secured, revolving letter of credit facility
initiated on January 29, 2003, see note 21(f) to our consolidated financial
statements. In addition, we have posted cash collateral related to commercial
operations of $4 million and letters of credit of $30 million from Orion Power
subsidiary facilities. We have also posted $371 million of letters of credit
from subsidiary facilities in connection with the support of financings. Based
on current commodity prices, we estimate that as of March 20, 2003, we could be
required to post additional collateral of up to $222 million related to our
domestic operations. This estimate could increase based on changes to commodity
prices. Factors which could lead to an increase in our actual posting of
collateral include adverse changes in our industry or negative reactions to
additional credit rating downgrades or the secured nature of the refinancing of
our debt facilities.
For our European operations, as of March 20, 2003, we have posted cash
collateral and letters of credit in the amount of $49 million and $455 million,
respectively, to support commercial operations. Of these letters of credit, $37
million are drawn under uncommitted banking arrangements. Additionally, we have
posted letters of credit of $363 million under a separate facility to support
cross border lease transactions. Based on current commodity prices, we estimate
that as of March 20, 2003, we could be required to post additional collateral
of up to $7 million related to our European operations. This estimate could
increase based on changes to commodity prices. Factors which could lead to an
increase in our actual posting of collateral include adverse changes in our
industry or negative reactions to additional credit rating downgrades or the
secured nature of the refinancing of our debt facilities. As of March 20, 2003,
we had $86 million in unrestricted available cash and cash equivalents and $178
million available under committed European facilities to support European
operations. These amounts are currently available to meet working capital needs
and possible future requirements for credit support related to our European
commercial obligations.
We believe that our current level of cash and borrowing capability, along
with our future anticipated cash flows from operations, will be sufficient to
meet the liquidity needs of our business for the next twelve months. Under
certain unfavorable commodity price scenarios, however, it is possible that we
could experience inadequate liquidity.
In addition, we have been involved in certain commercial activities
(including long-term sales of electric energy or capacity from our generating
facilities) that prospectively may not be feasible due to our current credit
and liquidity situation, among other factors. The credit downgrades have also
resulted in more limited access to credit worthy counterparties with which to
transact and the need to make commercial concessions with counterparties as an
inducement for them to do business with us. Given these factors, we had reduced
the level of our trading, marketing and hedging activities, which will result
in a potential reduction and greater volatility in future earnings.
In March 2003, we decided to exit our proprietary trading activities and
liquidate, to the extent practicable, our proprietary positions. Although we
are exiting the proprietary trading business, we have existing positions, which
will be closed as economically feasible or in accordance with their terms. We
will continue to engage in hedging activities related to our electric
generating facilities, pipeline storage positions and fuel positions.
It is likely that, in order to exercise the Texas Genco option as permitted
under our credit facilities, we may sell some of our assets. We have identified
certain non-strategic generating assets for potential sale. To date, we have
not reached an agreement to dispose of any significant assets nor have we
included or assumed any
88
proceeds from asset sales in our current liquidity plan, other than the sale of
our European energy operations (see note 21(b) to our consolidated financial
statements). Due to unfavorable market conditions in the wholesale power
markets, there can be no assurance that we will be successful in disposing of
domestic generating assets at reasonable prices or on a timely basis.
Other Sources and Uses of Cash and Factors Impacting Cash.
Sale of our European Energy Operations. In February 2003, we signed a
purchase agreement to sell our European energy operations to Nuon, a
Netherlands-based electricity distributor. Upon consummation of the sale, we
expect to receive cash proceeds from the sale of approximately $1.2 billion
(Euro 1.1 billion). We intend to use the cash proceeds from the sale first to
prepay the Euro 600 million bank term loan borrowed by Reliant Energy Capital
(Europe), Inc. to finance a portion of the acquisition costs of our European
energy operations. The maturity date of the credit facility, which originally
was scheduled to mature in March 2003, has been extended (see notes 9(a) and
21(c) to our consolidated financial statements). We intend to use the remaining
cash proceeds of approximately $0.5 billion (Euro 0.5 billion) to partially
fund our option to acquire Texas Genco in 2004 (see note 4(b) to our
consolidated financial statements). However, if we do not exercise the option,
we will use the remaining cash proceeds to prepay debt. Certain approvals are
needed for the sale to occur. No assurance can be given that we will obtain the
necessary approvals or that they can be obtained in a timely manner. For
further discussion of the sale, see note 21(b) to our consolidated financial
statements.
Generating Capacity Auction Line of Credit. On October 1, 2002, our retail
energy segment, through a subsidiary, entered into a master power purchasing
contract with Texas Genco covering, among other things, our purchases of
capacity and/or energy from Texas Genco's generating facilities. In connection
with the March 2003 refinancing, this contract has been amended to grant Texas
Genco a security interest in the accounts receivable and related assets of
certain retail energy segment subsidiaries, the priority of which is subject to
certain permitted prior financing arrangements, and the junior liens granted to
the lenders under the March 2003 refinancing. In addition, many of the covenant
restrictions contained in the contract were removed in the amendment.
California Trade Receivables and the FERC Refunds. As of December 31, 2002,
we were owed a total receivable, including interest, of $120 million (net of
estimated refund provision) 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, 2002. As of December 31,
2002, we had a $6 million pre-tax credit provision against these receivable
balances. From January 1, 2003 through March 31, 2003, we have collected $7
million of these receivable balances. For additional information regarding
these receivables and uncertainties in the California wholesale market, see
notes 14(h) and 14(i) to our consolidated financial statements.
During 2002, we recorded $176 million in reserves for potential refunds owed
by us, which excludes the $14 million settlement reached with the FERC in
January 2003 relating to two days of trading in 2000 (see note 14(h) to our
consolidated financial statements). Our inception-to-date reserve for such
refunds totals $191 million as of December 31, 2002. We estimate the range of
our refund obligations for California energy sales to be approximately $191
million to $240 million (excluding the $14 million refund related to the FERC
settlement in January 2003). For additional information regarding the FERC
refunds, see note 14(i) to our consolidated financial statements.
Counterparty Credit Risk. For a discussion of our counterparty credit risk,
see "Management's Discussion and Analysis of Financial Conditions and Results
of Operations--Trading and Marketing Operations."
Receivables Facility Covenant Violation. For discussion of a covenant
violation under the receivables facility, see note 15 to our consolidated
financial statements.
Liberty Electric Generating Station Contingency. The output of the Liberty
Station is contracted under a tolling agreement between Liberty Electric Power,
LLC, a wholly-owned indirect subsidiary of Orion Power, and
89
PG&E Energy Trading-Power, LP for a term of approximately 14 years, with an
option to extend at the end of the term. For information regarding this tolling
agreement, issues related to the financing of the Liberty Station and other
related contingencies, including foreclosure concerns, see note 14(l) to our
consolidated financial statements.
Reliant Energy Desert Basin Contingency. REDB sells capacity to Salt River
Project under a long-term power purchase agreement. We guarantee certain of
REDB's obligations under the power purchase agreement. As a result of our
credit downgrade to below investment grade by two major ratings agencies, Salt
River Project has requested performance assurance in the form of cash or a
letter of credit from REDB under the power purchase agreement and from Reliant
Resources under the guarantee. Under the power purchase agreement and
guarantee, the total amount of performance assurance cannot exceed $150
million. For information regarding REDB's obligations, our related guarantee
and other related contingencies, see note 14(k) to our consolidated financial
statements.
Other Items. For other items that may affect our future cash flows from
operations, see "--Risk Factors."
Off-Balance Sheet Transactions
Construction Agency Agreements and Equipment Financing Structure. 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 three power generation projects. As of December 31, 2002, we did
not consolidate the results of the special purpose entities in our consolidated
financial statements. Effective January 1, 2003, upon the adoption of FIN No.
46, we began consolidating these special purpose entities. For information
regarding these transactions and the refinancing in March 2003, see notes 14(b)
and 21(a) to our consolidated financial statements.
Receivables Facility Agreement. In July 2002, we entered into a receivables
facility arrangement with a financial institution to sell an undivided interest
in accounts receivable from residential and small commercial retail electric
customers under which, on an ongoing basis, the financial institution will
invest a maximum of $125 million for its interest in such receivables. Pursuant
to this receivables facility, we formed a QSPE as a bankruptcy remote
subsidiary. For additional information regarding this transaction, see note 15
to our consolidated financial statements.
REMA Sales/Leaseback Transactions. In August 2000, we entered into separate
sale/leaseback transactions with each of the three owner-lessors for our
interests in three generating stations acquired in the REMA acquisition. For
additional discussion of these lease transactions, see note 14(a) to our
consolidated financial statements.
New Accounting Pronouncements, Significant Accounting Policies and Critical
Accounting Estimates
New Accounting Pronouncements
For discussion regarding new accounting pronouncements that impact us, see
note 2(t) to our consolidated financial statements.
Significant Accounting Policies
For discussion regarding our significant accounting policies, see note 2 to
our consolidated financial statements.
Critical Accounting Estimates
Our consolidated financial statements have been prepared in accordance with
GAAP. The preparation of these financial statements requires that we make
estimates and judgments that affect the reported amounts of
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assets, liabilities, revenues and expenses and related disclosure of contingent
assets and liabilities at the date of our financial statements. Estimates and
assumptions about future events and their effects cannot be perceived with
certainty. On an on-going basis, we evaluate our estimates based on historical
experience, current market conditions and on various other assumptions that we
believe to be reasonable under the circumstances, the results of which form the
basis for making judgments about the carrying values of assets and liabilities
that are not readily apparent from other sources. Nevertheless, actual results
may differ from these estimates under different assumptions or conditions.
A critical accounting estimate is (a) one that requires assumptions that are
highly uncertain at the time the estimate is made and (b) one in which
different estimates could have reasonably been used in the current period, or
changes in the accounting estimate that are reasonably likely to occur, which
would have a material impact on the presentation of our financial condition or
results of operations. Our 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 our critical accounting estimates are
limited to those described below. Our senior management has discussed the
development and selection of the estimate of each of our critical accounting
estimates with our audit committee of the board of directors. For a detailed
discussion on the application of these and other accounting estimates, see Item
8. "Financial Statements and Supplementary Data, Note 1--Summary of Significant
Accounting Policies." For each of our critical accounting estimates, we
describe the following:
. the underlying estimate, including the methodology used, assumptions, and
reasonably likely changes;
. the significance of the estimate to our financial condition and results
of operations;
. how changes in the accounting estimate or the assumptions underlying it
would affect our financial information; and
. certain historical changes in our estimates.
California Receivables Realizability and Refund Methodologies.
In response to the filing of a number of complaints challenging the level of
wholesale prices in California, the FERC initiated a staff investigation and
issued a number of orders implementing a series of wholesale market reforms. In
these orders, the FERC also instituted a refund proceeding. The FERC issued an
order on March 26, 2003, adopting in most respects the proposed findings of the
presiding administrative law judge that had been issued in December 2002
following a hearing to apply the refund formula. The most consequential change
involved the adoption of a different methodology for determining the gas price
component of the refund formula. Instead of using California gas indices, the
FERC ordered the use of a proxy gas price based on producing area price indices
plus the posted transportation costs. In addition, the order allows generators
to petition for a reduction of the refund calculation upon a submittal to the
FERC of their actual gas costs and subsequent FERC approval. Based on the
proposed findings of the administrative law judge, discussed above, adjusted
for the March 2003 FERC order decision to revise the methodology for
determining the gas price component of the formula, we estimate our refund
obligation to be between $191 million and $240 million for energy sales in
California (excluding the $14 million refund related to the FERC settlement in
January 2003, as discussed in note 14(h) to our consolidated financial
statements). The low range of our estimate is based on a refund calculation
factoring in a reduction in the total FERC refund based on the actual cost paid
for gas over the proposed proxy gas price. The high range of our estimate of
the refund obligation assumes that the refund obligation is not adjusted for
the actual cost paid for gas over the proposed proxy gas price. Our estimate of
the range will be revised further following responsive submissions to FERC and
subsequent FERC orders. We cannot currently predict whether that will result in
an increase or decrease in our high and low points in the range. As of December
31, 2001, we had a pre-tax credit provision of $68 million against receivable
balances related to energy sales in the California market. As of December 31,
2002, we had a remaining pre-tax credit provision of $6 million against these
receivable balances. For further discussion of our provisions and reserves, see
note 14(i) to our consolidated financial statements.
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Goodwill and Other Intangibles.
We periodically evaluate goodwill and other intangible assets for impairment
when events or changes in circumstances indicate that the carrying value of
these assets may not be recoverable. The test is required to be performed at
least annually.
We estimate the fair value of our reporting units using a combination of
approaches, including an income approach based on internal plans, a market
approach based on transactions in the marketplace for comparable types of
assets, and a comparable public company approach. The income approach used in
our analysis is a discounted cash flow analysis based on our internal plans and
contains numerous assumptions made by management, any number of which if
changed could significantly affect the outcome of the analysis. We believe that
the income approach is the most subjective of the approaches.
The internal cash flow analyses used in our impairment analysis range over a
period of ten to 15 years with an assumed terminal value for the value of our
operations at the end of the analysis of an EBITDA multiple of primarily 6 to
7.5. For our annual impairment test as of November 1, 2002, these after-tax
cash flows (excluding interest) were discounted back to the date of the
analysis at an appropriate risk-adjusted discount rate of primarily 9% in order
to determine the fair value of the reporting unit under the income approach.
The income approach is weighted along with the other two approaches to
determine the fair value of the reporting unit.
As part of our planning process we model all of the power generation
facilities in the regions in which we operate in addition to those operated by
us. Our internal analyses for our wholesale energy segment assume that there
will be increased demand for electricity in the regions in which we operate,
the markets in which we operate will continue to be deregulated, and that
electricity margins and prices will recover to a level sufficient to make it
profitable for companies like ours to build new generating facilities. Our
analyses assume that the demand for power will rise at an annual rate of
approximately 2% over the next several years. This growth over time is assumed
to result in decreased reserve margins in the areas where we operate. As
reserve margins decrease, it is our assumption that power generation margins
will rise substantially over time to a level sufficient to attract new capacity
(estimated to be in 2007 and 2008). We assume that this level of prices will be
such that companies will build new generation facilities and these new
facilities will be able to cover all of their operating expenses and yield an
internal rate of return on their investment of 9%. This assumed rate of return
is consistent with our risk-adjusted discount rate used in our analyses.
Over the past year, margins on the sales of electricity in our industry have
decreased substantially. If the assumed recovery in future margins does not
materialize as projected, we could be required to recognize an impairment
depending on the determination of the fair market value of our wholesale energy
segment's assets and liabilities.
Property, Plant and Equipment.
We periodically evaluate our property, plant and equipment when events and
circumstances indicate that the carrying value of these assets may not be
recoverable. Accounting standards require that if the sum of the undiscounted
expected future cash flows from our assets (without interest charges that will
be recognized as expenses when incurred) is less than the carrying value of the
asset, an asset impairment must be recognized in the consolidated financial
statements. The amount of impairment recognized is calculated by subtracting
the fair value of the asset from the carrying value of the asset. Assumptions
and estimates used in our impairment analyses are consistent with assumptions
and estimates used in our goodwill impairment analysis. See "Goodwill and Other
Intangibles" within this section for further discussion of estimates and
assumptions used in our impairment analyses.
During 2002, certain indicators for impairment existed with respect to steam
and combustion turbines and two heat recovery steam generators that we
purchased in September 2002. Based on our analysis, we determined this
equipment was impaired and accordingly recognized a $37 million pre-tax
impairment loss. For additional information regarding this impairment, see note
14(c) to our consolidated financial statements.
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In December 2002, we evaluated the Liberty generation station and the
related tolling agreement for impairment. There were no impairments based on
our analyses. However, in the future we could incur a pre-tax loss of an amount
up to our recorded net book value. For information regarding issues and
contingencies related to our Liberty power generation station and the related
tolling agreement, see note 14(l) to our consolidated financial statements.
Depreciation Expense.
We have a significant investment in power generation facilities.
Approximately 85% of our total gross property, plant and equipment are electric
generating facilities and equipment. Depreciation is computed using the
straight-line method based on estimated useful lives. For a description of our
accounting policies for property, plant and equipment and depreciation expense,
see note 2(f) to our consolidated financial statements.
For power generation facilities and equipment acquired in acquisitions,
third party expert appraisers and internal engineers are used to determine the
estimated useful lives of these assets. Such determination is made through an
assessment of the condition of the acquired power generation facilities and
equipment, a review of projected maintenance, and a study of future cash flows.
We utilize the weighted average life of the components of a power generation
unit as the estimated useful life of each generation unit of a facility. The
estimated useful lives are impacted by the condition of the acquired
facilities, the fuel type of the generation facilities and future environmental
requirements, among other factors.
For our developed power generation facilities, we utilize the specified
design life that is provided in the engineering, procurement and construction
contract. In the absence of a specified design life in the engineering,
procurement and construction contract, we obtain an estimate of the weighted
average life of the components of a power generation unit of a facility from
our in-house engineers.
The computation of depreciation expense requires judgment regarding the
estimated useful lives of property, plant and equipment. As circumstances
warrant, the estimated useful lives of property, plant and equipment are
reviewed to determine if any changes are needed. Such changes could involve an
increase or decrease in the estimated useful lives, which would impact future
depreciation expense.
Our power generation facilities are exposed to risks relating to the
breakdown or failure of equipment or processes. Significant portions 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 to or upgrade equipment to keep it
operating at peak efficiency, to comply with changing environmental
requirements, or to provide reliable operations. Such items could impact the
useful life of our power generation facilities. In addition, research and
development activities are ongoing to improve alternative technologies to
produce electricity, including fuel cells, microturbines and photovoltaic
(solar) cells. It is possible that advances in these or other alternative
technologies could reduce the costs of electricity production to a level below
that which we have forecasted and accordingly make portions of our power
generation facilities' useful lives decrease.
Trading and Marketing Assets and Liabilities.
Trading and marketing activities include (a) transactions establishing open
positions in the energy markets, primarily on a short-term basis, (b)
transactions intended to optimize our power generation portfolio, but which do
not qualify for hedge accounting and (c) energy price risk management services
to customers primarily related to natural gas, electric power and other
energy-related commodities. We provide these services by utilizing a variety of
derivative instruments (trading energy derivatives). We account for these
transactions under mark-to-market accounting; for information regarding
mark-to-market accounting, see notes 2(t) and 7 to our consolidated financial
statements. Specifically, these trading and marketing activities consist of the
following:
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. the large contracted commercial, industrial and institutional customers
under retail electricity contracts and the related energy supply
contracts of our retail energy segment entered into prior to October 25,
2002;
. the domestic energy trading, marketing, risk management services to our
customers and certain power origination activities of our wholesale
energy segment; and
. the European energy trading and origination operations of our European
energy segment.
Under the mark-to-market method of accounting, derivative instruments and
contractual commitments are recorded at fair value in revenues upon contract
execution. The net changes in their fair values are recognized in the
statements of consolidated operations as revenues in the period of change. The
recognized, unrealized balances are recorded as trading and marketing
assets/liabilities in the consolidated balance sheets.
We value our trading and marketing assets and liabilities based on (a)
prices actively quoted, (b) prices provided by other external sources or (c)
prices based on models and other valuation methods. For further discussion of
these various valuation techniques and the types of contracts included within
each, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations--Trading and Marketing Operations" within Item 7 of this
Form 10-K. Our pricing methodologies based on models and other valuation
methods 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 a
position. Other factors affecting our estimates of fair values include
valuation adjustments relating to time value, the volatility of the underlying
commitment, the cost of administering future obligations under existing
contracts, and the credit risk of counterparties. Volatility valuation
adjustments are calculated by utilizing observed market price volatility and
represent the estimated impact on fair values resulting from potential
fluctuations in current prices. Credit adjustments are based on estimated
defaults by counterparties and are calculated using historical default ratings
for corporate bonds for companies with similar credit ratings.
More specifically, the fair value of our retail energy segment electric
sales contracts with large commercial, industrial and institutional customers
was determined by comparing the contract price to an estimate of the market
cost of delivered retail energy and applying the estimated volumes under the
provisions of these contracts. The calculation of the estimated cost of energy
involves estimating the customer's anticipated load volume, and using forward
ERCOT OTC commodity prices, adjusted for the customer's anticipated load
characteristics. 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. The
delivery costs are estimated at the time sales contracts are executed. These
costs are based on published rates and our experience of actual delivery costs.
Examples of these delivery costs include electric line losses and unaccounted
for energy, ERCOT ISO administrative fees, market interaction charges, and may
include transmission and distribution fees. Our retail energy segment also
enters into supply contracts to substantially hedge the economics of the sales
contracts entered into with large commercial, industrial and institutional
customers. The fair values of these contracts are estimated using ERCOT OTC
forward price and volatility curves and correlations among power and fuel
prices specific to the ERCOT Region, net of credit risk.
The fair values of our trading and marketing assets and liabilities 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 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
94
significantly affect the values that could be obtained for these contracts, as
well as the costs at which these contracts could be hedged.
In order to determine the fair value for certain trading energy derivatives,
we must rely on modeling techniques. These techniques are used to offset the
effects of illiquid markets, in which price discovery is difficult. In certain
circumstances, prices are modeled using a variety of techniques such as moving
averages, calibration models, and other time series techniques, market
equilibrium analysis, extrapolation/interpolation, a range of contingent claims
valuation methods and volumetric risk modeling. By using these techniques we
are employing all available information to compensate for the lack of price
discovery due to market incompleteness.
While we use common industry practices to develop our valuation techniques,
changes in our methodologies or the underlying assumptions could result in
significantly different fair values and income recognition.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations--Trading and Marketing Operations" in Item 7 and "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.
Non-trading Derivative Assets and Liabilities.
To reduce the risk from market fluctuations in revenues and the resulting
cash flows derived from the sale of electric power, we 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). Effective January 1, 2001, we adopted SFAS No. 133, which
establishes accounting and reporting standards for derivative instruments,
including 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
accumulated other comprehensive income (loss), net of applicable taxes,
depending on the intended use of the derivative, its resulting designation and
its effectiveness. We apply hedge accounting for our 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. The gains and losses related to derivative instruments and
contractual commitments qualifying and designated as hedges are deferred in
accumulated other comprehensive income (loss) to the extent the contracts are
effective as a hedge, and then are recognized in our results of operations in
the same period as the settlement of the underlying hedged transaction. The
fair values and deferred gains and losses of derivative instruments and
contractual commitments qualifying and designated as hedges are based on the
same valuation techniques described above for trading and marketing assets and
liabilities. For a derivative not designated as a hedging instrument, the gain
or loss is recognized in earnings in the period it occurs based on the same
valuation techniques described above for trading and marketing assets and
liabilities. For additional discussion of our accounting policies for
non-trading derivatives, see note 7 to our consolidated financial statements.
Payment to CenterPoint.
We may be required to make a payment to CenterPoint in 2004 to the extent
our price to beat for providing retail electric service to residential and
small commercial customers in CenterPoint's Houston service territory during
2002 and 2003 exceeds the market price of electricity. This payment is required
unless, 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 CenterPoint's Houston service territory is committed to
be served by retail electric providers other than us. As of December 31, 2002,
our estimate for the payment related to residential customers is between $160
million and $190 million (pre-tax), with a most probable estimate of $175
million. As of December 31, 2002, we have accrued $128 million (based on the
recognition of the related revenues) relating to this probable payment to
CenterPoint and will recognize the remainder of the obligation in 2003.
Currently, we believe that the 40% test for small commercial customers will be
met and we will not make a
95
payment related to those customers. If the 40% test is not met related to our
small commercial customers and a payment is required, we estimate this payment
would be approximately $30 million.
In determining this range and the amount to accrue as of December 31, 2002,
there are certain factors which require estimates and assumptions by us: (a)
the market price of electricity for the period from January 1, 2002 through
December 31, 2003 and (b) the number of residential and small commercial
electric customers that we will have in CenterPoint's Houston service territory
on January 1, 2004, less the number of customers which we will have on that
date in other service territories in Texas.
We are accruing the potential payment liability for residential customers
based on (a) the difference of (i) the price to beat, which we are charging our
customers and (ii) the market rate as determined based on the EFL filed by our
primary competitor multiplied by (b) the amount of electric power consumed by
our residential customers in CenterPoint's Houston service territory during
that time period. The EFL is filed by each retail electric provider on the
first day of the calendar year and each time a provider's rates change. There
is the chance that the PUCT will determine that a different price should be
used as the market price. However, we have assumed that we will be paying up to
the maximum amount of $150 per net residential customer, based on the number of
residential customers served within CenterPoint's Houston service territory
less the number of residential customers which we will have in other service
territories in Texas. Therefore, there would be no impact to our consolidated
financial statements over the two-year time period if this were to occur. In
the future, we will revise our estimates of this payment as additional
information about the market price of electricity and the market share that
will be served by us and other retail electric providers on January 1, 2004
becomes available and we will adjust the related accrual at that time.
We monitor our customer acquisition and attrition rates, both in the
CenterPoint Houston service territory and in other service territories in
Texas. We have projected our number of residential and small commercial
customers as of January 1, 2004 based on these monthly trend lines and expected
changes that may occur as a result of additional activities in the market.
These include both the number of customers we serve in the Houston service
territory as well as other areas of Texas. We are assuming a certain number of
residential and small commercial customers within our Houston service territory
switch to other providers for their electricity. We have accrued and estimated
our most probable payment based on our most likely business plan. However, the
possibility of a higher or lower customer count exists based on the changes in
the level of competition and other factors, such as new entrants into the
market, competitor pricing and marketing activities. Holding all other factors
constant, if the percentage of our number of residential customers in our
Houston service territory increases four percentage points, our payment to
CenterPoint in 2004 would increase approximately $10 million. We have also
assumed that we gain market share in other areas (outside of Houston) of Texas.
We have assumed a certain percentage of residential customers switch from their
current retail electric provider to another provider and have assumed that we
gain a certain percentage of those that switched. Holding all other factors
constant, if the percentage of residential customers that we gain is one
percentage point less than we are estimating, our payment to CenterPoint in
2004 would increase by approximately $5 million.
For additional information regarding this payment, see note 14(e) to our
consolidated financial statements.
Retail Energy Segment Accrued Unbilled Revenue.
We record revenue for retail and other energy sales under the accrual
method. For retail customers, revenues are recognized when the services are
provided on the basis of periodic cycle meter readings by the transmission and
distribution utility. The transmission and distribution utilities send the
information to the ERCOT ISO, which in turn sends the information to us. Each
month we estimate the volume of electricity consumed from the last meter
reading for that month to the end of the month based on historical customer
volumes, usage by customer class and weather factors. We estimate a rate for
each MWh of usage using a mix by customer class determined by using historical
trends, contract prices, regulatory rates and experience. The volume estimate
is then multiplied by our estimated rate to calculate the unbilled revenue to
be recorded. We record the unbilled revenue
96
in the current reporting period and then reverse in the subsequent reporting
period when actual usage and rates are known and billed. Unbilled revenues
recognized at December 31, 2002 totaled $216 million, representing
approximately 2% of our 2002 revenue. Our unbilled revenue included $25 million
related to delayed billings. Assuming a 3% increase or decrease in either our
estimate of electricity usage volumes or estimated rate per MWh, our unbilled
revenue at December 31, 2002 would increase or decrease by approximately $6
million, respectively. Alternatively, a 3% increase or decrease in both our
estimated electricity usage and estimated rate per MWh would increase or
decrease our unbilled revenue at December 31, 2002 by approximately $13 million.
Retail Energy Segment Cost of Sales Recognition
We record our purchased power cost for our electricity sales and services to
retail customers based on estimated supply volumes and an estimated rate per
MWh for the applicable reporting period. The estimated supply volumes consider
the effects of historical customer volumes, weather factors and usage by
customer class. We estimate a rate for each MWh of usage using a mix by
customer class determined by using historical trends, contract prices,
regulatory rates and experience. The volume estimate is then multiplied by the
estimated rate per MWh and recorded as purchased power expense in the
applicable reporting period.
The ERCOT ISO is responsible for handling, scheduling and settlement for all
electricity volumes in the Texas deregulated electricity market. As part of the
settlement, the ERCOT ISO communicates the actual volumes compared to the
scheduled volumes. The ERCOT ISO calculates an additional charge or credit
based on the difference between the actual and scheduled volumes, based on a
market-clearing price. Preliminary settlement information is due from the ERCOT
ISO within two months after electricity is delivered with final settlement
information due within twelve months after electricity is delivered. As a
result, we adjust our estimated purchase power expense upon receipt of
settlement and consumption information. Additionally, we compare the ERCOT ISO
volumes usage data to our retail billing usage data and adjust for the volume
difference at the ERCOT ISO market-clearing price. Historically, our volume
estimates were adjusted in subsequent reporting periods by an average of 2% to
5% in either direction, while our adjustments to the estimated rate per MWh
were nominal. Assuming a 3% increase or decrease in our estimate of electricity
usage volumes purchased on an average month, our purchased power expense at
December 31, 2002 would have been increased or decreased by approximately $5
million. Changes in our volume usage would result in a similar change in billed
volumes, thus volume changes impacting purchased power expense would be
partially mitigated.
The ERCOT ISO settlement process was delayed due to operational problems
between the ERCOT ISO, the transmission and distribution utilities and the
retail electric providers. During the third quarter of 2002, the ERCOT ISO
began issuing final settlements for the pilot time period of July 31, 2001 to
December 31, 2001. The final settlements have been suspended until a market
synchronization of all customers between the market participants takes place.
The market synchronization will validate which retail electric provider served
each customer, for each day, beginning as of January 1, 2002, which was the
date the market opened to retail competition. Once this market synchronization
is complete, the ERCOT ISO will resume the final settlement process beginning
with January 1, 2002. The delay in the ERCOT ISO settlement process could
impact our ability to accurately reflect our energy supply costs.
We record our transmission and distribution charges using the same method
detailed above for our electricity sales and services to retail customers. At
December 31, 2002, the transmission and distribution charges not billed by the
transmission and distribution utilities to us totaled $59 million. Delays or
inaccurate billings from the transmission and distribution utilities could
impact our ability to accurately reflect our transmission and distribution
costs.
See "Management's Discussion and Analysis of Financial Condition and Results
of Operations--EBIT by Business Segment--Retail Energy" and "Management's
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors--Risks Related to Our Retail Energy Operations" in Item 7 of this
Form 10-K for further discussion regarding our risks associated with
information received from the ERCOT ISO.
97
Deferred Tax Assets Valuation Allowance.
We are required to estimate whether recoverability of our deferred tax
assets is more likely than not. We periodically assess the probability of
recovery of recorded deferred tax assets based on our forecast of future
earnings outlooks by tax jurisdiction. We use historical and projected future
operating results, based upon approved business plans, including a review of
the eligible carryforward period, tax planning opportunities and other relevant
considerations. Such estimates are inherently imprecise. Many assumptions are
utilized in the assessment that may prove to be materially incorrect in the
future. We have evaluated the need for valuation allowances of our net deferred
tax assets based on the likelihood of expected future taxable benefits. As of
December 31, 2001, our valuation allowance for all of our deferred tax assets
was $16 million. During 2002, we recorded $25 million additional valuation
allowance through income tax expense and $30 million in connection with the
Orion Power acquisition, resulting in a deferred tax asset valuation allowance
of $71 million as of December 31, 2002. We continue to evaluate the need for a
valuation allowance on a quarterly basis and any change in the amount that we
expect to ultimately realize will be included in income, as appropriate, in the
period in which such a determination is reached. For further discussion of our
income taxes, see note 13 to our consolidated financial statements.
Contingencies.
We follow SFAS No. 5 to determine accounting and disclosure requirements for
contingencies. We are involved in legal proceedings before various courts and
governmental agencies, some of which involve substantial amounts. In addition,
we are subject to a number of ongoing investigations by various governmental
agencies, such as the FERC, the PUCT, the SEC, the Internal Revenue Service,
the EPA and the Department of Labor. Certain of these proceedings and
investigations are the subject of intense, highly charged media and political
attention. As these matters progress, additional issues may be identified that
could expose us to further proceedings and investigations. Our management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters that can be
estimated. Accounting for contingencies requires significant judgment by us
regarding the estimated probabilities and ranges of exposure to potential
liability. Unless otherwise indicated in note 14(h) to our consolidated
financial statements, the ultimate outcome of the various lawsuits, proceedings
and investigations cannot be predicted at this time. The ultimate disposition
of some of these matters could have a material adverse effect on our financial
condition, results of operations and cash flows. For further discussion of our
various contingencies, see note 14 to our consolidated financial statements.
Pension and Postretirement Benefits.
We account for our pension and post retirement benefit obligations in
accordance with the provisions of SFAS No. 87 and SFAS No. 106. These standards
require the use of assumptions such as the discount rate, estimated return on
plan assets, compensation increases and the current level and escalation of
health care costs in the future. On an annual basis, we determine the
assumptions to be used to compute pension and postretirement expense and
pension contributions based upon discussions with outside actuaries and other
consultants. We believe the two most critical assumptions in determining the
benefit obligations for these plans are the discount rate, which estimates the
rate at which benefits could be effectively settled, and the expected long-term
rate of return on plan assets, which reflects the average rate of earnings
expected on the funds invested over the life of the plans. In addition, the
healthcare cost trend rate has a significant effect on the reported amounts for
the accumulated post retirement benefit obligation and related expense. Note
12(d) to our consolidated financial statement describes the impact of a
one-percentage point change in the health care cost trend rates; however, there
can be no certainty that a change would be limited to only one percentage point.
The pension and postretirement liability and future pension and
postretirement expense both increase as the discount rate is reduced. We
determined our discount rate assumption based on the current rates earned on
long-term bonds that receive one of the two highest ratings given by a
recognized rating agency. Lowering the
98
discount rate by 1.0% (from a range of 6.6% - 6.75% to a range of 5.6% - 5.75%)
would increase our pension liability and postretirement liability at December
31, 2002 by approximately $14 million and $16 million, respectively, and
increase our estimated 2003 pension expense and postretirement benefit expense
by approximately $3 million and $2 million, respectively. During 2001 and 2002,
we lowered our assumed discount rate for pension and postretirement benefits by
0.25% and 0.50%, respectively, to reflect current interest rate conditions.
Pension expense increases as the expected long-term rate of return on plan
assets decreases. We developed our expected long-term rate of return on plan
assets assumption by evaluating input from our retirement plan investment
advisors, review of asset class return expectations of a survey of Fortune 500
companies, as well as long-term inflation assumptions. Lowering our assumption
of the expected long-term rate of return on our plan assets by 1.0% (from 8.5%
to 7.5%) would increase our estimated 2003 pension expense by approximately
$0.3 million. During 2001 and 2002, we lowered our expected long-term rate of
return assumption by 0.50% and 1.0%, respectively, to reflect the impact of
recent trends and our long-term view.
A difference in the assumed rates and the actual rates, which will not be
known for decades, can be significant in relation to the obligation and the
annual expense recorded for these plans.
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, results of operations
and cash flows from our business activities are impacted by market risks.
Categories of market risks include exposures to commodity prices through
trading and marketing activities 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; and
. 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 procedures. 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. We frequently
utilize derivative instruments to execute our risk management and hedging
strategies.
Derivative instruments are 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 and marketing businesses utilize derivative instruments as a
means to optimize our power generation portfolio, manage commodity price risk,
and take market positions. In addition, we use derivative instruments in our
non-trading operations to manage and hedge exposures, such as exposure to
changes in electricity and fuel prices, interest rate risk on our floating-rate
borrowings and foreign currency risk related to
99
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. In March 2003, we decided to exit our
proprietary trading activities and liquidate, to the extent practicable, our
proprietary positions. Although we are exiting the proprietary trading
business, we have existing positions, which will be closed as economically
feasible or in accordance with their terms. We will continue to engage in
hedging activities related to our electric generating facilities, pipeline
storage positions and fuel positions.
Given our current credit and liquidity situation and other factors, we have
reduced the level of our marketing and hedging activities, which could result
in greater volatility in future earnings. Additionally, the reduction in market
liquidity may impair the effectiveness of our risk management procedures and
hedging strategies. These and other factors may adversely impact our results of
operations, financial condition and cash flows. For further discussion of our
current liquidity situation and related impacts, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations--Liquidity and
Capital Resources" in Item 7 of this Form 10-K.
For information regarding our commodity price risk, see "Management
Discussion and Analysis of Financial Condition and Results of Operations--Risk
Factors--Risks Related to Our Wholesale Energy Operations" in Item 7 of this
Form 10-K.
Trading Market Risk
We employ a risk management system to mitigate the risks associated with
trading and marketing operations. These operations involve market risk
associated with managing energy commodities and establishing strategic
positions in the energy markets, primarily on a short-term basis, by utilizing
energy derivative instruments. Our trading and marketing businesses depend on
price and volatility changes to create business opportunities, but these
businesses must control risk within authorized limits.
We primarily assess the risk of our trading and marketing positions using a
value at risk method, in order to maintain our total exposure within authorized
limits. Value at risk 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 parametric variance/covariance method with
delta/gamma approximation to calculate value at risk, which relies on
statistical relationships to describe how changes in commodity and commodity
derivatives prices can affect a portfolio of instruments with different
characteristics and market exposures. The delta/gamma approximation captures
most of the effects of option price risk in the portfolio.
Our value at risk limits are set by our board of directors, as further
discussed below. Violations in overall value at risk limits are required to be
reported to the audit committee of our board of directors pursuant to our
corporate-wide risk limit policy. For further discussion on our risk management
framework, see "--Risk Management Structure" below. Risk limits in trading and
marketing operations include both value at risk as well as other
non-statistical measures of portfolio exposure. The risk management process
supplements the measurement and enforcement of the limit metrics with
additional analyses including stress testing the portfolio for extreme events
and back-testing the value at risk model.
Our value at risk model utilizes four major parameters: confidence level,
volatility, correlation and holding period.
. Confidence level: Natural gas and petroleum products have a confidence
interval of 95% and power products have a confidence interval of 99%. The
confidence level for power products is higher in order to capture the
non-normality of power price behavior.
. Volatility: Calculated daily from historical forward prices using the
exponentially weighted moving average method.
. Correlation: Calculated daily from daily volatilities and historical
forward prices using the exponentially weighted moving average method.
This parameter is included to account for the diversification of the
portfolio.
100
. Holding period: Natural gas and petroleum products generally have one day
holding periods. Power products have holding periods of 1 to 20 days
based on the risk profile of the portfolio. The holding periods for power
products reflect our efforts to appropriately account for possible
liquidation periods of more than one day, which is reasonable for some
non-standard products.
Assuming a confidence level of 95% and a one-day holding period, if value at
risk is calculated at $10 million, we may state that there is a one in 20
chance that if prices move against our consolidated diversified positions, our
pre-tax loss in liquidating or offsetting with hedges, our applicable portfolio
in a one-day period would exceed $10 million.
While we believe that our assumptions and approximations are reasonable for
calculating value at risk, there is no uniform industry methodology for
estimating value at risk, and different assumptions and/or approximations could
produce materially different value at risk estimates.
An inherent limitation of value at risk is that past changes in market risk
may not produce accurate predictions of future market risk. Moreover, value at
risk calculated for a specified holding period does not fully capture the
market risk of positions that cannot be liquidated or offset with hedges within
that specified period. Future transactions, market volatility, reduction of
market liquidity, failure of counterparties to satisfy their contractual
obligations and/or a failure of risk controls could result in material losses
from our trading and marketing businesses.
The following table presents the daily value at risk for substantially all
of our trading and marketing positions for 2001 and 2002:
2001 2002
---- ----
(in millions)
As of December 31...... $27 $19
Year Ended December 31:
Average............. 9 18
High................ 27 29
Low................. 3 11
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The following chart sets forth the daily value at risk for substantially all
of our trading energy contracts for 2001 and 2002 (in millions):
[CHART]
2-Jan-2001 16.440239 1st Qtr '01
3-Jan-2001 18.048017
4-Jan-2001 10.915915
5-Jan-2001 11.122577
8-Jan-2001 10.631500
9-Jan-2001 14.305831
10-Jan-2001 15.226464
11-Jan-2001 15.465547
12-Jan-2001 9.958157
15-Jan-2001 10.578956
16-Jan-2001 10.639070
17-Jan-2001 8.827562
18-Jan-2001 7.807395
19-Jan-2001 12.475673
22-Jan-2001 12.797258
23-Jan-2001 12.519743
24-Jan-2001 13.394388
25-Jan-2001 15.964172
26-Jan-2001 13.359285
29-Jan-2001 13.005172
30-Jan-2001 11.502271
31-Jan-2001 11.976986
1-Feb-2001 12.257142
2-Feb-2001 14.898787
5-Feb-2001 11.746706
6-Feb-2001 10.040913
7-Feb-2001 8.210914
8-Feb-2001 6.114748
9-Feb-2001 5.483367
12-Feb-2001 5.552378
13-Feb-2001 8.513799
14-Feb-2001 7.534022
15-Feb-2001 7.131259
16-Feb-2001 5.506180
19-Feb-2001 5.363474
20-Feb-2001 4.957146
21-Feb-2001 5.106395
22-Feb-2001 4.788352
23-Feb-2001 4.675029
26-Feb-2001 4.962425
27-Feb-2001 7.869456
28-Feb-2001 7.215959
1-Mar-2001 7.902980
2-Mar-2001 11.238504
5-Mar-2001 9.387088
6-Mar-2001 17.134763
7-Mar-2001 16.877188
8-Mar-2001 14.030707
9-Mar-2001 12.190710
12-Mar-2001 9.696280
13-Mar-2001 4.070432
14-Mar-2001 4.590371
15-Mar-2001 6.136942
16-Mar-2001 7.241223
19-Mar-2001 4.402039
20-Mar-2001 5.751936
21-Mar-2001 6.369483
22-Mar-2001 6.042373
23-Mar-2001 5.958061
26-Mar-2001 5.551905
27-Mar-2001 7.366331
28-Mar-2001 5.529644
29-Mar-2001 5.896718
30-Mar-2001 6.016953
2-Apr-2001 9.834879 2nd Qtr '01
3-Apr-2001 11.485757
4-Apr-2001 12.078340
5-Apr-2001 14.344599
6-Apr-2001 15.933048
9-Apr-2001 13.591664
10-Apr-2001 10.710934
11-Apr-2001 12.044116
12-Apr-2001 12.637839
16-Apr-2001 11.352207
17-Apr-2001 10.219905
18-Apr-2001 6.545637
19-Apr-2001 8.367634
20-Apr-2001 8.405587
23-Apr-2001 7.662456
24-Apr-2001 7.280167
25-Apr-2001 6.755404
26-Apr-2001 8.499528
27-Apr-2001 8.493672
30-Apr-2001 8.385372
1-May-2001 8.843355
2-May-2001 6.906786
3-May-2001 6.669425
4-May-2001 5.814830
7-May-2001 5.914624
8-May-2001 5.019128
9-May-2001 5.945725
10-May-2001 4.398222
11-May-2001 4.868063
14-May-2001 4.602470
15-May-2001 5.376093
16-May-2001 4.717945
17-May-2001 3.863073
18-May-2001 3.429215
21-May-2001 3.588377
22-May-2001 4.415384
23-May-2001 4.898558
24-May-2001 4.565258
25-May-2001 5.777347
28-May-2001 5.881347
29-May-2001 6.249721
30-May-2001 4.636203
31-May-2001 4.864840
1-Jun-2001 4.983687
4-Jun-2001 4.245491
5-Jun-2001 5.102913
6-Jun-2001 4.200182
7-Jun-2001 2.948479
8-Jun-2001 6.744124
11-Jun-2001 7.371002
12-Jun-2001 6.493753
13-Jun-2001 6.295359
14-Jun-2001 4.880968
15-Jun-2001 5.210422
18-Jun-2001 5.120925
19-Jun-2001 4.991254
20-Jun-2001 4.496960
21-Jun-2001 4.211394
22-Jun-2001 4.303551
25-Jun-2001 4.474291
26-Jun-2001 2.996053
27-Jun-2001 3.301413
28-Jun-2001 5.410389
29-Jun-2001 8.776367
2-Jul-2001 7.255244 3rd Qtr '01
3-Jul-2001 7.293825
4-Jul-2001 7.293825
5-Jul-2001 8.372847
6-Jul-2001 11.225833
9-Jul-2001 9.226580
10-Jul-2001 8.087470
11-Jul-2001 7.129531
12-Jul-2001 6.489320
13-Jul-2001 5.942860
16-Jul-2001 5.623077
17-Jul-2001 4.376403
18-Jul-2001 4.859754
19-Jul-2001 3.501290
20-Jul-2001 3.465904
23-Jul-2001 3.624296
24-Jul-2001 3.642266
25-Jul-2001 3.730154
26-Jul-2001 3.560031
27-Jul-2001 4.528300
30-Jul-2001 3.437136
31-Jul-2001 4.148923
1-Aug-2001 5.270206
2-Aug-2001 4.800352
3-Aug-2001 4.279754
6-Aug-2001 4.473491
7-Aug-2001 4.541865
8-Aug-2001 5.162489
9-Aug-2001 6.717661
10-Aug-2001 5.113297
13-Aug-2001 6.762922
14-Aug-2001 5.064235
15-Aug-2001 5.186749
16-Aug-2001 6.933689
17-Aug-2001 4.538835
20-Aug-2001 4.201843
21-Aug-2001 4.731744
22-Aug-2001 4.572893
23-Aug-2001 3.689634
24-Aug-2001 4.340720
27-Aug-2001 3.367646
28-Aug-2001 3.597948
29-Aug-2001 5.000715
30-Aug-2001 5.552775
31-Aug-2001 6.214695
3-Sep-2001 6.022695
4-Sep-2001 6.427848
5-Sep-2001 6.047888
6-Sep-2001 5.260454
7-Sep-2001 6.014640
10-Sep-2001 5.292143
11-Sep-2001 5.389143
12-Sep-2001 3.158445
13-Sep-2001 3.764939
14-Sep-2001 5.363399
17-Sep-2001 6.591792
18-Sep-2001 6.816208
19-Sep-2001 6.104224
20-Sep-2001 5.986680
21-Sep-2001 6.309352
24-Sep-2001 5.529675
25-Sep-2001 5.182177
26-Sep-2001 5.528646
27-Sep-2001 6.107942
28-Sep-2001 5.617587
1-Oct-2001 6.617658 4th Qtr '01
2-Oct-2001 7.393765
3-Oct-2001 6.947100
4-Oct-2001 8.674111
5-Oct-2001 7.671782
8-Oct-2001 7.670422
9-Oct-2001 7.667765
10-Oct-2001 8.382972
11-Oct-2001 7.976459
12-Oct-2001 8.732914
15-Oct-2001 8.126716
16-Oct-2001 8.095239
17-Oct-2001 7.780685
18-Oct-2001 7.949018
19-Oct-2001 7.757021
22-Oct-2001 7.830656
23-Oct-2001 8.306001
24-Oct-2001 9.351342
25-Oct-2001 8.541448
26-Oct-2001 8.673579
29-Oct-2001 8.159580
30-Oct-2001 13.995714
31-Oct-2001 14.108991
1-Nov-2001 15.643811
2-Nov-2001 15.832897
5-Nov-2001 15.671663
6-Nov-2001 19.004129
7-Nov-2001 17.733247
8-Nov-2001 15.859885
9-Nov-2001 13.952841
12-Nov-2001 13.571103
13-Nov-2001 13.352052
14-Nov-2001 10.979914
15-Nov-2001 13.211619
16-Nov-2001 12.183012
19-Nov-2001 11.218255
20-Nov-2001 10.945647
21-Nov-2001 11.376730
22-Nov-2001 11.239725
23-Nov-2001 11.321725
26-Nov-2001 11.228725
27-Nov-2001 10.587342
28-Nov-2001 10.246459
29-Nov-2001 11.600472
30-Nov-2001 9.914581
2-Dec-2001 12.230778
3-Dec-2001 12.833778
4-Dec-2001 12.771778
5-Dec-2001 12.969807
6-Dec-2001 15.050952
7-Dec-2001 14.622745
10-Dec-2001 16.716341
11-Dec-2001 17.085547
12-Dec-2001 17.285259
13-Dec-2001 18.649044
14-Dec-2001 20.646800
17-Dec-2001 22.308499
18-Dec-2001 24.736471
19-Dec-2001 26.461454
20-Dec-2001 25.203104
21-Dec-2001 24.748015
24-Dec-2001 24.601015
26-Dec-2001 25.075519
27-Dec-2001 23.775087
28-Dec-2001 23.946831
31-Dec-2001 27.051287
2-Jan-2002 27.540225 1st Qtr '02
3-Jan-2002 24.986041
4-Jan-2002 22.649991
7-Jan-2002 21.785456
8-Jan-2002 21.303319
9-Jan-2002 20.923040
10-Jan-2002 22.253934
11-Jan-2002 20.739814
14-Jan-2002 19.703593
15-Jan-2002 19.201315
16-Jan-2002 17.789634
17-Jan-2002 17.590306
18-Jan-2002 17.138642
22-Jan-2002 16.503132
23-Jan-2002 16.017242
24-Jan-2002 14.603531
25-Jan-2002 16.303428
28-Jan-2002 16.083811
29-Jan-2002 16.395382
30-Jan-2002 15.426673
31-Jan-2002 16.846852
1-Feb-2002 16.712971
4-Feb-2002 17.089343
5-Feb-2002 17.107714
6-Feb-2002 16.556753
7-Feb-2002 16.898014
8-Feb-2002 16.459497
11-Feb-2002 16.691350
12-Feb-2002 17.624177
13-Feb-2002 17.239216
14-Feb-2002 17.564720
15-Feb-2002 16.689573
19-Feb-2002 15.502591
20-Feb-2002 17.400807
21-Feb-2002 16.556148
22-Feb-2002 16.324162
25-Feb-2002 16.528809
26-Feb-2002 16.399198
27-Feb-2002 16.259517
28-Feb-2002 17.117350
1-Mar-2002 17.243255
4-Mar-2002 16.994713
5-Mar-2002 17.532512
6-Mar-2002 17.526542
7-Mar-2002 18.242102
8-Mar-2002 18.214228
11-Mar-2002 17.682532
12-Mar-2002 18.633909
13-Mar-2002 20.650374
14-Mar-2002 20.791973
15-Mar-2002 23.407038
18-Mar-2002 23.798431
19-Mar-2002 21.122117
20-Mar-2002 20.954693
21-Mar-2002 21.814370
22-Mar-2002 26.143325
25-Mar-2002 24.011012
26-Mar-2002 18.184578
27-Mar-2002 19.783923
28-Mar-2002 22.455002
1-Apr-2002 21.673714 2nd Qtr '02
2-Apr-2002 21.249323
3-Apr-2002 21.831832
4-Apr-2002 23.131250
5-Apr-2002 21.984055
8-Apr-2002 19.685773
9-Apr-2002 19.536011
10-Apr-2002 17.976697
11-Apr-2002 17.959718
12-Apr-2002 16.468909
15-Apr-2002 16.425491
16-Apr-2002 17.547585
17-Apr-2002 17.055878
18-Apr-2002 18.803488
19-Apr-2002 15.916207
22-Apr-2002 16.230384
23-Apr-2002 19.068276
24-Apr-2002 17.744793
25-Apr-2002 15.912920
26-Apr-2002 14.656335
29-Apr-2002 19.564761
30-Apr-2002 21.115993
1-May-2002 29.413715
2-May-2002 28.099983
3-May-2002 22.448109
6-May-2002 21.206431
7-May-2002 22.154410
8-May-2002 18.352871
9-May-2002 16.936795
10-May-2002 16.855947
13-May-2002 17.292232
14-May-2002 17.106326
15-May-2002 18.879793
16-May-2002 17.637404
17-May-2002 16.920686
20-May-2002 15.441251
21-May-2002 16.438225
22-May-2002 14.942622
23-May-2002 15.145170
24-May-2002 15.170563
27-May-2002 15.195217
28-May-2002 13.779409
29-May-2002 14.168838
30-May-2002 14.050240
31-May-2002 13.760939
3-Jun-2002 13.647730
4-Jun-2002 13.693737
5-Jun-2002 14.284346
6-Jun-2002 14.690380
7-Jun-2002 14.754409
10-Jun-2002 13.862531
11-Jun-2002 12.860229
12-Jun-2002 12.849718
13-Jun-2002 14.388505
14-Jun-2002 14.042885
17-Jun-2002 16.124001
18-Jun-2002 16.023713
19-Jun-2002 16.069988
20-Jun-2002 15.793969
21-Jun-2002 16.045253
24-Jun-2002 15.867801
25-Jun-2002 15.979492
26-Jun-2002 15.952553
27-Jun-2002 18.853562
28-Jun-2002 19.520414
1-Jul-2002 18.033682 3rd Qtr '02
2-Jul-2002 21.096593
3-Jul-2002 18.484062
8-Jul-2002 18.631134
9-Jul-2002 18.151504
10-Jul-2002 18.095440
11-Jul-2002 18.533588
12-Jul-2002 17.555010
15-Jul-2002 17.198648
16-Jul-2002 18.194878
17-Jul-2002 19.044112
18-Jul-2002 18.966302
19-Jul-2002 19.358826
22-Jul-2002 18.966127
23-Jul-2002 18.873047
24-Jul-2002 19.176830
25-Jul-2002 18.463585
26-Jul-2002 18.348985
29-Jul-2002 20.438025
30-Jul-2002 20.006954
31-Jul-2002 19.782745
1-Aug-2002 19.356025
2-Aug-2002 18.830822
5-Aug-2002 16.585992
6-Aug-2002 15.755950
7-Aug-2002 16.003272
8-Aug-2002 15.606581
9-Aug-2002 18.673998
12-Aug-2002 18.493162
13-Aug-2002 19.297680
14-Aug-2002 18.392422
15-Aug-2002 18.408262
16-Aug-2002 18.240982
19-Aug-2002 17.851999
20-Aug-2002 17.710879
21-Aug-2002 17.794234
22-Aug-2002 17.756938
26-Aug-2002 17.821979
27-Aug-2002 17.889765
28-Aug-2002 17.406254
29-Aug-2002 17.690881
30-Aug-2002 18.601590
3-Sep-2002 18.641455
4-Sep-2002 18.059611
5-Sep-2002 20.735314
6-Sep-2002 20.803369
9-Sep-2002 21.225328
10-Sep-2002 20.896518
11-Sep-2002 21.744865
12-Sep-2002 21.047306
13-Sep-2002 20.368741
16-Sep-2002 21.284451
17-Sep-2002 20.064172
18-Sep-2002 19.036127
19-Sep-2002 19.192656
20-Sep-2002 18.551640
23-Sep-2002 17.968610
24-Sep-2002 17.685416
25-Sep-2002 19.635078
26-Sep-2002 18.583882
27-Sep-2002 19.261821
30-Sep-2002 17.778528
1-Oct-2002 18.669296 4th Qtr '02
2-Oct-2002 17.647788
3-Oct-2002 18.896999
4-Oct-2002 20.480454
7-Oct-2002 20.730427
8-Oct-2002 19.761523
9-Oct-2002 19.175367
10-Oct-2002 17.842404
11-Oct-2002 16.880334
14-Oct-2002 14.824883
15-Oct-2002 16.368305
16-Oct-2002 17.104334
17-Oct-2002 15.985303
18-Oct-2002 16.078954
21-Oct-2002 15.768602
22-Oct-2002 15.633684
23-Oct-2002 15.959728
24-Oct-2002 15.526769
25-Oct-2002 14.997391
28-Oct-2002 13.688562
29-Oct-2002 13.872468
30-Oct-2002 14.577499
31-Oct-2002 14.666594
1-Nov-2002 14.235101
4-Nov-2002 13.978377
5-Nov-2002 13.715435
6-Nov-2002 13.929728
7-Nov-2002 12.028778
11-Nov-2002 12.422179
12-Nov-2002 12.466551
13-Nov-2002 11.964884
14-Nov-2002 11.409805
15-Nov-2002 11.503069
18-Nov-2002 11.502314
19-Nov-2002 13.320338
20-Nov-2002 13.875788
21-Nov-2002 13.682257
22-Nov-2002 13.346967
25-Nov-2002 13.030413
26-Nov-2002 14.342093
27-Nov-2002 13.533977
2-Dec-2002 14.452858
3-Dec-2002 12.610850
4-Dec-2002 12.788036
5-Dec-2002 12.876371
6-Dec-2002 13.298572
9-Dec-2002 13.219847
10-Dec-2002 13.083292
12-Dec-2002 14.683989
13-Dec-2002 17.292857
16-Dec-2002 19.244355
17-Dec-2002 19.096810
18-Dec-2002 20.394674
19-Dec-2002 22.845521
20-Dec-2002 20.554503
23-Dec-2002 19.814453
26-Dec-2002 19.576321
27-Dec-2002 18.601690
30-Dec-2002 18.163204
31-Dec-2002 18.549005
During 2002, average value at risk exposure was higher compared to 2001 due
to increased power marketing activities in ERCOT related to our retail energy
segment. Value at risk exposure dropped to lower levels at the end of 2002 as a
result of decreased liquidity in the energy trading and marketing industry,
which led to lower market volatility and consequently, lower value at risk. The
increase in value at risk during the middle of December 2002 was due to an
increase in market prices and an increase in market volatility.
The following chart presents the distribution of our daily margins for our
trading and marketing activities for our wholesale energy segment during 2002
(in millions):
Distribution of Daily Margin of the Trading Portfolio for Wholesale Energy
Segment
Year Ended December 31, 2002
[CHART]
($8-$10) ($6-$8) ($4-$6) ($2-$4) ($0-$2) $0-$2 $2-$4 $4-$6 $6-$8 $8-$10 $10-$12 >$12
- -------- ------- ------- ------- ------- ----- ----- ----- ----- ------ ------- ----
0 1 9 21 73 84 34 12 2 1 2 1
102
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 margins. Prior to 2002, 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. 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 CenterPoint's electricity utility division who did not select
another retail electric provider. 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 and operations. For a discussion of risk factors affecting our
operations, see "Management's Discussion and Analysis of Financial Condition
and Results of Operations--Risk Factors" in Item 7 of this Form 10-K.
Derivative instruments, which we use as economic hedges, create exposure to
commodity prices, which, in turn, 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 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, 2002 levels would have decreased the fair value of our
non-trading energy derivatives by $72 million, excluding non-trading derivative
liabilities associated with our European energy segment's stranded cost import
contract.
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 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 and 2002, we recognized a gain of $37 million and a
loss of $8 million, respectively, in our results of operations due to hedge
ineffectiveness.
Our European energy segment's stranded cost import contracts have exposure
to commodity prices. A portion of this exposure has been hedged with financial
derivatives as of December 31, 2002. For information regarding these contracts,
see notes 7(b) and 14(j) to our consolidated financial statements. A decrease
of 10% in market prices of energy commodities from their December 31, 2002
levels would result in a loss of earnings of $10 million, including the impact
on the related hedging instruments.
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. For information regarding the impact of our
March 2003 refinancing of our credit facilities on interest expense, see
"Liquidity and Capital Resources--Consolidated Future Uses and Sources of Cash
and Certain Factors Impacting Future Uses and Sources of Cash" in Item 7 of
this Form 10-K.
103
Our floating-rate obligations aggregated $1.1 billion and $6.7 billion at
December 31, 2001 and 2002, respectively. If the floating interest rates were
to increase by 10% from December 31, 2002 rates, our interest expense would
increase by a total of $2 million each month in which such increase continued.
At December 31, 2001 and 2002, we had issued fixed-rate debt to third
parties aggregating $121 million and $637 million, excluding Liberty's
fixed-rate debt of $165 million. As of December 31, 2001, fair values were
estimated to be equivalent to the carrying amounts of these instruments. As of
December 31, 2002, the fair-market value of our fixed-rate debt, excluding
Liberty's fixed-rate debt of $165 million, was $448 million. 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, excluding Liberty's fixed-rate debt, would increase by $32 million
if interest rates were to decline by 10% from their rates at December 31, 2002.
For a discussion regarding the fair value of the $165 million Liberty
fixed-rate debt, see note 18 to our consolidated financial statements.
As of December 31, 2002, we have interest rate swap contracts with an
aggregate notional amount of $1.1 billion that fix the interest rate applicable
to floating rate short-term debt and floating rate long-term debt. These swaps
could be terminated at a cost of $65 million at December 31, 2002. These swaps
qualify for hedge accounting under SFAS No. 133 and the periodic settlements
are recognized as an adjustment to interest expense in the results of
operations over the term of the swap agreement. A decrease of 10% in the
December 31, 2002 level of interest rates would increase the cost of
terminating the swaps by $9 million. For information regarding the accounting
for these interest rate swaps, see notes 7(b) and 9(d) to our consolidated
financial statements.
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
currencies, although the majority of its business is conducted in the Euro and
prior to January 2001, the Dutch Guilder. Until December 2002, we substantially
hedged our entire net investment in our European subsidiaries against a
material decline of the Euro through a combination of Euro-denominated
borrowings, foreign currency swaps, options and forward contracts to reduce our
exposure to changes in foreign currency rates. In December 2002, we reduced our
hedged position by approximately $1.1 billion to $1.4 billion by using a
combination of Euro-denominated borrowings and foreign currency options to
reduce our exposure to changes in foreign currency rates. Changes in the value
of the foreign currency hedging instruments and debt are recorded as foreign
currency translation adjustments as a component of accumulated other
comprehensive loss in stockholders' equity. As of December 31, 2001 and 2002,
we had recorded a loss of $96 million and a gain of $33 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. In February
2003, we signed a share purchase agreement to sell our European energy
operations to Nuon, a Netherlands-based electricity distributor. For a
discussion of the sale, see note 21(b) to our consolidated financial statements.
As of December 31, 2002, our European energy segment had entered into
transactions to purchase $143 million at fixed exchange rates in order to hedge
future fuel purchases payable in U.S. dollars. As of December 31, 2002, the
fair value of these financial instruments was a $2 million liability. An
increase in the value of the Euro of 10% compared to the U.S. dollar from their
December 31, 2002 levels would result in a loss in the fair value of these
foreign currency financial instruments of $13 million.
Our European energy segment's stranded cost import contracts have foreign
currency exposure. A decrease of 10% in the U.S. dollar relative to the Euro
from their December 31, 2002 levels would result in a loss of earnings of $10
million.
104
Equity Price Risk. We have equity investments, which are classified as
"available-for-sale" under SFAS No. 115. As of December 31, 2001 and 2002, the
value of these securities was $12 million and $3 million, respectively. A 10%
decline in the market value per share of these securities from December 31,
2002 would decrease the fair value by less than $1 million.
Risk Management Structure
We have a risk control framework designed to limit, monitor, measure and
manage the risk in our existing portfolio of assets and contracts and to
authorize new transactions. These risks include market, credit and liquidity
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, value at risk 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 periodically
reviews the adequacy of our risk assessment and risk management controls and
policies with our management and director of internal auditing.
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 officers and includes a working group 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;
. determines the position reporting requirements for trading and marketing
activity;
. recommends adjustments to trading limits, products and policies to the
audit committee of our board of directors;
. approves business segments' detailed risk control policies;
. allocates board of director-approved trading and marketing risk capital
limits, including value at risk limits;
. approves new trading, marketing and hedging products and commodities;
. 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.
105
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 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
has corporate-wide oversight for maintaining consistent application of
corporate risk policies within individual business segments. The corporate risk
control organization is also directly responsible for all business unit risk
control activities. 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 allocation of risk limits within our business segments;
. reviews inherent risks in proposed transactions;
. reviews daily position reports of trading and marketing activities;
. 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 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;
. 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 value at risk
violations, are reported to the appropriate level of management in the business
segment and corporate organization, 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 in reviews.
106
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/or bankruptcy of customers or counterparties.
For information regarding a loss related to certain of our natural gas
trading positions in the first quarter of 2003, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations--EBIT by Business
Segment--Wholesale Energy" in Item 7 of this Form 10-K.
107
ITEM 8. Financial Statements and Supplementary Data.
INDEX TO FINANCIAL STATEMENTS
RELIANT RESOURCES, INC. AND SUBSIDIARIES
Independent Auditors' Report....................................................................... F-2
Statements of Consolidated Operations for the Years Ended December 31, 2000, 2001 and 2002......... F-3
Consolidated Balance Sheets as of December 31, 2001 and 2002....................................... F-4
Statements of Consolidated Cash Flows for the Years Ended December 31, 2000, 2001 and 2002......... F-5
Statements of Consolidated Stockholders' Equity and Comprehensive Income (Loss) for the Years Ended
December 31, 2000, 2001 and 2002................................................................. F-6
Notes to Consolidated Financial Statements......................................................... F-7
Supplementary Data................................................................................. 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, 2001 and
2002, and the related consolidated statements of operations, stockholders'
equity and comprehensive income (loss), and cash flows for each of the three
years in the period ended December 31, 2002. Our audits also include the
financial statement schedule listed in the Index at Item 15(a)(2). These
financial statements and the financial statement schedule are the
responsibility of the Company's management. Our responsibility is to express an
opinion on these financial statements and the financial statement schedule
based on our audits.
We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the
financial statements are free of material misstatement. An audit includes
examining, on a test basis, evidence supporting the amounts and disclosures in
the financial statements. An audit also includes assessing the accounting
principles used and significant estimates made by management, as well as
evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2001 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002, 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 notes 7, 6 and 2 to the consolidated financial statements,
the Company changed its method of accounting for derivative instruments and
hedging activities in 2001 and changed its method of accounting for goodwill
and other intangibles and its method of presenting its trading and marketing
activities from a gross basis to a net basis in 2002, respectively.
As discussed in note 1, the accompanying 2000 and 2001 consolidated
financial statements have been restated.
DELOITTE & TOUCHE LLP
Houston, Texas
March 31, 2003
F-2
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
(Thousands of Dollars, except per share amounts)
Year Ended December 31,
---------------------------------------
2000 2001 2002
------------- ------------- -----------
(As Restated, (As Restated,
see note 1) see note 1)
Revenues:
Revenues.................................................... $3,275,246 $6,129,942 $11,248,486
Trading margins (See notes 2(d) and 2(t))................... 199,793 369,436 309,512
---------- ---------- -----------
Total................................................... 3,475,039 6,499,378 11,557,998
---------- ---------- -----------
Expenses:
Fuel and cost of gas sold................................... 1,171,378 1,975,674 1,442,784
Purchased power............................................. 925,942 2,509,045 7,380,814
Accrual for payment to CenterPoint Energy, Inc.............. -- -- 128,300
Operation and maintenance................................... 422,314 494,286 903,138
General, administrative and development..................... 304,061 503,150 665,030
European energy goodwill impairment......................... -- -- 481,927
Depreciation................................................ 114,825 152,479 385,066
Amortization................................................ 78,857 94,285 50,858
---------- ---------- -----------
Total................................................... 3,017,377 5,728,919 11,437,917
---------- ---------- -----------
Operating Income............................................... 457,662 770,459 120,081
---------- ---------- -----------
Other (Expense) Income:
(Losses) gains from investments, net........................ (16,509) 22,040 (24,215)
Income of equity investment of unconsolidated subsidiaries.. 42,860 57,440 22,617
Gain on sale of development project......................... 18,011 -- --
Other, net.................................................. 5,963 8,890 33,426
Interest expense............................................ (42,337) (63,268) (304,201)
Interest income............................................. 17,732 26,645 35,431
Interest (expense) income--affiliated companies, net........ (172,269) 12,477 4,754
---------- ---------- -----------
Total other (expense) income............................ (146,549) 64,224 (232,188)
---------- ---------- -----------
Income (Loss) Before Income Taxes, Cumulative Effect of
Accounting Change and Extraordinary Item..................... 311,113 834,683 (112,107)
Income Tax Expense............................................. 95,893 274,394 214,105
---------- ---------- -----------
Income (Loss) Before Cumulative Effect of Accounting Change
and Extraordinary Item....................................... 215,220 560,289 (326,212)
Cumulative effect of accounting change, net of tax.......... -- 3,062 (233,600)
Extraordinary item, net of tax.............................. 7,445 -- --
---------- ---------- -----------
Net Income (Loss)....................................... $ 222,665 $ 563,351 $ (559,812)
========== ========== ===========
Basic and Diluted Earnings (Loss) per Share:
Income (loss) before cumulative effect of accounting change. $ 2.02 $ (1.12)
Cumulative effect of accounting change, net of tax.......... 0.01 (0.81)
---------- -----------
Net income (loss)....................................... $ 2.03 $ (1.93)
========== ===========
See Notes to our Consolidated Financial Statements
F-3
RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(Thousands of Dollars)
December 31,
-------------------------
2001 2002
------------- -----------
(As Restated,
ASSETS see note 1)
Current Assets:
Cash and cash equivalents....................................................................... $ 118,453 $ 1,226,526
Restricted cash................................................................................. 167,421 218,769
Accounts and notes receivable and accrued unbilled revenues, principally customer, net.......... 1,182,140 1,522,906
Note receivable related to receivables facility................................................. -- 169,582
Accounts and notes receivable--affiliated companies, net........................................ 415,081 --
Inventory....................................................................................... 174,035 318,893
Stranded costs settlement receivable............................................................ 201,503 --
Trading and marketing assets.................................................................... 1,046,116 660,014
Non-trading derivative assets................................................................... 392,900 365,985
Margin deposits on energy trading and hedging activities........................................ 213,727 342,452
Collateral for electric generating equipment.................................................... 141,701 --
Accumulated deferred income taxes............................................................... 20,814 58,872
Prepayments and other current assets............................................................ 126,936 187,504
----------- -----------
Total current assets......................................................................... 4,200,827 5,071,503
----------- -----------
Property, Plant and Equipment, net................................................................. 4,558,542 8,940,759
----------- -----------
Other Assets:
Goodwill, net................................................................................... 890,912 1,540,506
Other intangibles, net.......................................................................... 315,438 736,689
Notes receivable--affiliated companies, net..................................................... 30,278 --
Equity investments in unconsolidated subsidiaries............................................... 386,841 313,112
Trading and marketing assets.................................................................... 393,196 311,989
Non-trading derivative assets................................................................... 254,168 97,810
Stranded costs indemnification receivable....................................................... 203,693 202,647
Accumulated deferred income taxes............................................................... 71,907 3,430
Prepaid lease................................................................................... 121,699 200,052
Restricted cash................................................................................. -- 7,000
Collateral for electric generating equipment.................................................... 88,268 --
Other........................................................................................... 203,645 211,323
----------- -----------
Total other assets........................................................................... 2,960,045 3,624,558
----------- -----------
Total Assets................................................................................. $11,719,414 $17,636,820
=========== ===========
LIABILITIES AND STOCKHOLDERS' EQUITY
Current Liabilities:
Current portion of long-term debt and short-term borrowings..................................... $ 320,538 $ 1,449,845
Accounts payable, principally trade............................................................. 1,002,326 1,062,541
Trading and marketing liabilities............................................................... 913,059 542,121
Non-trading derivative liabilities.............................................................. 399,277 342,725
Margin deposits from customers on energy trading and hedging activities......................... 144,700 50,203
Retail customer deposits........................................................................ 8 51,750
Accumulated deferred income taxes............................................................... 57,848 18,567
Other........................................................................................... 253,792 408,192
----------- -----------
Total current liabilities.................................................................... 3,091,548 3,925,944
----------- -----------
Other Liabilities:
Accumulated deferred income taxes............................................................... 25,585 503,033
Trading and marketing liabilities............................................................... 308,372 239,794
Non-trading derivative liabilities.............................................................. 639,211 315,301
Major maintenance reserve....................................................................... 16,784 23,023
Accrual for payment to CenterPoint Energy, Inc.................................................. -- 128,300
Non-derivative stranded costs liability......................................................... 203,693 202,647
Benefit obligations............................................................................. 127,012 138,365
Other........................................................................................... 455,865 462,445
----------- -----------
Total other liabilities...................................................................... 1,776,522 2,012,908
----------- -----------
Long-term Debt..................................................................................... 867,712 6,045,080
----------- -----------
Commitments and Contingencies (note 14)
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; 299,804,000 issued).. 61 61
Additional paid-in capital...................................................................... 5,789,869 5,836,957
Treasury stock at cost, 11,000,000 and 9,198,766 shares......................................... (189,460) (158,483)
Retained earnings............................................................................... 563,351 3,539
Accumulated other comprehensive loss............................................................ (180,189) (29,186)
----------- -----------
Stockholders' equity......................................................................... 5,983,632 5,652,888
----------- -----------
Total Liabilities and Stockholders' Equity................................................ $11,719,414 $17,636,820
=========== ===========
See Notes to our Consolidated Financial Statements
F-4
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(Thousands of Dollars)
Year Ended December 31,
---------------------------------------
2000 2001 2002
------------- ------------- -----------
(As Restated, (As Restated,
Cash Flows from Operating Activities: see note 1) see note 1)
Net income (loss)..................................................................... $ 222,665 $ 563,351 $ (559,812)
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating
activities:
European energy goodwill impairment................................................. -- -- 481,927
Depreciation and amortization....................................................... 193,682 246,764 435,924
Deferred income taxes............................................................... (27,476) 32,540 255,097
Net trading and marketing assets and liabilities.................................... (3,984) (185,136) 22,923
Net non-trading derivative assets and liabilities................................... -- 23,327 (49,878)
Net amortization of contractual rights and obligations.............................. -- -- (3,306)
Curtailment and related benefit enhancement......................................... -- 99,523 --
Accounting settlement for certain benefit plans..................................... -- -- 47,356
Contributions of marketable securities to charitable foundation..................... 15,172 -- --
Impairment of marketable equity securities and other investments.................... 26,504 -- 31,780
Undistributed earnings of unconsolidated subsidiaries............................... (24,931) (30,280) (19,642)
Accrual for payment to CenterPoint, Inc............................................. -- -- 128,300
Gain on sale of development project................................................. (18,011) -- --
Stranded cost indemnification settlement gain....................................... -- (36,881) --
Stranded cost contracts settlement gain............................................. -- -- (109,000)
Cumulative effect of accounting change.............................................. -- (3,062) 233,600
Extraordinary item.................................................................. (7,445) -- --
Other, net.......................................................................... (2,034) (11,712) (21,157)
Changes in other assets and liabilities:
Restricted cash.................................................................... (50,000) (117,421) 276,319
Accounts and notes receivable and unbilled revenue, net............................ (1,174,918) 582,629 90,096
Accounts receivable/payable--affiliated companies, net............................. (168,692) 92,906 26,603
Inventory.......................................................................... (9,468) (59,153) (86,364)
Collateral for electric generating equipment, net.................................. (84,879) (145,090) 136,013
Margin deposits on energy trading and hedging activities, net...................... (206,480) 167,374 (219,652)
Net non-trading derivative assets and liabilities.................................. -- (117,858) (150,964)
Prepaid lease obligation........................................................... -- (180,531) (78,551)
Proceeds from sale of debt securities.............................................. 123,428 -- --
Other current assets............................................................... (92,719) 102,348 (51,426)
Other assets....................................................................... (103,692) (39,882) (13,787)
Accounts payable................................................................... 1,465,925 (1,064,239) (114,118)
Taxes payable/receivable........................................................... 57,016 (13,368) (11,170)
Other current liabilities.......................................................... 209,216 (55,984) 67
Other liabilities.................................................................. (11,337) 22,814 (66,662)
----------- ----------- -----------
Net cash provided by (used in) operating activities............................... 327,542 (127,021) 610,516
----------- ----------- -----------
Cash Flows from Investing Activities:
Capital expenditures.................................................................. (933,180) (839,908) (660,526)
Business acquisitions, net of cash acquired........................................... (2,121,408) -- (2,963,801)
Proceeds from sale-leaseback transactions............................................. 1,000,000 -- --
Payment of business purchase obligation............................................... (981,789) -- --
Investments in unconsolidated subsidiaries............................................ (5,755) -- --
Distribution from equity investment in unconsolidated subsidiary...................... -- -- 137,475
Other, net............................................................................ 28,830 1,839 674
----------- ----------- -----------
Net cash used in investing activities............................................. (3,013,302) (838,069) (3,486,178)
----------- ----------- -----------
Cash Flows from Financing Activities:
Proceeds from long-term debt.......................................................... 770,009 -- 22,324
Proceeds from issuance of stock, net.................................................. -- 1,696,074 --
Payments of long-term debt............................................................ (307,201) (4,084) (242,478)
(Decrease) increase in short-term borrowings, net..................................... (31,906) 217,323 3,845,505
Change in notes with affiliated companies, net........................................ 1,219,946 (731,894) 385,652
Purchase of treasury stock............................................................ -- (189,460) --
Contributions from CenterPoint........................................................ 1,094,259 9,441 --
Payments of financing costs........................................................... (108) (1,330) (43,209)
Other, net............................................................................ (23,843) 3,470 12,932
----------- ----------- -----------
Net cash provided by financing activities......................................... 2,721,156 999,540 3,980,726
----------- ----------- -----------
Effect of Exchange Rate Changes on Cash and Cash Equivalents........................... 5,088 (5,752) 3,009
----------- ----------- -----------
Net Increase in Cash and Cash Equivalents.............................................. 40,484 28,698 1,108,073
Cash and Cash Equivalents at Beginning of Year......................................... 49,271 89,755 118,453
----------- ----------- -----------
Cash and Cash Equivalents at End of Year............................................... $ 89,755 $ 118,453 $ 1,226,526
=========== =========== ===========
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest (net of amounts capitalized)............................................... $ 205,103 $ 84,650 $ 301,462
Income taxes........................................................................ 72,784 243,740 10,027
See Notes to our Consolidated Financial Statements
F-5
RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Thousands of Dollars)
Unrealized
Additional (Loss) Gain on
Common Treasury Paid-In Retained Available For
Stock Stock Capital Earnings Sale Securities
------ --------- ---------- ----------- ---------------
Balance December 31, 1999........................................... $-- $ -- $ -- $ 757,751 $(17,228)
Net income (As Restated, see note 1)............................... 222,665
Contributions from CenterPoint..................................... 1,369,278
Transfer to common stock and additional paid-in capital............ 1 2,349,693 (2,349,694)
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......................................................... 17,228
Unrealized loss on available-for-sale securities, net of tax of
$1 million...................................................... (2,264)
Comprehensive income (As Restated, see note 1)...................
--- --------- ---------- ----------- --------
Balance December 31, 2000 (As Restated, see note 1)................. 1 -- 2,349,693 -- (2,264)
Net income (As Restated, see note 1)............................... 563,351
Contributions from CenterPoint..................................... 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 $236 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 $35 million......................
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 net income, net of tax of $5
million......................................................... (8,670)
Comprehensive income (As Restated, see note 1)...................
--- --------- ---------- ----------- --------
Balance December 31, 2001 (As Restated, see note 1)................. 61 (189,460) 5,789,869 563,351 6,050
Net loss........................................................... (559,812)
Contributions from CenterPoint..................................... 47,088
Issuance of treasury stock......................................... 30,977
Other comprehensive income (loss):
Foreign currency translation adjustments, net of tax of $113
million.........................................................
Changes in minimum non-qualified pension liability, net of
tax of $3 million...............................................
Deferred gain from cash flow hedges, net of tax of $31
million.........................................................
Reclassification of net deferred gain from cash flow hedges
into net loss, net of tax of $8 million.........................
Unrealized loss on available-for-sale securities, net of tax of
$1 million...................................................... (1,672)
Reclassification adjustments for gains on sales of available-
for-sale securities realized in net loss, net of tax of $2
million......................................................... (3,262)
Comprehensive loss...............................................
--- --------- ---------- ----------- --------
Balance December 31, 2002........................................... $61 $(158,483) $5,836,957 $ 3,539 $ 1,116
=== ========= ========== =========== ========
Deferred Foreign Additional Total
Derivative Currency Minimum Accumulated Other
Gains Translation Benefits Comprehensive
(Losses) Adjustments Liability (Loss) Income
---------- ----------- ---------- -----------------
Balance December 31, 1999........................................... $ -- $ 162 $ -- $ (17,066)
Net income (As Restated, see note 1)...............................
Contributions from CenterPoint.....................................
Transfer to common stock and additional paid-in capital............
Other comprehensive income (loss):
Foreign currency translation adjustments......................... (1,726) (1,726)
Additional minimum non-qualified pension liability
adjustment, net of tax of $0.4 million.......................... (716) (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 (As Restated, see note 1)...................
--------- -------- ------- ---------
Balance December 31, 2000 (As Restated, see note 1)................. -- (1,564) (716) (4,544)
Net income (As Restated, see note 1)...............................
Contributions from CenterPoint.....................................
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) (94,066)
Changes in minimum non-qualified pension liability, net of
tax of $4 million............................................... (6,799) (6,799)
Cumulative effect of adoption of SFAS No. 133, net of tax
of $236 million................................................. (459,944) (459,944)
Deferred gain from cash flow hedges, net of tax of $228
million......................................................... 427,994 427,994
Reclassification of net deferred gain from cash flow hedges
into net income, net of tax of $35 million...................... (51,144) (51,144)
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 net income, net of tax of $5
million......................................................... (8,670)
Comprehensive income (As Restated, see note 1)...................
--------- -------- ------- ---------
Balance December 31, 2001 (As Restated, see note 1)................. (83,094) (95,630) (7,515) (180,189)
Net loss...........................................................
Contributions from CenterPoint.....................................
Issuance of treasury stock.........................................
Other comprehensive income (loss):
Foreign currency translation adjustments, net of tax of $113
million......................................................... 128,450 128,450
Changes in minimum non-qualified pension liability, net of
tax of $3 million............................................... 4,869 4,869
Deferred gain from cash flow hedges, net of tax of $31
million......................................................... 38,437 38,437
Reclassification of net deferred gain from cash flow hedges
into net loss, net of tax of $8 million......................... (15,819) (15,819)
Unrealized loss on available-for-sale securities, net of tax of
$1 million...................................................... (1,672)
Reclassification adjustments for gains on sales of available-
for-sale securities realized in net loss, net of tax of $2
million......................................................... (3,262)
Comprehensive loss...............................................
--------- -------- ------- ---------
Balance December 31, 2002........................................... $ (60,476) $ 32,820 $(2,646) $ (29,186)
========= ======== ======= =========
Total
Stockholders' Comprehensive
Equity Income (Loss)
------------- -------------
Balance December 31, 1999........................................... $ 740,685
Net income (As Restated, see note 1)............................... 222,665 $ 222,665
Contributions from CenterPoint..................................... 1,369,278
Transfer to common stock and additional paid-in capital............ --
Other comprehensive income (loss):
Foreign currency translation adjustments......................... (1,726) (1,726)
Additional minimum non-qualified pension liability
adjustment, net of tax of $0.4 million.......................... (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
Unrealized loss on available-for-sale securities, net of tax of
$1 million...................................................... (2,264) (2,264)
---------
Comprehensive income (As Restated, see note 1)................... $ 235,187
---------- =========
Balance December 31, 2000 (As Restated, see note 1)................. 2,345,150
Net income (As Restated, see note 1)............................... 563,351 $ 563,351
Contributions from CenterPoint..................................... 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)
Changes in minimum non-qualified pension liability, net of
tax of $4 million............................................... (6,799) (6,799)
Cumulative effect of adoption of SFAS No. 133, net of tax
of $236 million................................................. (459,944) (459,944)
Deferred gain from cash flow hedges, net of tax of $228
million......................................................... 427,994 427,994
Reclassification of net deferred gain from cash flow hedges
into net income, net of tax of $35 million...................... (51,144) (51,144)
Unrealized gain on available-for-sale securities, net of tax of
$9 million...................................................... 16,984 16,984
Reclassification adjustments for gains on sales of available-
for-sale securities realized in net income, net of tax of $5
million......................................................... (8,670) (8,670)
---------
Comprehensive income (As Restated, see note 1)................... $ 387,706
---------- =========
Balance December 31, 2001 (As Restated, see note 1)................. 5,983,632
Net loss........................................................... (559,812) $(559,812)
Contributions from CenterPoint..................................... 47,088
Issuance of treasury stock......................................... 30,977
Other comprehensive income (loss):
Foreign currency translation adjustments, net of tax of $113
million......................................................... 128,450 128,450
Changes in minimum non-qualified pension liability, net of
tax of $3 million............................................... 4,869 4,869
Deferred gain from cash flow hedges, net of tax of $31
million......................................................... 38,437 38,437
Reclassification of net deferred gain from cash flow hedges
into net loss, net of tax of $8 million......................... (15,819) (15,819)
Unrealized loss on available-for-sale securities, net of tax of
$1 million...................................................... (1,672) (1,672)
Reclassification adjustments for gains on sales of available-
for-sale securities realized in net loss, net of tax of $2
million......................................................... (3,262) (3,262)
---------
Comprehensive loss............................................... $(408,809)
---------- =========
Balance December 31, 2002........................................... $5,652,888
==========
See Notes to our Consolidated Financial Statements
F-6
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
For the Three Years Ended December 31, 2000, 2001 and 2002
(1) BACKGROUND AND BASIS OF PRESENTATION
Reliant Resources, Inc., a Delaware corporation, was incorporated in August
2000 with 1,000 shares of common stock which were owned by Reliant Energy,
Incorporated (Reliant Energy). We refer to Reliant Resources, Inc. as "Reliant
Resources," and to Reliant Resources and its subsidiaries collectively, as
"we," "us," or "our," unless the context clearly indicates otherwise. We
provide electricity and energy services with a focus on the competitive retail
and wholesale segments of the electric power industry in the United States.
Throughout much of Texas, we provide standardized electricity and related
products and services to residential and small commercial customers with an
aggregate peak demand for power up to one megawatt (MW) and offer customized
electric commodity and energy management services to large commercial,
industrial and institutional customers with an aggregate peak demand for power
in excess of one MW. We have built a portfolio of electric power generation
facilities, through a combination of acquisitions and development, that are not
subject to traditional cost-based regulation; therefore we can generally sell
electricity at prices determined by the market, subject to regulatory
limitations. We trade and market electricity, natural gas, natural gas
transportation capacity and other energy-related commodities. We also optimize
our physical assets and provide risk management services for our asset
portfolio. In March 2003, we decided to exit our proprietary trading activities
and liquidate, to the extent practicable, our proprietary positions. Although
we are exiting the proprietary trading business, we have existing positions,
which will be closed as economically feasible or in accordance with their
terms. We will continue to engage in hedging activities related to our electric
generating facilities, pipeline storage positions and fuel positions.
Reliant Energy 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 (PUCT), Reliant Energy transferred
substantially all of its unregulated businesses to Reliant Resources in order
to separate its regulated and unregulated operations. In accordance with the
plan, 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. For additional information
regarding the IPO, see notes 3 and 10(a).
CenterPoint Energy, Inc. was formed on August 31, 2002 as the new holding
company of Reliant Energy. We refer to CenterPoint Energy, Inc. and its
predecessor company, Reliant Energy, as "CenterPoint." Unless clearly indicated
otherwise these references to "CenterPoint" mean CenterPoint Energy, Inc. on or
after August 31, 2002 and Reliant Energy prior to August 31, 2002. CenterPoint
is a diversified international energy services and energy delivery company that
owned the majority of Reliant Resources outstanding common stock prior to
September 30, 2002. On September 30, 2002, CenterPoint distributed all of the
240 million shares of our common stock it owned to its common shareholders of
record as of the close of business on September 20, 2002 (Distribution). The
Distribution completed the separation of Reliant Resources and CenterPoint into
two separate publicly held companies.
The operations included in the consolidated financial statements for 2000
consist of CenterPoint's, or its direct and indirect subsidiaries', unregulated
power generation and related energy trading, marketing, 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 2000, CenterPoint and its direct
and indirect subsidiaries conducted these operations. Effective December 31,
2000, CenterPoint consolidated its unregulated operations under Reliant
Resources (Consolidation). A subsidiary of CenterPoint,
F-7
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Reliant Energy Resources Corp. (RERC Corp.), transferred some of its
subsidiaries, including its trading and marketing subsidiaries, to us. In
connection with the transfer from RERC Corp., we paid $94 million to RERC Corp.
Also effective December 31, 2000, CenterPoint transferred its wholesale power
generation businesses, its unregulated retail electric operations, its
communications business and most of its other unregulated businesses to us. In
accordance with accounting principles generally accepted in the United States
of America, the transfers from RERC Corp. and CenterPoint were accounted for as
a reorganization of entities under common control.
Restatement
Subsequent to the issuance of our financial statements as of and for the
year ended December 31, 2001, we identified four natural gas financial swap
transactions that should not have been recorded in our records. We have
concluded, based on the offsetting nature of the transactions and manner in
which the transactions were documented, that none of the transactions should
have been given accounting recognition. We previously accounted for these
transactions in our financial statements as a reduction in revenues in December
2000 and an increase in revenues in January 2001, with the effect of decreasing
net income in the fourth quarter of 2000 and increasing net income in the first
quarter of 2001, in each case by $20.0 million pre-tax ($12.7 million
after-tax) and the effect of increasing basic and diluted earnings per share by
$0.05 in the first quarter of 2001. There were no cash flows associated with
the transactions.
Also, subsequent to the issuance of our financial statements for 2001 and
for the first three quarters of 2002, we determined that we had incorrectly
calculated the amount of hedge ineffectiveness for 2001 and the first three
quarters of 2002 for hedging instruments entered into prior to the adoption of
Statement of Financial Accounting Standards (SFAS) No. 133 "Accounting for
Derivative Instruments and Hedging Activities," as amended (SFAS No. 133).
These hedging instruments included long-term forward contracts for the sale of
power in the California market through December 2006. The amount of hedge
ineffectiveness for these forward contracts was calculated using the trade
date. However, the proper date for the hedge ineffectiveness calculation is
hedge inception, which for these contracts was deemed to be January 1, 2001,
concurrent with the adoption of SFAS No. 133. These errors in accounting for
hedge ineffectiveness resulted in an understatement of revenues of $28.7
million ($18.6 million after-tax) and earnings per share of $0.07 in 2001.
The consolidated financial statements for 2000 and 2001 have been restated
from amounts previously reported to remove the effects of the four natural gas
swap transactions from 2000 and 2001 and to correctly account for the amount of
hedge ineffectiveness in 2001. The restatement had no impact on previously
reported consolidated operating, investing and financing cash flows for 2000 or
2001. The following is a summary of the principal effects of the restatement
for 2000 and 2001: (Note--Those line items for which no change in amounts are
shown were not affected by the restatement.)
F-8
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Year Ended
December 31, 2000
----------------------
As As Previously
Restated Reported(1)
-------- -------------
(in millions)
Revenues.................................................................... $3,275 $3,255
Trading margins............................................................. 200 200
------ ------
Total revenues........................................................... 3,475 3,455
Total operating expenses.................................................... 3,017 3,017
------ ------
Operating income............................................................ 458 438
Other expense, net.......................................................... 147 147
------ ------
Income before income tax expense and extraordinary item..................... 311 291
Income tax expense.......................................................... 95 88
------ ------
Income before extraordinary item............................................ 216 203
Extraordinary item.......................................................... 7 7
------ ------
Net income.................................................................. $ 223 $ 210
====== ======
Year Ended
December 31, 2001
----------------------
As As Previously
Restated Reported(1)
-------- -------------
(in millions)
Revenues.................................................................... $6,130 $6,122
Trading margins............................................................. 369 369
------ ------
Total revenues........................................................... 6,499 6,491
Total operating expenses.................................................... 5,729 5,729
------ ------
Operating income............................................................ 770 762
Other income, net........................................................... 64 64
------ ------
Income before income tax expense and cumulative effect of accounting changes 834 826
Income tax expense....................................................... 274 272
------ ------
Income before cumulative effect of accounting change........................ 560 554
Cumulative effect of accounting change...................................... 3 3
------ ------
Net income.................................................................. $ 563 $ 557
====== ======
Basic Earnings Per Share:
Income before cumulative effect of accounting change..................... $ 2.02 $ 2.00
Cumulative effect of accounting change, net of tax....................... 0.01 0.01
------ ------
Net income........................................................... $ 2.03 $ 2.01
====== ======
F-9
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
December 31, 2001
---------------------
As As Previously
Restated Reported(2)
-------- -------------
ASSETS (in millions)
Current assets........................................ $ 4,201 $ 4,201
Total long-term assets................................ 7,518 7,518
------- -------
Total Assets................................... $11,719 $11,719
======= =======
LIABILITIES AND STOCKHOLDERS' EQUITY
Current liabilities................................... $ 3,091 $ 3,091
Total long-term liabilities........................... 2,644 2,644
Stockholders' Equity:
Preferred stock.................................... -- --
Common Stock....................................... -- --
Additional paid-in capital......................... 5,790 5,777
Treasury stock..................................... (189) (189)
Retained earnings.................................. 563 557
Accumulated other comprehensive loss............... (180) (161)
------- -------
Stockholders' equity........................... 5,984 5,984
------- -------
Total Liabilities and Stockholders' Equity..... $11,719 $11,719
======= =======
- --------
(1) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis as allowed by
Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for
Contracts involved in Energy Trading and Risk Management Activities" (EITF
No. 98-10). Comparative financial statements for prior periods have been
reclassified to conform to this presentation. For information regarding the
presentation of trading and marketing activities on a net basis, see note
2(t). Revenues, fuel and cost of gas sold expense and purchased power
expense have been reclassified to conform to this presentation.
(2) Some amounts from the previous years have been reclassified to conform to
the presentation of our consolidated balance sheet as of December 31, 2002.
These reclassifications do not affect stockholders' equity or net income.
The effects of the restatement discussed above on the unaudited condensed
quarterly financial statement information for 2001 and 2002 have been included
in note 19.
Basis of Presentation
The accompanying consolidated financial statements for 2000 are presented on
a carve-out basis and include our historical operations. The financial
statements for 2000 have been prepared from CenterPoint's historical accounting
records.
The statements of consolidated operations include all revenues and costs
directly attributable to us, including costs for facilities and costs for
functions and services performed by centralized CenterPoint organizations and
directly charged to us based on usage or other allocation factors prior to the
Distribution. The results of operations in these consolidated financial
statements also include general corporate expenses allocated by CenterPoint to
us prior to the Distribution. 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
we had operated as a separate entity prior to the Distribution.
F-10
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Our financial reporting segments include the following: retail energy,
wholesale energy, European energy and other operations. The retail energy
segment includes our retail electric operations and associated supply
activities. This segment provides customized, integrated energy services to
large commercial, industrial and institutional customers and standardized
electricity and related services to residential and small commercial customers
in Texas. 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 operates power generation
facilities in the Netherlands and conducts wholesale energy trading and
origination activities in Europe; see note 21(b) regarding the sale of our
European energy operations. The other operations segment primarily includes
unallocated general corporate expenses and non-operating investments.
(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
(a) Reclassifications.
Some amounts from the previous years have been reclassified to conform to
the 2002 presentation of financial statements. These reclassifications do not
affect earnings.
(b) Use of Estimates and Market Risk and Uncertainties.
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.
We are subject to the risk associated with price movements of energy
commodities and the credit risk associated with our trading, risk management,
hedging and retail electric activities. For additional information regarding
these risks, see notes 7, 14 and 17. We are also subject to risks relating to
effects of competition, changes in interest rates and foreign currencies,
results of financing efforts, operation of deregulating power markets, seasonal
weather patterns, availability of energy supply, availability of transmission
capacity, resolution of lawsuits and regulatory proceedings, technological
obsolescence and the regulatory environment in the United States and Europe. In
addition, we are subject to risks relating to the reliability of the systems,
procedures and other infrastructure necessary to operate our businesses.
(c) Principles of Consolidation.
Our accounts and those of our wholly-owned and majority owned subsidiaries
are included in the consolidated financial statements. All significant
intercompany transactions and balances are eliminated in consolidation. The
results of our European energy segment are consolidated on a one-month-lag
basis due to the availability of financial information. We have made
adjustments to the European energy segment's 2001 results of operations to
include the effect for the settlement of an indemnity for certain energy
obligations in December 2001 (see note 14(j)).
F-11
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
We use the equity method of accounting for investments in entities in which
we have an ownership interest between 20% and 50% and exercise significant
influence through representation on advisory or management committees. For our
equity method accounting investments, our representation on advisory or
management committees does not enable us to have majority control of the
investments' management and operating decisions. The allocation of profits and
losses is based on our ownership interest. For additional information regarding
investments recorded using the equity method of accounting, see note 8. Other
investments, excluding marketable securities, are carried at cost. For these
other investments, we do not exercise significant influence. For additional
information regarding these investments, see note 2(o).
In 2000, we entered into separate sale/leaseback transactions with each of
the three owner-lessors for our respective interests in three power generating
stations acquired in an acquisition. For additional discussion of these lease
transactions, see note 14(a). We do not consolidate these generating
facilities. 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. As of December 31, 2002, we did not consolidate these special purpose
entities. For information regarding these transactions, see note 14(b). In July
2002, we entered into a receivable facility arrangement with a financial
institution to sell an undivided interest in accounts receivable from
residential and small commercial retail electric customers under which, on an
ongoing basis, the financial institution will invest up to a maximum amount for
its interest in such receivables. Pursuant to this receivables facility, we
formed a qualified special purpose entity as a bankruptcy remote subsidiary. We
do not consolidate this qualified special purpose entity. For additional
information regarding this qualified special purpose entity, see note 15.
Each of Orion Power New York, LP (Orion NY), Orion Power New York LP, LLC,
Orion Power New York GP, Inc., Astoria Generating Company, L.P., Carr Street
Generating Station, LP, Erie Boulevard Hydropower, LP, Orion Power MidWest, LP
(Orion MidWest), Orion Power Midwest LP, LLC, Orion Power Midwest GP, Inc.,
Twelvepole Creek, LLC and Orion Power Capital, LLC (Orion Capital) is a
separate legal entity and has its own assets.
(d) Revenues.
We record gross revenue for energy sales and services related to our
electric power generation facilities under the accrual method and these
revenues generally are recognized upon delivery. Electric power and other
energy services are sold at market-based prices through existing power
exchanges or through third-party contracts. Energy sales and services related
to our electric power generation facilities not billed by month-end are accrued
based upon estimated energy and services delivered.
We record gross revenue for energy sales and services to residential, small
commercial and non-contracted large commercial, industrial and institutional
retail electric customers under the accrual method and these revenues generally
are recognized upon delivery. Our contracted electricity sales to large
commercial, industrial and institutional customers for contracts entered into
after October 25, 2002 are typically accounted for under the accrual method and
these revenues generally are recognized upon delivery (see note 2(t)). The
determination of these sales is based on the reading of the customers' meters
by the transmission and distribution utilities. The transmission and
distribution utilities send the information to the Electric Reliability Council
of Texas (ERCOT) Independent System Operator (ERCOT ISO), which in turn sends
the information to us. This activity occurs on a systematic basis throughout
the month. At the end of each month, amounts of energy delivered to customers
since the date of the last meter reading are estimated and the corresponding
unbilled revenue is estimated. This unbilled revenue is estimated each month
based on daily forecasted volumes, estimated customer usage by class,
F-12
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
weather factors and applicable customer rates based on analyses reflecting
significant historical trends and experience. As of December 31, 2001 and 2002,
our retail energy segment had accrued unbilled revenues of $14 million and $216
million, respectively.
Our energy trading, marketing, risk management services to customers and
certain power origination activities and our contracted electricity sales to
large commercial, industrial and institutional customers and the related energy
supply contracts for contracts entered into prior to October 25, 2002 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 fair value in revenues upon contract execution. The
net changes in their fair values are recognized in the statements of
consolidated operations as revenues in the period of change. Trading and
marketing revenues related to the sale of natural gas, electric power and other
energy related commodities are recorded on a net basis. 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 7. For a discussion of EITF No. 02-03, "Issues Related to Accounting
for Contracts Involved in Energy Trading and Risk Management Activities" (EITF
No. 02-03) rescinding EITF No. 98-10 and the presentation of trading and
marketing activities on a net basis beginning in the quarter ended September
30, 2002, see notes 2(t) and 7.
The gains and losses related to derivative instruments and contractual
commitments qualifying and designated as hedges related to the purchase and
sale of electric power and purchase of fuel are deferred in accumulated other
comprehensive income (loss) to the extent the contracts are effective as
hedges, and then are recognized in our results of operations in the same period
as the settlement of the underlying hedged transactions. Realized gains and
losses on financial derivatives designated as hedges are included in revenues
in the statements of consolidated operations. Revenues, fuel and cost of gas
sold, and purchased power related to physical sale and purchase contracts
designated as hedges are generally recorded on a gross basis in the delivery
period. For additional discussion, see note 7.
(e) General, Administrative and Development Expenses.
The general and administrative expenses in the statement of consolidated
operations include (a) employee-related costs of the trading, marketing, power
origination and risk management services operations, (b) certain contractor
costs, (c) advertising, (d) materials and supplies, (e) bad debt expense, (f)
marketing and market research, (g) corporate and administrative services
(including management services, financial and accounting, cash management and
treasury support, legal, information technology system support, office
management and human resources) and (h) certain benefit costs. Some of these
expenses were allocated from CenterPoint prior to the Distribution as further
discussed in notes 3 and 4(a).
(f) Property, Plant and Equipment and Depreciation Expense
We record property, plant and equipment at historical cost. We recognize
repair and maintenance costs incurred in connection with planned major
maintenance, such as turbine and generator overhauls, under the
"accrue-in-advance" method for our 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, we
estimate the costs of planned major maintenance and accrue the related expense
over the maintenance cycle. As of December 31, 2001 and 2002, our major
maintenance reserve was $19 million and $24 million, respectively, of which $2
million and $1 million, respectively, were included in other current
liabilities. We expense all other repair and maintenance costs as incurred. For
power generation operations acquired or developed subsequent to January 1,
2000, we expense all repair and maintenance costs as incurred, including
F-13
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
planned major maintenance. Depreciation is computed using the straight-line
method based on estimated useful lives. Property, plant and equipment includes
the following:
December 31,
Estimated Useful --------------
Lives (Years) 2001 2002
---------------- ------ ------
(in millions)
Electric generation facilities........ 10-50 $2,828 $8,163
Building and building improvements.... 9-32 14 24
Other................................. 3-10 164 442
Land and land improvements............ 147 261
Assets under construction............. 1,682 677
------ ------
Total.............................. 4,835 9,567
Accumulated depreciation.............. (276) (626)
------ ------
Property, plant and equipment, net. $4,559 $8,941
====== ======
(g) Goodwill and Amortization Expense.
We record goodwill for the excess of the purchase price over the fair value
assigned to the net assets of an acquisition. Through December 31, 2001, we
amortized goodwill on a straight-line basis over 5 to 40 years. Pursuant to our
adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142)
on January 1, 2002, we discontinued amortizing goodwill into our results of
operations. See note 6 for a discussion regarding our adoption of SFAS No. 142.
Goodwill amortization expense was $35 million and $51 million for 2000 and
2001, respectively. The 2001 goodwill amortization expense includes a $19
million goodwill impairment related to the communications business (see note
16). Amortization expense for other intangibles, excluding contractual rights
and obligations, was $44 million, $43 million and $51 million for 2000, 2001
and 2002, respectively. See also note 6.
The following table summarizes our acquisitions and the associated goodwill:
December 31,
Amortization --------------
Acquisition (1) Period (Years)(2) 2001 2002
- --------------- ----------------- ------ ------
(in millions)
Orion Power Holdings, Inc....................... -- $ -- $1,324
Reliant Energy Power Generation Benelux N.V..... 30 879 --
Reliant Energy Services, Inc.................... 40 131 131
California Generation Plants.................... 30 70 70
Energy Services Division of Southland Industries 15 37 37
Reliant Energy Mid-Atlantic Power Holdings, LLC. 35 6 7
Florida Generation Plant........................ 35 2 2
------ ------
Total........................................ 1,125 1,571
Accumulated amortization........................ (84) (30)
Foreign currency exchange impact................ (150) --
------ ------
Total goodwill, net.......................... $ 891 $1,541
====== ======
- --------
(1) Effective January 1, 2002, goodwill is evaluated for impairment on a
reporting unit basis in accordance with SFAS No. 142 (see note 6).
F-14
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(2) In accordance with SFAS No. 142, we discontinued amortizing goodwill into
our results of operations effective January 1, 2002 (see note 6). The
amortization periods presented relate to prior years' amortization.
We periodically evaluate long-lived assets, including goodwill and other
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, excluding goodwill and other intangibles beginning in
2002, is based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. A resulting impairment
loss is highly dependent on the underlying assumptions. During 2001, we
determined equipment and goodwill associated with our communications business
was impaired and accordingly recognized $22 million of equipment impairments
and $19 million of goodwill impairments (see note 16). In 2002, we recognized
impairment charges totaling $716 million relating to our European energy
segment goodwill (see note 6). During 2002, we determined that steam and
combustion turbines and two heat recovery steam generators purchased in
September 2002 were impaired and accordingly recognized a $37 million
impairment loss (see note 14(c)). For discussion of goodwill and other
intangible asset impairment analyses in 2002, see note 6.
(h) Stock-based Compensation Plans.
We apply the intrinsic method of accounting for employee stock-based
compensation plans in accordance with Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB No. 25). Under the
intrinsic value method, no compensation expense is recorded when options are
issued with an exercise price equal to the market price of the underlying stock
on the date of grant. Since our stock options have all been granted at market
value at date of grant, no compensation expense has been recognized under APB
No. 25. We comply with the disclosure requirements of SFAS No. 123, "Accounting
for Stock-Based Compensation" (SFAS No. 123) and SFAS No. 148, "Accounting for
Stock-Based Compensation--Transition and Disclosure, an amendment to SFAS No.
123" (SFAS No. 148) and disclose the pro forma effect on net income (loss) and
earnings (loss) per share as if the fair value method of accounting had been
applied to all stock awards. Had compensation costs been determined as
prescribed by SFAS No. 123, our net income (loss) and earnings (loss) per share
amounts would have approximated the following pro forma results for 2000, 2001
and 2002, which take into account the amortization of stock-based compensation,
including performance shares, purchases under the employee stock purchase plan
and stock options, to expense on a straight-line basis over the vesting periods:
Year Ended
December 31,
-----------------------
2000 2001 2002
---- ----- ------
(in millions, except per
share amounts)
Net income (loss), as reported.......................................... $223 $ 563 $ (560)
Add: Stock-based employee compensation expense included in reported net
income/loss, net of related tax effects............................... 4 5 2
Deduct: Total stock-based employee compensation expense determined under
fair value based method for all awards, net of related tax effects.... (7) (34) (38)
---- ----- ------
Pro forma net income (loss)............................................. $220 $ 534 $ (596)
==== ===== ======
Earnings (loss) per share:
Basic and diluted, as reported....................................... $2.03 $(1.93)
===== ======
Basic and diluted, pro forma......................................... $1.93 $(2.05)
===== ======
F-15
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
For further information regarding our stock-based compensation plans and our
assumptions used to compute pro forma amounts, see note 12.
(i) 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
2000, 2001 and 2002, we capitalized interest of $35 million, $59 million and
$27 million, respectively.
(j) Income Taxes.
Prior to September 30, 2002, we were included in the consolidated federal
income tax returns of CenterPoint and we calculated our income tax provision on
a separate return basis under a tax sharing agreement with CenterPoint.
Pursuant to the tax sharing agreement with CenterPoint and agreements entered
into at the time of the Distribution (see Note 4(a)), CenterPoint will owe us
amounts related to certain loss carryovers, income inclusions from foreign
affiliates, net income tax receivables/payables relating to our operations
prior to the Distribution and other tax liabilities. Prior to September 30,
2002, current federal and some state income taxes were payable to or receivable
from CenterPoint. Subsequent to the Distribution, we will file a separate
federal tax return.
We use the liability method of accounting for deferred income taxes and
measure deferred income taxes for all significant income tax temporary
differences. Unremitted earnings from our foreign operations are deemed to be
permanently reinvested in foreign operations. For additional information
regarding income taxes, see note 13.
(k) Cash.
We record as cash and cash equivalents all highly liquid short-term
investments with original maturities of three months or less.
(l) Restricted Cash.
Restricted cash includes cash at certain subsidiaries that is restricted by
financing agreements, but is available to the applicable subsidiary to use to
satisfy certain of its obligations. As of December 31, 2001 and 2002, we had
$167 million and $226 million in restricted cash, respectively, recorded in the
consolidated balance sheets.
The credit facilities of certain subsidiaries of Orion Power Holdings, Inc.
(Orion Power) contain various covenants that include, among others,
restrictions on the payment of dividends to Orion Power and us. As of December
31, 2002, restricted cash under Orion Power's subsidiaries' credit facilities
totaled $200 million. For further information, see note 9(a). In addition,
senior notes of Orion Power restrict its ability to pay dividends to us unless
Orion Power meets certain conditions. As of December 31, 2002, the specified
conditions were satisfied.
Our subsidiary, which owns an electric power generation facility in
Channelview, Texas (Channelview), is party to a credit agreement used to
finance construction of its generating plant. The credit agreement contains
restrictive covenants that restrict Channelview's ability to, among other
things, make dividend distributions unless Channelview satisfies various
conditions. As of December 31, 2002, we had restricted cash of $13 million
related to Channelview. As of December 31, 2001, we had no restricted cash
related to Channelview. For further information regarding the Channelview
credit agreement, see note 9(a).
F-16
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
In December 2001, our subsidiary, Reliant Energy Power Generation Benelux,
N.V. (REPGB), a Dutch power generation company, and its former shareholders
agreed to settle the indemnity obligations of the former shareholders insofar
as they related to NEA B.V. (NEA), formerly the coordinating body for the Dutch
electricity sector. Under the settlement agreement, the former shareholders of
REPGB paid REPGB approximately $202 million in the first quarter of 2002. REPGB
deposited the settlement payment into an escrow account, withdrawals from which
are at the discretion of REPGB for use in discharging certain stranded cost
obligations. As of December 31, 2002, the remaining escrowed funds totaled $6
million, which are recorded in restricted cash.
As of December 31, 2001, we have 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. As of December 31, 2002, we had no restricted cash
related to REMA. For additional discussion regarding REMA's lease transactions,
see note 14(a).
As of December 31, 2002, we had $7 million in long-term restricted cash
pledged to secure the payment and performance when due related to the issuance
of surety bonds. In the event of default with regard to the surety bonds, the
issuer could request payment of the restricted cash from us. As of December 31,
2001, we had no restricted cash of this nature.
(m) Allowance for Doubtful Accounts.
Accounts and notes receivable, principally from customers, in the
consolidated balance sheets are net of an allowance for doubtful accounts of
$90 million and $69 million at December 31, 2001 and 2002, respectively. The
net provision for doubtful accounts in the statements of consolidated
operations for 2000, 2001 and 2002 was $43 million, $38 million and $21 million
(net of $62 million in credit reserves reversed in 2002), respectively. These
amounts exclude items written off during the years related to refunds for
energy sales in California and related to Enron Corp. and its affiliates
(Enron). For more information regarding the provisions against receivable
balances related to energy sales in the California market and to Enron, see
notes 14(i) and 17, respectively.
(n) 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 through
December 31, 2002, as discussed in note 7. However, as discussed in note 2(t),
inventory purchased after October 25, 2002 and effective January 1, 2003,
inventory used in the trading and marketing operations is no longer marked to
market in accordance with EITF No. 02-03. Below is a detail of inventory:
December 31,
------------
2001 2002
---- ----
(in millions)
Materials and supplies $ 65 $136
Coal.................. 35 59
Natural gas........... 41 78
Heating oil........... 33 46
---- ----
Total inventory.... $174 $319
==== ====
F-17
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(o) Investments.
As of December 31, 2001 and 2002, we held marketable equity securities of
$12 million and $3 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), we report "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, 2001 and 2002, we had an accumulated unrealized gain, net
of tax, relating to these securities of $6 million and $1 million, respectively.
During 2000, pursuant to SFAS No. 115, we 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
decision to recognize this impairment resulted from a combination of events
occurring in 2000 related to this investment. These events affecting the
investment included changes occurring in the investment's senior management,
announcement of significant restructuring charges and related downsizing for
the entity, reduced earnings estimates for this entity by brokerage analysts
and the bankruptcy of a competitor of the investment in the first quarter of
2000. These events, coupled with the stock market value of our investment in
these securities continuing to be below our cost basis, caused management to
believe the decline in fair value of these "available-for-sale" securities to
be other than temporary.
In addition, we held debt and equity securities classified as "trading." In
accordance with SFAS No. 115, we report "trading" securities at estimated fair
value in our consolidated balance sheets and any unrealized holding gains and
losses are recorded as gains (losses) from investments in the statements of
consolidated operations. As of December 31, 2001, we held equity securities
classified as "trading" totaling $1 million. As of December 31, 2002, we no
longer hold equity securities classified as "trading." We recorded unrealized
holding gains on "trading" securities included in gains from investments in the
statements of consolidated operations of $4 million and $5 million during 2000
and 2001, respectively. During 2002, the recorded unrealized holding gain on
"trading" securities included in losses from investments in the statements of
consolidated operations was less than $1 million.
As of December 31, 2001 and 2002, we have other investments of $68 million
and $44 million, respectively, excluding marketable securities, in which we
have ownership interests of 20% or less and do not exercise significant
influence, which are carried at cost. During 2002, we incurred a pre-tax
impairment loss of $32 million ($30 million after-tax) related to these
investments. Management's decision to recognize these impairments resulted from
a combination of events occurring in 2002 related to these investments. These
events included reduced cash flow expectations for certain of these investments
and management's decision to minimize further financial support to these
investments. These events, coupled with management's intent to sell certain
investments in the near-term below our cost basis, led us to believe the
decline in the fair value of these investments was other than temporary.
(p) Project Development Costs.
Project development costs include costs for professional services, permits
and other items that are incurred incidental to a particular project. We
expense these costs as incurred until the project is considered probable. After
a project is considered probable, subsequent capitalizable costs incurred are
capitalized to the project. When project operations begin, we begin to amortize
these costs on a straight-line basis over the life of the facility. As of
December 31, 2001 and 2002, we had recorded in the consolidated balance sheets
project development costs associated with projects under construction of $9
million and $6 million, respectively.
F-18
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(q) Environmental Costs.
We expense or capitalize environmental expenditures, as appropriate,
depending on their future economic benefit. We expense amounts that relate to
an existing condition caused by past operations and that do not have future
economic benefit. We record undiscounted liabilities related to these future
costs when environmental assessments and/or remediation activities are probable
and the costs can be reasonably estimated.
(r) Deferred Financing Costs.
Deferred financing costs are costs incurred in connection with obtaining
financings. These costs are deferred and amortized, using the straight-line
method, which approximates the effective interest method, over the life of the
related debt. As of December 31, 2001 and 2002, we had $8 million and $44
million, respectively, of net deferred financing costs capitalized in our
consolidated balance sheets.
(s) Foreign Currency Adjustments.
Local currencies are the functional currency of our 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.
(t) Changes in Accounting Principles and New Accounting Pronouncements.
SFAS No. 141. In July 2001, the Financial Accounting Standards Board (FASB)
issued SFAS No. 141 "Business Combinations" (SFAS No. 141). 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. We adopted the provisions of the 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.
SFAS No. 142. See note 6 for a discussion regarding our adoption of SFAS
No. 142 on January 1, 2002.
SFAS No. 143. 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 a change in accounting
principle in the statement of operations in the period of adoption. We are
currently evaluating the impact of SFAS No. 143 on our consolidated financial
statements and expect to record a cumulative effect of a change in accounting
principle of a net gain.
F-19
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
SFAS No. 144. 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 did not
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. We adopted SFAS No. 144 on January 1, 2002.
SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the statement of operations. Instead, such gains and
losses will be classified as extraordinary items only if they are deemed to be
unusual and infrequent. SFAS No. 145 also requires sale-leaseback accounting
for certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The changes related to debt extinguishment will be
effective for fiscal years beginning after May 15, 2002, and the changes
related to lease accounting are effective for transactions occurring after May
15, 2002. We will apply this guidance prospectively.
SFAS No. 148. In December 2002, the FASB issued SFAS No. 148. This
statement provides alternative methods of transition for a company that
voluntarily changes to the fair value method of accounting for stock-based
employee compensation. SFAS No. 148 also amends disclosure requirements of SFAS
No. 123 to require prominent disclosure in both annual and interim financial
statements about the method of accounting for stock-based employee compensation
and the effect of the method used on reported results. SFAS No. 148 is
effective for annual financial statements for fiscal years ending after
December 15, 2002 and condensed financial statements for interim periods
beginning after December 15, 2002. Currently, we are evaluating if we will
voluntarily change to the fair value method of accounting for stock-based
employee compensation in the future. We have adopted the disclosure
requirements of SFAS No. 148 for the consolidated financial statements for 2002
(see note 12(a)).
FIN No. 45. In November 2002, the FASB issued FASB Interpretation No. 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Direct Guarantees of Indebtedness of Others," (FIN No. 45) which increases the
disclosure requirements for a guarantor in its interim and annual financial
statements about its obligations under certain guarantees that it has issued.
It clarifies that a guarantor's required disclosures include the nature of the
guarantee, the maximum potential undiscounted payments that could be required,
the current carrying amount of the liability, if any, for the guarantor's
obligations (including the liability recognized under SFAS No. 5, "Accounting
for Contingencies"), and the nature of any recourse provisions or available
collateral that would enable the guarantor to recover amounts paid under the
guarantee. It also requires a guarantor to recognize, at the inception of a
guarantee issued after December 31, 2002, a liability for the fair value of the
obligation undertaken in issuing the guarantee, including its ongoing
obligation to stand ready to perform over the term of the guarantee in the
event that specified triggering events or conditions occur. We have
F-20
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
adopted the disclosure requirements of FIN No. 45 for 2002 (see note 14(g)) and
will apply the initial recognition and initial measurement provisions on a
prospective basis for all guarantees issued after December 31, 2002. The
adoption of FIN No. 45 will have no impact to our historical consolidated
financial statements, as existing guarantees are not subject to the measurement
provisions. We are currently evaluating the impact of FIN No. 45's initial
recognition and measurement provisions on our consolidated financial statements.
FIN No. 46. In January 2003, the FASB issued FASB Interpretation No. 46
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51"
(FIN No. 46). The objective of FIN No. 46 is to achieve more consistent
application of consolidation policies to variable interest entities and to
improve comparability between enterprises engaged in similar activities. FIN
No. 46 states that an enterprise must consolidate a variable interest entity if
the enterprise has a variable interest that will absorb a majority of the
entity's expected losses if they occur, receives a majority of the entity's
expected residual returns if they occur, or both. If one enterprise absorbs a
majority of a variable interest entity's expected losses and another enterprise
receives a majority of that entity's expected residual returns, the enterprise
absorbing a majority of the losses shall consolidate the variable interest
entity and will be called the primary beneficiary. FIN No. 46 is effective
immediately to variable interest entities created after January 31, 2003, and
to variable interest entities in which an enterprise obtains an interest after
that date. For enterprises that acquired variable interests prior to February
1, 2003, the effective date is for fiscal years or interim periods beginning
after June 15, 2003. FIN No. 46 requires entities to either (a) record the
effects prospectively with a cumulative effect adjustment as of the date on
which FIN No. 46 is first applied or (b) restate previously issued financial
statements for the years with a cumulative effect adjustment as of the
beginning of the first year being restated. We have elected to early adopt FIN
No. 46 and are currently evaluating the adoption impact as it relates to a
cumulative effect of a change in accounting principle on January 1, 2003.
Based on our preliminary analysis, we believe that we have variable
interests in three power generation projects that are being constructed by
off-balance sheet special purpose entities under construction agency agreements
as of December 31, 2002, which pursuant to this guidance would require
consolidation effective January 1, 2003. As of December 31, 2002, these special
purpose entities had property, plant and equipment of $1.3 billion, net other
assets of $3 million and debt obligations of $1.3 billion. As of December 31,
2002, the special purpose entities had equity from unaffiliated third parties
of $49 million. These special purpose entities' financing agreement, the
construction agency agreements and the related guarantees were terminated as
part of the refinancing in March 2003. For information regarding these special
purpose entities and the refinancing, see notes 14(b) and 21(a).
We do not expect the adoption of FIN No. 46 to have a material impact on our
results of operations or financial position, excluding the consolidation of the
entities under the construction agency agreements as discussed above.
EITF No. 02-03. In June 2002, the EITF had its initial meeting regarding
EITF No. 02-03 and reached a consensus that all mark-to-market gains and losses
on energy trading contracts should be shown net in the statement of operations
whether or not settled physically. In October 2002, the EITF issued a consensus
that superceded the June 2002 consensus. The October 2002 consensus required,
among other things, that energy derivatives held for trading purposes be shown
net in the statement of operations. This new consensus is effective for fiscal
periods beginning after December 15, 2002. However, consistent with the new
consensus and as allowed under EITF No. 98-10, beginning with the quarter ended
September 30, 2002, we now report all energy trading and marketing activities
on a net basis in the statements of consolidated operations. Comparative
financial statements for prior periods have been reclassified to conform to
this presentation.
F-21
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
The adoption of net reporting resulted in reclassifications of revenues,
fuel and cost of gas sold, purchased power expense during 2000 and 2001 as
follows:
Year Ended December 31,
-----------------------------------------------
2000 2001
----------------------- -----------------------
As As
As Previously As Previously
Reclassified Reported Reclassified Reported
------------ ---------- ------------ ----------
(in millions)
Revenues................. $3,255 $18,722 $6,122 $31,130
Trading margins.......... 200 - 369 -
------ ------- ------ -------
Total................. 3,455 18,722 6,491 31,130
Fuel and cost of gas sold 1,172 10,555 1,975 15,234
Purchased power.......... 925 6,809 2,509 13,889
Other operating expenses. 920 920 1,245 1,245
------ ------- ------ -------
Total................. 3,017 18,284 5,729 30,368
------ ------- ------ -------
Operating income......... $ 438 $ 438 $ 762 $ 762
====== ======= ====== =======
Furthermore, in October 2002, under EITF No. 02-03, the EITF reached a
consensus to rescind EITF No. 98-10. All new contracts that would have been
accounted for under EITF No. 98-10, and that do not fall within the scope of
SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
as amended (SFAS No. 133) should no longer be marked-to-market through earnings
beginning October 25, 2002. In addition, mark-to-market accounting is no longer
applied to inventories used in the trading and marketing operations. This
transition is effective for us for the first quarter of 2003. We expect to
record a cumulative effect of a change in accounting principle of approximately
$40 million loss, net of tax, effective January 1, 2003, related to EITF No.
02-03.
The EITF has not reached a consensus on whether recognition of dealer profit
or unrealized gains and losses at inception of an energy trading contract is
appropriate in the absence of quoted market prices or current market
transactions for contracts with similar terms. In the June 2002 EITF meeting
and again in the October 2002 EITF meeting, the FASB staff indicated that until
such time as a consensus is reached, the FASB staff will continue to hold the
view that previous EITF consensuses do not allow for recognition of dealer
profit, unless evidenced by quoted market prices or other current market
transactions for energy trading contracts with similar terms and
counterparties. During 2001 and 2002, we recorded $119 million and $57 million,
respectively, of fair value at the contract inception related to trading and
marketing activities. Inception gains recorded were evidenced by quoted market
prices and other current market transactions for energy trading contracts with
similar terms and counterparties.
(3) RELATED PARTY TRANSACTIONS
The consolidated financial statements include significant transactions
between CenterPoint and us. The disclosures within this note are for these
transactions for 2000, 2001 and the nine months ended September 30, 2002, up to
the date of the Distribution. Some of these transactions involve 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,
F-22
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
office support services and purchasing and logistics. The costs of services
have been directly charged or allocated to us 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 we been an
unaffiliated entity. Amounts charged and allocated to us for these services
were $34 million, $9 million and $15 million for 2000, 2001 and the nine months
ended September 30, 2002, respectively, and are included primarily in operation
and maintenance expenses and general and administrative expenses. In addition,
during 2001, we incurred costs of $27 million primarily related to corporate
support services, which were billed to CenterPoint and its affiliates. Some of
our subsidiaries have entered into office rental agreements with CenterPoint.
During 2000, 2001 and the nine months ended September 30, 2002, we incurred $4
million, $16 million and $24 million, respectively, of rent expense to
CenterPoint.
Certain of these services and the office space lease arrangements between
CenterPoint and us 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 will have a material effect on our
consolidated results of operations, cash flows or financial position. For
additional information regarding these services and office space lease
arrangements between CenterPoint and us, see note 4(a).
Below is a detail of accounts and notes receivable to affiliated companies
as of December 31, 2001 (in millions):
Net accounts receivable--affiliated companies.................... $ 27
Net short-term notes receivable--affiliated companies............ 388
Net long-term notes receivable--affiliated companies............. 30
----
Total net accounts and notes receivable--affiliated companies. $445
====
Net accounts receivable--affiliated companies, representing primarily
current month balances of transactions between us and CenterPoint or its
subsidiaries, related primarily to natural gas purchases and sales, interest,
charges for services and office space rental. Net short-term notes
receivable--affiliated companies represented the accumulation of a variety of
cash transfers and operating transactions and specific negotiated financing
transactions with CenterPoint or its subsidiaries and generally bore interest
at market-based rates. Net long-term notes receivable--affiliated companies
primarily related to a specific negotiated financing transaction with a
subsidiary of CenterPoint, see note 14(f). Net interest expense related to
these net borrowings/receivables was $172 million during 2000. Net interest
income related to these net borrowings/receivables was $12 million and $5
million during 2001 and the nine months ended September 30, 2002, respectively.
In May 2001, CenterPoint converted or contributed an aggregate of $1.7
billion of our indebtedness to CenterPoint and its subsidiaries to equity
without the issuance of any additional shares of our common stock, pursuant to
the terms of a master separation agreement between CenterPoint and us (Master
Separation Agreement), by recording an increase to our additional paid-in
capital. In addition, we used $147 million of the net proceeds of the IPO to
repay certain indebtedness owed to CenterPoint in May 2001.
During 2001 and the first half of 2002, proceeds not initially utilized from
the IPO were advanced to a subsidiary of CenterPoint (the CenterPoint money
fund) on a short-term basis. We reduced our advance to the CenterPoint money
fund following the IPO to fund capital expenditures and to meet our working
capital needs. As of December 31, 2001, we had outstanding advances to the
CenterPoint money fund of $390 million, which is included in accounts and notes
receivable in our consolidated balance sheet.
F-23
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
We purchased natural gas, natural gas transportation services, electric
generation energy and capacity, and electric transmission services from,
supplied natural gas to, and provided marketing and risk management services to
affiliates of CenterPoint. Purchases and sales related to our trading and
marketing activities are recorded net in trading margins in the statements of
consolidated operations. During 2000 and 2001, there were no material purchases
of electric generation energy and capacity and electric transmission services
from CenterPoint and its subsidiaries. Purchases of electric generation energy
and capacity and electric transmission services from CenterPoint and its
subsidiaries were $1.5 billion in the nine months ended September 30, 2002.
During 2000, 2001 and the nine months ended September 30, 2002, the net
purchases and sales and services from/to CenterPoint and its subsidiaries
related to our trading and marketing operations totaled $405 million, $469
million and $161 million, respectively. In addition, during 2000, 2001 and the
nine months ended September 30, 2002, other sales and services to CenterPoint
and its subsidiaries totaled $23 million, $56 million and $15 million,
respectively. Sales and purchases to/from CenterPoint subsequent to the
Distribution are not reported as affiliated transactions.
During 2001, REPGB received efficiency and energy payments from NEA, an
equity investment, 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.
During 2001 and 2002, we purchased entitlements to some of the generation
capacity of electric generation assets of Texas Genco, LP (Texas Genco), a
subsidiary of CenterPoint. We purchased these entitlements in capacity auctions
conducted by Texas Genco and pursuant to rights granted to us under the Master
Separation Agreement, see note 4(b). As of December 31, 2002, we had purchased
entitlements to capacity of Texas Genco averaging 5,865 MW per month in 2003.
Our anticipated capacity payments related to these capacity entitlements are
$336 million in 2003. During the first quarter of 2003, through March 20, 2003,
we purchased additional entitlements to some of the generation capacity of
electric generation assets of Texas Genco averaging 879 MW per month for 2003
with capacity payments of $84 million. For additional information regarding
agreements relating to Texas Genco, see note 4(b).
During 2000, 2001 and the nine months ended September 30, 2002, CenterPoint
made equity contributions to us of $1.4 billion, $1.8 billion and $21 million,
respectively. For the three months ended December 31, 2002, we recorded equity
contributions to us from CenterPoint of $26 million, which CenterPoint funded
in January 2003, for a total of $47 million during 2002. The contributions
received by us in 2000 primarily related to (a) conversion of $1 billion of the
borrowings from CenterPoint used to fund the acquisition of REMA (see note
5(b)), (b) the forgiveness of $284 million of debt held by subsidiaries that
were transferred from RERC Corp. to us (see note 1) and (c) general operating
costs. The contributions in 2001 primarily related to the conversion into
equity of debt owed to CenterPoint and some related interest expense totaling
$1.7 billion and the contribution of net benefit assets and liabilities, net of
deferred income taxes. The contributions in 2002 primarily related to benefit
obligations, net of deferred income taxes, pursuant to the Master Separation
Agreement.
(4) AGREEMENTS BETWEEN CENTERPOINT AND US
(a) Transition Agreements.
We entered into various written agreements with CenterPoint that were
required to facilitate an orderly separation of our businesses and operations
from those of CenterPoint in contemplation of our IPO and the Distribution. The
agreements, which are described below, address, among other things, the
provision of certain services and the leasing of facilities on an interim
basis, as well as the allocation of certain liabilities and obligations.
F-24
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
CenterPoint has agreed to provide us 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
services. Certain of these arrangements will continue until December 31, 2004;
however, we have the right to terminate categories of services at an earlier
date. The charges we pay to CenterPoint for these services allow CenterPoint to
recover its fully allocated costs of providing the services, plus out-of-pocket
costs and expenses. It is not anticipated that termination of any these
arrangements will have a material effect on our business, results of
operations, financial condition or cash flows.
We agreed to provide CenterPoint customer service call center operations,
credit and collection and revenue accounting services for CenterPoint's
electric utility division, and receiving and processing payment services for
the accounts of CenterPoint's electric utility division and two of
CenterPoint's natural gas distribution divisions. CenterPoint provided the
office space and equipment for us to perform these services. The charges
CenterPoint paid us for these services allowed us to recover our fully
allocated costs of providing the services, plus out-of-pocket costs and
expenses. As of December 31, 2001, we no longer provide these services to
CenterPoint.
We lease office space in CenterPoint's corporate headquarters and in various
other CenterPoint facilities in Houston, Texas. Our lease on our corporate
headquarters primarily expires in January 2004. We also have various agreements
with CenterPoint relating to ongoing commercial arrangements, including the
leasing of optical fiber and related maintenance activities, gas purchasing and
agency matters and subcontracting energy services under existing contracts.
We have agreements with CenterPoint providing for mutual indemnities and
releases with respect to our respective businesses and operations, corporate
governance matters, the responsibility for employee compensation and benefits,
and the allocation of tax liabilities. The agreements also require us to
indemnify CenterPoint for any untrue statement of a material fact, or omission
of a material fact necessary to make any statement not misleading, in the
registration statement or prospectus that we filed with the SEC in connection
with our IPO. We have also guaranteed, in the event CenterPoint becomes
insolvent, certain non-qualified benefits of CenterPoint's and its
subsidiaries' existing retirees at the Distribution totaling approximately $58
million.
(b) Agreements Relating to Texas Genco.
Texas Genco owns the Texas generating assets formerly held by CenterPoint's
electric utility division. Texas Genco, as the affiliated power generator of
CenterPoint, is required by law to sell at auction 15% of the output of its
installed generating capacity. These auction obligations will continue until
January 2007, unless at least 40% of the electricity consumed by residential
and small commercial customers in CenterPoint's service territory is being
served by retail electric providers other than us. Texas Genco has agreed to
auction all of its capacity that remains subsequent to the capacity auctioned
mandated under PUCT rules and after certain other adjustments. We have the
right to purchase 50% (but not less than 50%) of such remaining capacity at the
prices established in such auctions. We also have the right to participate
directly in such auctions. Texas Genco's obligation to auction its capacity and
our associated rights terminate (a) if we do not exercise our option to acquire
CenterPoint's ownership interest in Texas Genco by January 24, 2004 and (b) if
we exercise our option to acquire CenterPoint's ownership interest in Texas
Genco, on the earlier of (i) the closing of the acquisition or (ii) if the
closing has not occurred, the last day of the sixteenth month after the month
in which the option is exercised. For a discussion of our purchases of capacity
from Texas Genco in 2001 and 2002, see note 3.
In January 2003, CenterPoint distributed approximately 19% of the common
stock of Texas Genco. CenterPoint has granted us an option to purchase all of
the remaining shares of common stock of Texas Genco
F-25
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
held by CenterPoint. We may exercise the option between January 10, 2004 and
January 24, 2004. The per share exercise price under the option will be the
average daily closing price on the national exchange for publicly held shares
of common stock of Texas Genco for the 30 consecutive trading days with the
highest average closing price during the 120 trading days immediately preceding
January 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 PUCT.
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. We have agreed that if we exercise the Texas Genco option, we will
also purchase all notes and other receivables from Texas Genco then held by
CenterPoint, at their principal amount, plus accrued interest. Similarly, if
Texas Genco holds notes or receivables from CenterPoint, we will assume
CenterPoint's obligations in exchange for a payment to us by CenterPoint of an
amount equal to the principal, plus accrued interest.
We have entered into a support agreement with CenterPoint, pursuant to which
we provide engineering and technical support services and environmental, safety
and industrial health services to support operations and maintenance of Texas
Genco's facilities. We 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 we
charge for these services are designed to allow us to recover our fully
allocated direct and indirect costs and reimbursement of out-of-pocket
expenses. Expenses associated with capital investment in systems and software
that benefit both the operation of Texas Genco's facilities and our facilities
in other regions are allocated on an installed MW basis. The term of this
agreement will end on the first to occur of (a) the closing date of our
acquisition of Texas Genco under the option, (b) CenterPoint's sale of Texas
Genco, or all or substantially all of the assets of Texas Genco, if we do not
exercise the Texas Genco option, or (c) May 31, 2005 if we do not exercise the
option; however, Texas Genco may extend the term of this agreement until
December 31, 2005.
On October 1, 2002, we entered into a master power purchase contract with
Texas Genco covering, among other things, our purchases of capacity and/or
energy from Texas Genco's generating units, under an unsecured line of credit.
This contract contains covenants that restrict the activities of several of our
retail energy segment's subsidiaries. These restrictions include limitations on
the ability of these subsidiaries to (a) sell assets (including customers); (b)
consolidate or merge with other companies, including affiliated companies
outside the retail energy segment; (c) grant liens on their properties (other
than permitted liens); (d) borrow money in excess of agreed upon levels (other
than securitizations of customer accounts); (e) enter into or guarantee certain
trading arrangements; and (f) incur liabilities outside the ordinary course of
their businesses. In addition, there are restrictions involving transactions
with affiliated companies outside the retail energy segment. The primary term
of this contract ends on December 31, 2003.
(5) BUSINESS ACQUISITIONS
(a) Orion Power Holdings, Inc.
In February 2002, we acquired all of the outstanding shares of common stock
of Orion Power for an aggregate purchase price of $2.9 billion and assumed debt
obligations of $2.4 billion. We funded the Orion Power acquisition with a $2.9
billion credit facility (see note 9(a)) and $41 million of cash on hand. As a
result of the acquisition, our consolidated debt obligations also increased by
the amount of Orion Power's debt obligations. As of February 19, 2002, Orion
Power's debt obligations were $2.4 billion ($2.1 billion net of restricted cash
pursuant to debt covenants). Orion Power is an electric power generating
company with a diversified portfolio of generating assets, both geographically
across the states of New York, Pennsylvania, Ohio
F-26
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
and West Virginia, and by fuel type, including gas, oil, coal and hydro. The
primary reason for the acquisition was to enhance our then current domestic
power generation position by combining our domestic generation capacity and
Orion Power's domestic generation capacity. The Orion Power acquisition
expanded our market presence into the New York and East Central Area
Reliability Coordinating Counsel power markets. As of February 19, 2002, Orion
Power had 81 generating facilities with a total generating capacity of 5,644 MW
and two development projects with an additional 804 MW of capacity under
construction. As of December 31, 2002, both projects under construction had
reached commercial operation.
We accounted for the acquisition as a purchase with assets and liabilities
of Orion Power reflected at their estimated fair values. Our fair value
adjustments primarily included adjustments in property, plant and equipment,
contracts, severance liabilities, debt, unrecognized pension and postretirement
benefits liabilities and related deferred taxes. We finalized these fair value
adjustments in February 2003, based on final valuations of property, plant and
equipment, intangible assets and other assets and obligations. There were no
additional material modifications to the preliminary adjustments from December
31, 2002.
The net purchase price of Orion Power was allocated and the fair value
adjustments to the seller's book value were as follows:
Purchase
Price Fair Value
Allocation Adjustments
---------- -----------
(in millions)
Current assets................... $ 636 $ (8)
Property, plant and equipment.... 3,823 519
Goodwill......................... 1,324 1,220
Other intangibles................ 477 282
Other long-term assets........... 103 34
------- ------
Total assets acquired......... 6,363 2,047
------- ------
Current liabilities.............. (1,777) (51)
Current contractual obligations.. (29) (29)
Long-term contractual obligations (86) (86)
Long-term debt................... (1,006) (45)
Other long-term liabilities...... (501) (396)
------- ------
Total liabilities assumed..... (3,399) (607)
------- ------
Net assets acquired....... $ 2,964 $1,440
======= ======
Adjustments to property, plant and equipment and other intangibles,
excluding contractual rights, are based primarily on valuation reports prepared
by independent appraisers and consultants.
The following factors contributed to the recognized goodwill of $1.3
billion: commercialization value attributable to our marketing and trading
capabilities, commercialization and synergy value associated with fuel
procurement in conjunction with existing generating plants in the region, entry
into the New York power market, general and administrative cost synergies with
existing Pennsylvania-New Jersey-Maryland power market generating assets and
headquarters, and risk diversification value due to increased scale, fuel
supply mix and the nature of the acquired assets. Of the resulting goodwill,
all but $105 million is not deductible for United States income tax purposes.
The $1.3 billion of goodwill was assigned to the wholesale energy segment.
F-27
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
The components of other intangible assets and the related weighted-average
amortization period for the Orion Power acquisition consist of the following:
Purchase Weighted-Average
Price Amortization
Allocation Period (Years)
---------- ----------------
(in millions)
Air emission regulatory allowances.................. $314 38
Contractual rights.................................. 106 8
Federal Energy Regulatory Commission (FERC) licenses 57 38
----
Total............................................ $477
====
There was no allocation of purchase price to any intangible assets that are
not subject to amortization.
Our results of operations include the results of Orion Power for the period
beginning February 19, 2002. The following table presents selected financial
information and unaudited pro forma information for 2001 and 2002, as if the
acquisition had occurred on January 1, 2001 and 2002, as applicable:
Year Ended December 31,
--------------------------------------
2001 2002
----------------- --------------------
Pro Pro
Actual forma Actual forma
------ ------ ------- -------
(in millions, except per share amounts)
Revenues..................................................... $6,499 $7,655 $11,558 $11,665
Income (loss) before cumulative effect of accounting change.. 560 604 (326) (390)
Net income (loss)............................................ 563 607 (560) (624)
Basic and diluted earnings (loss) per share before cumulative
effect of accounting change................................ $ 2.02 $ 2.18 $ (1.12) $ (1.34)
Basic and diluted earnings (loss) per share.................. 2.03 2.19 (1.93) (2.15)
These unaudited pro forma results, based on assumptions we deem appropriate,
have been prepared for informational purposes only and are not necessarily
indicative of the amounts that would have resulted if the acquisition of Orion
Power had occurred on January 1, 2001 and 2002, as applicable. Purchase-related
adjustments to the results of operations include the effects on revenues, fuel
expense, depreciation and amortization, interest expense, interest income and
income taxes. Adjustments that affected revenues and fuel expense were a result
of the amortization of contractual rights and obligations relating to the
applicable power and fuel contracts that were in existence at January 1, 2001
or January 1, 2002, as applicable. Such amortization included in the pro forma
results above was based on the value of the contractual rights and obligations
at February 19, 2002. The amounts applicable to 2002 were retroactively applied
to January 1, 2002 through February 19, 2002 and the year ended December 31,
2001, to arrive at the pro forma effect on those periods. The unaudited pro
forma condensed consolidated financial statements reflect the acquisition of
Orion Power in accordance with SFAS No. 141 and SFAS No. 142. For additional
information regarding our adoption of SFAS No. 141 and SFAS No. 142, see notes
2(t) and 6.
(b) Reliant Energy Mid-Atlantic Power Holdings, LLC.
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
F-28
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
capacity of approximately 4,262 MW. With the exception of development entities
that were sold to another subsidiary in July 2000, the assets of the entities
acquired are held by REMA. The purchase price for the May 2000 transaction was
$2.1 billion. In 2002, we made an $8 million payment to the prior owner for
post-closing adjustments, which resulted in an adjustment to the purchase
price. We accounted for the acquisition as a purchase with assets and
liabilities of REMA reflected at their estimated fair values. Our 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 that 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
$7 million was recorded as goodwill and was amortized over 35 years through
December 31, 2001. See note 6 regarding the cessation of goodwill amortization.
We 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
CenterPoint. In May 2000, $1.0 billion of these loans were subsequently
converted to equity.
The net purchase price of REMA was allocated and the fair value adjustments
to the seller's book value are as follows:
Purchase
Price Fair Value
Allocation Adjustments
---------- -----------
(in millions)
Current assets................. $ 85 $ (27)
Property, plant and equipment.. 1,898 627
Goodwill....................... 7 (144)
Other intangibles.............. 196 33
Other long-term assets......... 3 (5)
------ -----
Total assets acquired....... 2,189 484
------ -----
Current liabilities............ (50) (13)
Other long-term liabilities.... (39) (15)
------ -----
Total liabilities assumed... (89) (28)
------ -----
Net assets acquired..... $2,100 $ 456
====== =====
Adjustments to property, plant and equipment, other intangibles, which
include 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, we entered into separate sale-leaseback transactions with
each of three owner-lessors covering our 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, we lease an
interest in each facility from each owner-lessor under a leveraged facility
lease agreement. As consideration for the sale of our interest in the
facilities, we received $1.0 billion in cash. We used the $1.0 billion of sale
proceeds to repay intercompany indebtedness owed by us to CenterPoint.
Our results of operations include the results of REMA for the period
beginning May 12, 2000. The following table presents selected actual financial
information and unaudited pro forma information for 2000, as if
F-29
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
the acquisition had occurred on January 1, 2000. Pro forma amounts also give
effect to the sale and leaseback of interests in three REMA generating plants
discussed above.
Year Ended
December 31, 2000
-----------------
Pro
Actual forma
------ ------
(in millions)
Revenues........................ $3,475 $3,641
Income before extraordinary item 216 207
Net income...................... 223 214
These unaudited pro forma results, based on assumptions deemed appropriate
by our 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 January 1, 2000.
Purchase-related adjustments to the results of operations include the effects
on depreciation and amortization, interest expense and income taxes.
(c) Reliant Energy Power Generation Benelux N.V.
Effective October 7, 1999, we 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 us consisted of $833
million in cash. On March 1, 2000, under the terms of the acquisition
agreement, we funded the remaining purchase obligation for $982 million. A
portion of this obligation ($596 million) was financed with a three-year term
loan facility obtained in the first quarter of 2000 (see note 9(a)). We
recorded the REPGB acquisition under the purchase method of accounting, with
assets and liabilities of REPGB reflected at their estimated fair values.
(6) GOODWILL AND INTANGIBLES
In July 2001, the FASB issued SFAS No. 142, which states that 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 their fair values. We adopted the provisions of the statement, which
apply to goodwill and intangible assets acquired prior to June 30, 2001 on
January 1, 2002, and thus discontinued amortizing goodwill into our results of
operations. A reconciliation of previously reported net income (loss) and
earnings (loss) per share to the amounts adjusted for the exclusion of goodwill
amortization follows:
Year Ended December 31,
----------------------
2000 2001 2002
---- ------ ------
(in millions, except per
share amounts)
Reported net income (loss)............................................... $223 $ 563 $ (560)
Add: Goodwill amortization, net of tax................................... 35 51 --
Less: Goodwill impairment relating to exiting communications business (1) -- (19) --
---- ------ ------
Adjusted net income (loss)............................................... $258 $ 595 $ (560)
==== ====== ======
Basic and diluted earnings (loss) per share:
Reported net income (loss)............................................... $ 2.03 $(1.93)
Add: Goodwill amortization, net of tax................................... 0.18 --
Less: Goodwill impairment relating to exiting communications business (1) (0.07) --
------ ------
Adjusted basic and diluted earnings (loss) per share..................... $ 2.14 $(1.93)
====== ======
- --------
(1) This impairment of $19 million, net of tax, is included in the annual
goodwill amortization amount, net of tax, of $51 million.
F-30
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
The components of other intangible assets consist of the following:
December 31, 2001 December 31, 2002
Weighted-Average -------------------- --------------------
Amortization Carrying Accumulated Carrying Accumulated
Period (Years) Amount Amortization Amount Amortization
---------------- -------- ------------ -------- ------------
(in millions)
Air emission regulatory allowances 36 $255 $(78) $586 $(120)
Contractual rights................ 8 -- -- 106 (26)
Power generation site permits..... 35 77 (3) 77 (6)
Water rights...................... 35 68 (4) 68 (6)
FERC licenses..................... 38 -- -- 57 (1)
Other............................. 5 -- -- 5 (3)
---- ---- ---- -----
Total.......................... $400 $(85) $899 $(162)
==== ==== ==== =====
We recognize specifically identifiable intangibles, including air emissions
regulatory allowances, contractual rights, power generation site permits, water
rights and FERC licenses, when specific rights and contracts are acquired. We
have no intangible assets with indefinite lives recorded as of December 31,
2002. We amortize air emissions regulatory allowances primarily on a
units-of-production basis as utilized. We amortize other acquired intangibles,
excluding contractual rights, on a straight-line basis over the lesser of their
contractual or estimated useful lives. All intangibles, excluding goodwill, are
subject to amortization.
In connection with the acquisition of Orion Power, we recorded the fair
value of certain fuel and power contracts acquired. We estimated the fair value
of the contracts using forward pricing curves as of the acquisition date over
the life of each contract. Those contracts with positive fair values at the
date of acquisition (contractual rights) were recorded to intangible assets and
those contracts with negative fair values at the date of acquisition
(contractual obligations) were recorded to other current and long-term
liabilities in the consolidated balance sheet.
Contractual rights and contractual obligations are amortized to fuel expense
and revenues, as applicable, based on the estimated realization of the fair
value established on the acquisition date over the contractual lives. There may
be times during the life of the contract when accumulated amortization exceeds
the carrying value of the recorded assets or liabilities due to the timing of
realizing the fair value established on the acquisition date.
Estimated amortization expense, excluding contractual rights and
obligations, for the next five years is as follows (in millions):
2003..... $ 36
2004..... 28
2005..... 28
2006..... 27
2007..... 24
----
Total. $143
====
F-31
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
We amortized $26 million and $29 million of contractual rights and
contractual obligations, respectively, for a net amount of $3 million, during
2002. Estimated amortization of contractual rights and contractual obligations
for the next five years is as follows:
Contractual Contractual Net Decrease
Rights Obligations in Income
----------- ----------- ------------
(in millions)
2003..... $ 36 $(33) $ 3
2004..... 35 (31) 4
2005..... 17 (9) 8
2006..... 13 (3) 10
2007..... 21 (1) 20
---- ---- ---
Total. $122 $(77) $45
==== ==== ===
As of December 31, 2001 and 2002, we had $32 million and $135 million,
respectively, of net goodwill recorded in our consolidated balance sheets that
is deductible for United States income tax purposes for future periods.
The following tables show the composition of goodwill by reportable segment
as of December 31, 2001 and 2002 and changes in the carrying amount of goodwill
for 2001 and 2002, by reportable segment:
Foreign
As of Currency As of
January 1, Amortization Exchange December 31,
2001 Expense Impairment Impact Other 2001
---------- ------------ ----------- -------- ----- ------------
(in millions)
Retail energy... $ 34 $ (2) $ -- $ -- $ -- $ 32
Wholesale energy 194 (4) -- -- (6) 184
European energy. 760 (26) -- (60) 1 675
Other........... 19 -- (19) -- -- --
------ ------ ----- ---- ---- ------
Total........ $1,007 $ (32) $ (19) $(60) $ (5) $ 891
====== ====== ===== ==== ==== ======
Goodwill Foreign
As of Acquired Currency As of
January 1, During the Exchange December 31,
2002 Period Impairments Impact Other 2002
---------- ------------ ----------- -------- ----- ------------
(in millions)
Retail energy... $ 32 $ -- $ -- -- $ -- $ 32
Wholesale energy 184 1,324 -- -- 1 1,509
European energy. 675 -- (716) 68 (27) --
------ ------ ----- ---- ---- ------
Total........ $ 891 $1,324 $(716) $ 68 $(26) $1,541
====== ====== ===== ==== ==== ======
During the fourth quarter of 2002, we reached an agreement with the Dutch
tax authorities on the tax basis of property, plant and equipment as of the
date of our acquisition of REPGB and accordingly we recorded a $27 million
reduction to deferred tax liability with the offset recorded to goodwill.
During the third quarter of 2002, we completed the transitional impairment
test for the adoption of SFAS No. 142 on our consolidated financial statements,
including the review of goodwill for impairment as of
F-32
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
January 1, 2002. This impairment test is performed in two steps. The initial
step is designed to identify potential goodwill impairment by comparing an
estimate of the fair value of the applicable reporting unit to its carrying
value, including goodwill. If the carrying value exceeded fair value, a second
step is performed, which compares the implied fair value of the applicable
reporting unit's goodwill with the carrying amount of that goodwill, to measure
the amount of the goodwill impairment, if any. Based on this impairment test,
we recorded an impairment of our European energy segment's goodwill of $234
million, net of tax. This impairment loss was recorded retroactively as a
cumulative effect of a change in accounting principle for the quarter ended
March 31, 2002. Based on the first step of this goodwill impairment test, no
goodwill was impaired for our other reporting units.
The circumstances leading to the goodwill impairment of our European energy
segment included a significant decline in electric margins attributable to the
deregulation of the European electricity market in 2001, lack of growth in the
wholesale energy trading markets in Northwest Europe, continued regulation of
certain European fuel markets and the reduction of proprietary trading in our
European operations. Our measurement of the fair value of the European energy
segment was based on a weighted-average approach considering both an income
approach, using future discounted cash flows, and a market approach, using
acquisition multiples, including price per MW, based on publicly available data
for recently completed European transactions.
As of March 31, 2002, we completed our assessment of intangible assets and
no indefinite lived intangible assets were identified. No related impairment
losses were recorded in the first quarter of 2002 and no changes were made to
the expected useful lives of our intangible assets as a result of this
assessment.
SFAS No. 142 also requires goodwill to be tested annually and between annual
tests if events occur or circumstances change that would more likely than not
reduce the fair value of a reporting unit below its carrying amount. We have
elected to perform our annual test for indications of goodwill impairment as of
November 1, in conjunction with our annual planning process. In estimating the
fair value of our European energy segment for the annual impairment test, we
considered the sales price in the agreement that we signed in February 2003 to
sell our European energy operations to a Netherlands-based electricity
distributor (see note 21(b)). We concluded that the sales price reflects the
best estimate of fair value of our European energy segment as of November 1,
2002, to use in our annual impairment test. Based on our annual impairment
test, we determined that an impairment of the full amount of our European
energy segment's net goodwill of $482 million should be recorded in the fourth
quarter of 2002. For additional information regarding this transaction and its
impacts, see note 21(b).
Based on our annual impairment test, no goodwill was impaired for our other
reporting units. Our impairment analyses for our other reporting units include
numerous assumptions, including but not limited to:
. increases in demand for power that will result in the tightening of
supply surpluses and additional capacity requirements over the next three
to eight years, depending on the region;
. improving prices in electric energy, ancillary services and existing
capacity markets as the power supply surplus is absorbed; and
. our expectation that more balanced, fair market rules will be
implemented, which provide for the efficient operations of unregulated
power markets, including capacity markets or mechanisms in regions where
they currently do not exist.
These assumptions are consistent with our fundamental belief that long run
market prices must reach levels sufficient to support an adequate rate of
return on the construction of new power generation.
F-33
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
An impairment analysis requires estimates of future market prices, valuation
of plant and equipment, growth, competition and many other factors as of the
determination date. The resulting impairment analysis is highly dependent on
these underlying assumptions. Such assumptions are consistent with those
utilized in our annual planning process and industry valuation and appraisal
reports. If the assumptions and estimates underlying this goodwill impairment
evaluation differ greatly from the actual results or to the extent that such
assumptions change through time, there could be additional goodwill impairments
in the future.
(7) DERIVATIVE INSTRUMENTS, INCLUDING ENERGY TRADING, MARKETING, PRICE RISK
MANAGEMENT SERVICES AND POWER ORIGINATION ACTIVITIES.
Effective January 1, 2001, we 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 accumulated other
comprehensive income (loss), net of applicable taxes, 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.
During 2001 and 2002, we did not enter into any fair value hedges.
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 $460 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by $566 million, $127 million, $811 million and $339 million,
respectively, in our consolidated balance sheet. During 2001, $249 million of
the initial after-tax transition adjustment recorded in accumulated other
comprehensive loss was recognized in net income.
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. We have utilized 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 our operating results and cash flows. We have utilized (a) cross-currency
swaps, forward contracts and options to hedge our net investments in and cash
flows of our foreign subsidiaries, (b) interest rate swaps to mitigate the
impact of changes in interest rates and (c) other financial instruments to
manage various other market risks.
Trading, marketing and hedging operations often involve risk associated with
managing energy commodities and in certain circumstances establishing open
positions in the energy markets, primarily on a short-term basis. These risks
fall into three different categories: price and volume volatility, credit risk
of trading counterparties and adequacy of the control environment for trading.
We routinely enter into energy derivatives to hedge sale commitments, fuel
requirements and inventories of natural gas, coal, electricity, crude oil and
products and other commodities to minimize the risk of market fluctuations in
our trading, marketing, power origination and risk management services
operations.
The primary types of energy derivatives we use 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.
F-34
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
. 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, Price Risk Management Services and Certain
Power Origination Activities.
Trading and marketing activities include (a) transactions establishing open
positions in the energy markets, primarily on a short-term basis, (b)
transactions intended to optimize our power generation portfolio, but which do
not qualify for hedge accounting and (c) energy price risk management services
to customers primarily related to natural gas, electric power and other
energy-related commodities. We provide these services by utilizing a variety of
derivative instruments (trading energy derivatives).
See note 2(t), which discusses the EITF's rescission of EITF No. 98-10 by
issuance of EITF No. 02-03. All new contracts entered into on or after October
25, 2002, can no longer be marked-to-market through earnings, unless the
contract is within the scope of SFAS No. 133. Note 2(t) also discusses the
estimated cumulative effect of a change in accounting principle to be recorded
effective January 1, 2003.
We applied mark-to-market accounting for our energy trading, marketing,
price risk management services to customers and certain origination activities
in our operations in North America and Europe. We also applied mark-to-market
accounting to contracted sales by our retail energy segment to large
commercial, industrial and institutional customers and the related energy
supply contracts for contracts entered into prior to October 25, 2002.
Accordingly, these contracts 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 in
the consolidated balance sheets. In addition, trading and marketing
assets/liabilities include option premiums for trading activities. Contracted
sales by our retail energy segment to large commercial, industrial and
institutional customers and the related energy supply contracts entered into
after October 25, 2002, will, for the most part, no longer be marked-to-market
through earnings. For contracted sales by our retail energy segment to large
commercial, industrial and institutional customers and the related energy
supply contracts entered into after October 25, 2002 that are derivatives
pursuant to SFAS No. 133, we will apply hedge accounting or designate them as
"normal," as further described below.
The fair values as of December 31, 2001 and 2002, are estimated by using
quoted prices where available and other valuation techniques when market data
is not available, for example in illiquid markets. Our 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 a
position.
Other factors affecting our estimates of fair values include valuation
adjustments relating to time value, the volatility of the underlying
commitment, the cost of administering future obligations under existing
contracts, and the credit risk of counterparties. Volatility valuation
adjustments are calculated by utilizing observed market price volatility and
represent the estimated impact on fair values resulting from potential
fluctuations in current prices. Credit adjustments are based on estimated
defaults by counterparties and are calculated using historical default ratings
for corporate bonds for companies with similar credit ratings.
F-35
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
The fair values 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
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). 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 fair values, is
approximately one year. The maximum term of any contract in the trading
portfolio is 15 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 our 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, we 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.
We apply hedge accounting for our 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 125% for hedge designation. If and when
correlation ceases to exist at an acceptable level, hedge accounting ceases and
prospective changes in fair value are recognized currently in our results of
operations. During 2001 and 2002, the amount of hedge ineffectiveness
recognized in revenues from derivatives that are designated and qualify as cash
flow hedges, including interest rate swaps, was a gain of $37 million and a
loss of $8 million, respectively. For 2001 and 2002, 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, we realize in net income (loss) the deferred gains and losses recognized
in accumulated other comprehensive loss. During 2001 and 2002, there were zero
and $16 million, respectively, which is excluded from the hedge ineffectiveness
above, of 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. The losses reclassified into earnings in 2002
primarily related to deferred losses of interest rate swaps. Once the
anticipated transaction occurs, the accumulated deferred gain or loss
recognized in accumulated other comprehensive loss is reclassified and included
in our statements of consolidated operations under the captions (a) fuel
expenses, in the case of natural gas purchase transactions, (b) purchased
power, in the case of electric power purchase transactions, (c) revenues, in
the case of electric power and natural gas sales transactions and financial
electric power or natural gas derivatives and (d) interest expense, in the case
of interest rate swap transactions. As of December 31, 2002, we expect $12
million of accumulated other comprehensive loss to be reclassified into net
income during the next twelve months.
F-36
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of December 31, 2001 and 2002, the maximum length of time we are hedging
our exposure to the variability in future cash flows for forecasted
transactions excluding the payment of variable interest on existing financial
instruments is 11 years and 10 years, respectively. As of December 31, 2001 and
2002, the maximum length of time we are hedging our exposure to the payment of
variable interest rates is four years and seven years, respectively.
For a discussion of our interest rate swaps, see note 9(d).
As of December 31, 2001 and 2002, our European energy segment has entered
into forward and swap contracts to purchase $271 million and $143 million,
respectively, 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. During the normal course of business, we review our currency
hedging strategies and determine the hedging approach deemed appropriate based
upon the circumstances of each situation. Until December 2002, we substantially
hedged our entire net investment in our European subsidiaries against a
material decline of the Euro through a combination of Euro-denominated
borrowings, foreign currency swaps, options and forward contracts to reduce our
exposure to changes in foreign currency rates. In December 2002, we reduced our
hedged position by approximately $1.1 billion to $1.4 billion and are using a
combination of Euro-denominated borrowings and foreign currency options to
reduce our exposure to changes in foreign currency rates. In March 2003, we
adjusted the hedge of our net investment in our European energy operations; see
note 21(b).
We record 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 our net investment in
our European subsidiaries. Euro-denominated borrowings and foreign currency
swaps and forward contracts generally offset amounts recorded in stockholders'
equity as adjustments resulting from translation of the hedged investment into
U.S. dollars while foreign currency options partially offset such amounts.
During 2001 and 2002, the derivative and non-derivative instruments designated
as hedging the net investment in our European subsidiaries resulted in a gain
of $31 million and a loss of $210 million, respectively, which are 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. 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. For additional information
regarding these stranded cost contracts and the related accounting pursuant to
SFAS No. 133, see note 14(j).
During 2001, we entered into two structured transactions, which were
recorded in the consolidated 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. The change
in fair value of these derivative assets and liabilities must be recorded in
the statement of consolidated operations for each reporting period. As of
December 31, 2001 we have recorded $118 million of net non-trading derivative
assets related to these transactions. During 2001 and 2002, $117 million of net
non-trading derivative assets and $121 million of net non-trading derivative
assets, respectively, were settled related to these transactions; $1 million
and $3 million, respectively, of pre-tax unrealized gains were recognized.
F-37
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(c) Credit Risks.
In addition to the risk associated with price movements, credit risk is
inherent in our risk management activities and hedging activities. Credit risk
relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. We have broad credit policies and parameters. It
is our policy that all transactions must be within approved counterparty or
customer credit limits. We seek to enter into contracts that permit us to net
receivables and payables with a given counterparty. We also enter into
contracts that enable us to obtain collateral from a counterparty as well as to
terminate contracts upon the occurrence of certain events of default. We
periodically review the financial condition of our counterparties. If the
counterparties to these arrangements failed to perform, we would exercise our
legal rights to obtain contractual remedies related to such non-performance. We
might be forced to acquire alternative hedging arrangements or be required to
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 the provision related to
energy sales in California, see note 14(i). For information regarding the net
provision recorded in 2001 related to energy sales to Enron, see note 17.
The following table shows the combined composition of our trading and
marketing assets and our non-trading derivative assets, after taking into
consideration netting within each contract and any master netting contracts
with counterparties, as of December 31, 2001 and 2002:
December 31, 2001 December 31, 2002
----------------- ----------------
Investment Investment
Trading and Marketing Assets and Grade Grade
Non-Trading Derivative Assets (1)(2) Total (1)(2) Total
-------------------------------- ---------- ------ ---------- -----
(in millions)
Energy marketers..................... $ 488 $ 571 $258 $ 417
Financial institutions............... 58 58 133 133
Gas and electric utilities........... 346 348 138 148
Oil and gas producers................ 95 118 12 106
Industrial........................... 32 54 16 33
Others............................... 81 127 29 44
------ ------ ---- -----
Total............................. $1,100 1,276 $586 881
====== ====
Collateral held (3).................. (167) (188)
------ -----
Total exposure, net of collateral. 1,109 693
Credit and other reserves............ (114) (68)
------ -----
$ 995 $ 625
====== =====
- --------
(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees).
(2) For unrated counterparties, we perform credit analyses, considering
contractual rights and restrictions to create an internal credit rating.
(3) Collateral consists of cash and standby letters of credit.
Trading and marketing assets and liabilities and non-trading derivative
assets and liabilities are presented separately in our consolidated balance
sheets. The trading and non-trading derivative asset and trading and
non-trading derivative liability balances were offset separately for trading
and non-trading activities although in certain cases contracts permit the
offset of trading and non-trading derivative assets and liabilities with a
given counterparty. For the purpose of disclosing credit risk, trading and
non-trading derivative assets and liabilities with a given counterparty were
offset if the counterparty has entered into a contract with us which permits
netting.
F-38
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of December 31, 2001, no individual counterparty accounted for more than
10% of our total credit exposure, net of collateral. As of December 31, 2002,
one counterparty with a credit rating below investment grade represented 12% of
our total credit exposure, net of collateral.
(d) Trading and Non-trading--General Policy.
We have established a risk oversight committee. The risk oversight
committee, which is comprised of corporate officers and includes a working
group 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 committee's duties are to approve our commodity risk
policies, allocate risk capital within limits established by our board of
directors, approve trading of new products and commodities, monitor risk
positions and monitor compliance with our risk management policies and
procedures and trading limits established by our board of directors.
Our 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.
(8) EQUITY INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES
We have a 50% interest in a 470 MW electric generation plant in Boulder
City, Nevada. The plant became operational in May 2000. We have a 50%
partnership interest in a 108 MW cogeneration plant in Orange, Texas. In
addition, we, through REPGB, have a 22.5% interest in NEA.
Currently, NEA does not have on-going operations and is in the process of
resolving its existing contingencies and liquidating its remaining assets.
Prior to 2001, 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. During 2001, NEA sold its national grid
transmission company, TenneT, to the Dutch government. As of December 31, 2001
and 2002, NEA's assets primarily consisted of proceeds held by NEA related to
the sale of TenneT. Prior to 2001, NEA's operating results were derived from
operating as the national electricity pooling and coordinating body for the
generation output of the large-scale Dutch generation companies. Beginning in
2001, NEA no longer served in this capacity. During 2001 and 2002, NEA's income
was derived from interest income from proceeds held by NEA related to the sale
of TenneT and in addition, in 2001 from the gain on the sale of TenneT. In
connection with the sale of our European energy operations (see note 21(b)),
our investment in NEA will be sold. For additional information regarding our
investment in NEA and financial impacts, see note 14(j).
Our equity investments in unconsolidated subsidiaries are as follows:
As of
December 31,
------------
2001 2002
---- ----
(in millions)
Nevada generation plant.............................. $ 57 $ 73
Texas cogeneration plant............................. 31 30
NEA.................................................. 299 210
---- ----
Equity investments in unconsolidated subsidiaries. $387 $313
==== ====
F-39
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Our income from equity investments of unconsolidated subsidiaries is as
follow:
Year Ended
December 31,
--------------
2000 2001 2002
---- ---- ----
(in millions)
Nevada generation plant.......................................... $42 $ 5 $16
Texas cogeneration plant......................................... 1 1 2
NEA.............................................................. -- 51 5
--- --- ---
Income from equity investments in unconsolidated subsidiaries. $43 $57 $23
=== === ===
During 2000, 2001 and 2002, the net distributions were $18 million, $27
million and $140 million, respectively, from these investments. The 2002 net
distributions include a $137 million distribution from NEA.
As of December 31, 2002, the companies, in which we have an unconsolidated
equity investment, carry debt that is currently estimated to be $326 million
($113 million based on our proportionate ownership interests of the
investments).
Summarized financial information for our equity method investments'
operating results is as follows:
Year Ended
December 31,
-----------------
2000 2001 2002
------ ---- ----
(in millions)
Nevada Generation Plant:
Revenues................ $ 260 $133 $101
Gross profit............ 127 22 19
Operating income (loss). 114 (5) (5)
Net income (loss)....... 108 (12) 31
Texas Cogeneration Plant:
Revenues................ $ 39 $ 45 $ 41
Gross profit............ 11 11 12
Operating income........ 3 3 4
Net income.............. 3 3 4
NEA:
Revenues................ $2,776 $ -- $ --
Gross profit............ 54 -- --
Operating income (loss). 245 81 (8)
Net income.............. 292 774 20
F-40
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Summarized financial information for our equity method investments'
financial position is as follows:
As of
December 31,
-------------
2001 2002
------ ------
(in millions)
Nevada Generation Plant:
Current assets......... $ 22 $ 53
Noncurrent assets...... 247 243
------ ------
Total.............. $ 269 $ 296
====== ======
Current liabilities.... $ 12 $ 14
Noncurrent liabilities. 145 142
Equity................. 112 140
------ ------
Total.............. $ 269 $ 296
====== ======
Texas Cogeneration Plant:
Current assets......... $ 6 $ 11
Noncurrent assets...... 63 60
------ ------
Total.............. $ 69 $ 71
====== ======
Current liabilities.... $ 6 $ 10
Noncurrent liabilities. -- --
Equity................. 63 61
------ ------
Total.............. $ 69 $ 71
====== ======
NEA:
Current assets......... $1,590 $1,201
Noncurrent assets...... 18 23
------ ------
Total.............. $1,608 $1,224
====== ======
Current liabilities.... $ 611 $ 49
Noncurrent liabilities. 195 188
Equity................. 802 987
------ ------
Total.............. $1,608 $1,224
====== ======
F-41
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(9) BANKING OR DEBT FACILITIES, OTHER SHORT-TERM DEBT AND OTHER LONG-TERM DEBT
As more fully described in note 21(a), we refinanced certain credit
facilities in March 2003.
The following table presents the components of our banking or debt
facilities, other short-term debt and other long-term debt to third parties as
of December 31, 2001 and 2002:
2001 2002
----------------------------- ---------------------------
Weighted Weighted
Average Average
Interest Interest
Rate(1) Long-term Current(2) Rate(1) Long-term Current(2)
-------- --------- ---------- -------- --------- ----------
(in millions, excluding interest rates)
Banking or Debt Facilities
Other Operations Segment:
Orion acquisition term loan..................... -- $ -- $ -- 3.68% $2,908 $ -- (3)
364-day revolver/term loan...................... -- -- -- 3.20 800 -- (3)
Three-year revolver............................. -- -- -- 3.13 208 350(3)
Wholesale Energy Segment:
Orion Power and Subsidiaries:
Orion MidWest and Orion NY term loans........ -- -- -- 3.96 1,211 109
Orion MidWest working capital facility....... -- -- -- 3.92 -- 51
Orion NY working capital facility............ -- -- -- -- -- --
Liberty Generating Project:
Floating rate debt........................ -- -- -- 3.02 -- 103
Fixed rate debt........................... -- -- -- 9.02 -- 165
Reliant Energy Channelview LP: --
Equity bridge loan........................... 2.63% -- 92 -- -- --
Term loan and working capital facility:......
Floating rate debt........................ 3.56 235 2 2.81 290 8
Fixed rate debt........................... 9.547 60 -- 9.547 75 --
REMA letter of credit facilities................ -- -- -- -- -- --
European Energy Segment:
Reliant Energy Capital (Europe), Inc.(4)........ 4.64 534 -- 4.19 -- 630(5)
REPGB 364-day revolver(4)....................... 4.18 -- 155 -- -- --
REPGB letter of credit facility................. -- -- -- -- -- --
---- ---- ------ ------
Total facilities....................... 829 249 5,492 1,416
---- ---- ------ ------
Other Short-term Debt
European Energy Segment:
Short-term arrangements via brokers and
financial institutions......................... 3.51 -- 50 -- -- --
---- ---- ------ ------
Total other short-term debt............ -- 50 -- --
---- ---- ------ ------
Other Long-term Debt
Wholesale Energy Segment:
Orion Power senior notes........................ -- -- -- 12.0 400 --
Adjustment to fair value of debt(6)............. -- -- -- -- 66 8
Other........................................... -- -- -- 6.2 1 --
Retail Energy Segment:
Other........................................... -- -- -- 5.41 3 6
European Energy Segment:
REPGB debentures(4)(7).......................... 7.35 38 22 6.65 37 1
Adjustment to fair value of debt(7)............. -- 1 -- -- -- --
Other
Adjustment to fair value of interest rate
swaps(6)....................................... -- -- -- -- 46 19
---- ---- ------ ------
Total other long-term debt............. 39 22 553 34
---- ---- ------ ------
Total debt.......................... $868 $321 $6,045 $1,450
==== ==== ====== ======
F-42
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
- --------
(1) The weighted average interest rate is for borrowings outstanding as of
December 31, 2001 or 2002, as applicable.
(2) Includes amounts due within one year of the date noted, as well as loans
outstanding under revolving and working capital facilities classified as
current liabilities.
(3) See note 21(a) for a discussion of the facilities refinanced in March 2003.
As a result of the refinancing, $3.9 billion has been classified as
long-term.
(4) Borrowings were primarily denominated in Euros and the assumed exchange
rate was 0.8895 U.S. dollar per Euro and 1.0492 U.S. dollar per Euro at
December 31, 2001 and 2002, respectively. The results of our European
energy segment are consolidated on a one-month lag basis.
(5) In March 2003, we extended the maturity of this facility. See notes 21(b)
and 21(c).
(6) Debt and interest rate swaps acquired in the Orion Power acquisition are
adjusted to fair market value as of the acquisition date. Included in
interest expense is amortization of $5 million and $25 million for
valuation adjustments for debt and interest rate swaps, respectively, for
2002. These valuation adjustments are being amortized over the respective
remaining terms of the related financial instruments.
(7) REPGB debt was adjusted to fair market value as of the acquisition date.
The fair value adjustments are being amortized over the respective
remaining term of the related long-term debt.
As of December 31, 2002, maturities of all facilities, other short-term debt
and other long-term debt were $1.4 billion in 2003, $170 million in 2004, $1.1
billion in 2005, $515 million in 2006, $3.4 billion in 2007 and $720 million in
2008 and beyond.
F-43
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(a) Banking or Debt Facilities.
The following table provides a summary of the amounts owed and amounts
available as of December 31, 2002 under our various committed credit facilities:
Commitments
Total Letters Expiring By
Committed Drawn of Unused December 31,
Credit Amount Credit Amount 2003 Expiration Date
--------- ------ ------- ------ ------------ -----------------------
(in millions)
Other Operations Segment:
Orion acquisition term loan............ $2,908 $2,908 $ -- $ -- $2,908(1) February 2003
364-day revolver/term loan............. 800 800 -- -- 800(1) August 2003
Three-year revolver.................... 800 558 235 7 -- (1) August 2004
Wholesale Energy Segment:
Orion Power and Subsidiaries:
Orion MidWest and Orion NY
term loans......................... 1,320 1,320 -- -- 109 March 2003-October 2005
Orion MidWest working capital
facility........................... 75 51 14 10 -- October 2005
Orion NY working capital
facility........................... 30 -- -- 30 -- October 2005
Liberty Generating Project.......... 290 268 17 5 8 January 2003-April 2026
Reliant Energy Channelview LP:
Term loan and working capital
facility........................... 382 373 -- 9 3 January 2003-July 2024
REMA letter of credit facilities....... 51 -- 38 13 51 August 2003
European Energy Segment:
Reliant Energy Capital (Europe), Inc... 630 630 -- -- 630(2)(3) March 2003
REPGB 364-day revolver................. 194 -- 18(4) 176 194(2) July 2003
REPGB letter of credit facility........ 420 -- 355 65 420(2) July 2003
------ ------ ---- ---- ------
Total............................ $7,900 $6,908 $677 $315 $5,123
====== ====== ==== ==== ======
- --------
(1) In March 2003, these facilities were refinanced to mature in March 2007.
See note 21(a) for further discussion.
(2) The results of our European energy segment are consolidated on a one-month
lag basis.
(3) In March 2003, we extended the maturity of this facility. See notes 21(b)
and 21(c).
(4) This amount excludes $12 million of cash collateralized letters of credit
as they do not affect our availability under the facility.
As of December 31, 2002, we had $7.9 billion in committed credit facilities
of which $315 million was unused. These facilities expired as follows (in
millions):
2003........... $5,123
2004........... 940
2005........... 1,210
2006........... 24
2007........... 61
2008 and beyond 542
F-44
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of December 31, 2002, committed credit facilities aggregating $5.2
billion were unsecured and $5.1 billion were scheduled to expire by December
31, 2003. As part of the refinancing in March 2003, the debt related to our
construction agency agreements (see note 14(b)) together with the Orion
acquisition term loan and the 364-day revolver/term loan and the three-year
revolver were combined into a single credit facility which is now secured.
As of December 31, 2002, letters of credit outstanding under these
facilities aggregated $677 million and borrowings aggregated $6.9 billion of
which $5.5 billion were classified as long-term debt, based upon the
refinancing as described in note 21(a) or the availability of committed credit
facilities coupled with management's intention to maintain these borrowings in
excess of one year.
As of December 31, 2001, we had $5.6 billion in committed credit facilities
of which $4.1 billion remained unused. 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.
Orion Acquisition Term Loan. Reliant Resources entered into an unsecured
$2.2 billion term loan facility during the fourth quarter of 2001, which was
amended in January 2002 to provide for $2.9 billion in funding to finance the
purchase of Orion Power. For discussion of the acquisition of Orion Power, see
note 5(a). Interest rates on the borrowings under this facility are based on
either (a) the London inter-bank offered rate (LIBOR) plus a margin based on
Reliant Resources' credit rating and length of time outstanding, which was 2.0%
at December 31, 2002 or (b) a base rate. This facility was funded on February
19, 2002 for $2.9 billion. The credit agreement contained affirmative and
negative covenants, including a negative pledge, and a requirement to maintain
a ratio of net debt to the sum of net debt, stockholders' equity and
subordinated affiliate debt not to exceed 0.60 to 1.00. The maturity of this
term loan was one year from the date on which it was funded. The maturity date
was extended from February 19, 2003 to March 31, 2003. During March 2003, we
refinanced this term loan facility (see note 21(a)).
364-day Revolver/Term Loan and Three-year Revolver. In 2001, Reliant
Resources entered into two unsecured syndicated revolving credit facilities
with a group of financial institutions, which provided for $800 million each or
an aggregate of $1.6 billion in committed credit. The one-year term-out
provision in the $800 million unsecured 364-day revolving credit facility was
exercised before it matured on August 22, 2002, resulting in a one-year term
loan with a maturity of August 22, 2003. The three-year revolver had a maturity
date of August 22, 2004. As of December 31, 2001 and 2002, there were $0 and
$1.4 billion in borrowings outstanding, respectively, under these facilities.
At December 31, 2001 and 2002, letters of credit outstanding under these two
facilities aggregated $51 million and $235 million, respectively. Interest
rates on the borrowings were based on (a) LIBOR plus a margin based on our
credit rating, (b) a base rate or (c) a rate determined through a bidding
process. The LIBOR margin as of December 31, 2002 was 1.375% for the 364-day
facility and 1.075% for the three-year facility. The credit agreements
contained affirmative and negative covenants, including a negative pledge, that
had to be met to borrow funds or obtain letters of credit and which required us
to maintain a ratio of net debt to the sum of net debt, stockholders' equity
and subordinated affiliate debt not to exceed 0.60 to 1.00. The revolving
credit facilities were subject to facility and usage fees that were calculated
based on the amount of the facility commitments and on the amounts outstanding
under the facilities relative to the commitments, respectively. As of the
term-out, the 364-day facility was subject to a facility fee that was based on
the amount outstanding under the facility. During March 2003, we refinanced
these facilities (see note 21(a)).
F-45
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Orion Power's Debt Obligations. As a result of our acquisition of Orion
Power in early 2002, our consolidated net debt obligations also increased by
the amount of Orion Power's net debt obligations, which are discussed below. In
October 2002, a portion of this debt was refinanced, the terms of which are
also discussed below.
Orion Power Revolving Senior Credit Facility. Orion Power had an unsecured
revolving senior credit facility. This facility was prepaid and terminated in
October 2002 in connection with the execution of the amended and restated Orion
MidWest and Orion NY credit facilities. See below for further discussion of the
debt refinancing. The amount of this facility was reduced on September 6, 2002,
from $75 million to $62 million in conjunction with a reduction of the total
letters of credit outstanding. Amounts outstanding under the facility bore
interest at a floating rate.
Orion MidWest Credit Agreement. Orion MidWest, an indirect wholly-owned
subsidiary of Orion Power, had a secured credit agreement, which included a
$988 million acquisition facility and a $75 million revolving working capital
facility, including letters of credit. This debt was refinanced in October
2002; see below for further discussion. The loans bore interest at the
borrower's option at LIBOR plus 2.00% or a base rate plus 1.00%.
Orion New York Credit Agreement. Orion NY, an indirect wholly-owned
subsidiary of Orion Power, had a secured credit agreement, which included a
$412 million acquisition facility and a $30 million revolving working capital
facility, including letters of credit. This debt was refinanced in October
2002; see below for further discussion. The loans bore interest at the
borrower's option at LIBOR plus 1.75% or a base rate plus 0.75%.
In connection with the Orion Power acquisition, the existing interest rate
swaps for the Orion MidWest credit facility and the Orion NY credit facility
were bifurcated into a debt component and a derivative component. The fair
values of the debt components, approximately $59 million for the Orion MidWest
credit facility and $31 million for the Orion NY credit facility, were based on
our incremental borrowing rates at the acquisition date for similar types of
borrowing arrangements. The value of the debt component will be reduced as
interest rate swap payments are made. For the period from February 20, 2002
through December 31, 2002, the value of the debt component was reduced by $17
million and $8 million for Orion MidWest and Orion NY, respectively. See note 7
for information regarding our derivative financial instruments. See note 9(d)
for further discussion regarding our interest-rate swaps.
Orion Power's Refinanced Debt. During October 2002, the Orion Power
revolving credit facility was prepaid and terminated and, as part of the same
transaction, we refinanced the Orion MidWest and Orion NY credit facilities,
which refinancing included an extension of the maturities by three years to
October 2005. In connection with these refinancings, we applied excess cash of
$145 million to prepay and terminate the Orion Power revolving credit facility
and to reduce the term loans and revolving working capital facilities at Orion
MidWest and Orion NY. As of the refinancing date, the amended and restated
Orion MidWest credit facility includes a term loan of approximately $974
million and a $75 million revolving working capital facility. As of the
refinancing date, the amended and restated Orion NY credit facility includes a
term loan of approximately $353 million and a $30 million revolving working
capital facility. The loans under each facility bear interest at LIBOR plus a
margin or at a base rate plus a margin. The LIBOR margin is 2.50% during the
first twelve months, 2.75% during the next six months, 3.25% for the next six
months and 3.75% thereafter. The base rate margin is 1.50% during the first
twelve months, 1.75% for the next six months, 2.25% for the next six months and
2.75% thereafter. The amended and restated Orion NY credit facility is secured
by a first lien on a substantial portion of the assets of Orion NY and its
subsidiaries (excluding certain plants) and a second lien on substantially
F-46
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
all of the assets of Orion MidWest and its subsidiary. The amended and restated
Orion MidWest credit facility is, in turn, secured by a first lien on
substantially all of the assets of Orion MidWest and its subsidiary and a
second lien on a substantial portion of the assets of Orion NY and its
subsidiaries (excluding certain plants). Both the Orion MidWest and Orion NY
credit facilities contain affirmative and negative covenants, including
negative pledges, that must be met by each borrower under its respective
facility to borrow funds or obtain letters of credit, and which require Orion
MidWest and Orion NY to maintain a combined debt service coverage ratio of 1.5
to 1.0. These covenants are not anticipated to materially restrict either
borrower's ability to borrow funds or obtain letters of credit under its
respective credit facility. The facilities also provide for any available cash
under one facility to be made available to the other borrower to meet
shortfalls in the other borrower's ability to make certain payments, including
operating costs. This is effected through distributions of such available cash
to Orion Power Capital, LLC, a direct subsidiary of Orion Power formed in
connection with the refinancing. Orion Power Capital, LLC, as indirect owner of
each of Orion MidWest and Orion NY, can then contribute such cash to the other
borrower. Although cash sufficient to make the November and December 2002
payments on Orion Power's 12% senior notes and 4.5% convertible senior notes
(each described below) was provided in connection with the refinancing, the
ability of the borrowers to make subsequent dividends to Orion Power for such
interest payments or otherwise is subject to certain requirements (described
below) that are likely to restrict such dividends.
As of December 31, 2002, Orion MidWest had $969 million and $51 million of
term loans and revolving working capital facility loans outstanding,
respectively. A total of $14 million in letters of credit were also outstanding
under the Orion MidWest credit facility. As of December 31, 2002, Orion NY had
$351 million of term loans outstanding. There were no loans or letters of
credit outstanding under the Orion NY working capital facility. As of December
31, 2002, restricted cash under the Orion MidWest and the Orion NY credit
facilities was $72 million and $73 million, respectively, and $27 million at
Orion Capital. Such restricted cash may be dividended to Orion Power if Orion
MidWest and Orion NY have made certain prepayments and a number of distribution
tests have been met, including satisfaction of certain debt service coverage
ratios and the absence of events of default. It is likely that these tests will
restrict a dividend of such restricted cash to Orion Power. Any restricted cash
which is not dividended will be applied on a quarterly basis to prepay on a pro
rata basis outstanding loans at Orion MidWest and Orion NY. No distributions
may be made under any circumstances after October 28, 2004. Orion MidWest's and
Orion NY's obligations under the respective facilities are non-recourse to
Reliant Resources.
Liberty Credit Agreement. In July 2000, Liberty Electric Power, LLC (LEP)
and Liberty Electric PA, LLC (Liberty), indirect wholly-owned subsidiaries of
Orion Power, entered into a facility that provides for (a) a construction/term
loan in an amount of up to $105 million; (b) an institutional term loan in an
amount of up to $165 million; (c) a revolving working capital facility for an
amount of up to $5 million; and (d) a debt service reserve letter of credit
facility of $17 million. The outstanding borrowings related to the Liberty
credit agreement are non-recourse to Reliant Resources.
In May 2002, the construction loans were converted to term loans. As of the
conversion date, the term loans had an outstanding principal balance of $270
million, with $105 million having a final maturity in 2012 and the balance
having maturities through 2026. On the conversion date, Orion Power made the
required cash equity contribution of $30 million into Liberty, which was used
to repay a like amount of equity bridge loans advanced by the lenders. A
related $41 million letter of credit furnished by Orion Power as credit support
was returned for cancellation. In addition, on the conversion date, a $17
million letter of credit was issued in satisfaction of Liberty's obligation to
provide a debt service reserve. The facility also provides for a $5 million
working capital line of credit. The debt service reserve letter of credit
facility and the working capital facility expire in May 2007.
F-47
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of December 31, 2002, amounts outstanding under the Liberty credit
agreement bear interest at a floating rate, which may be either LIBOR plus
1.25% or a base rate plus 0.25%, except for the institutional term loan which
bears interest at a fixed rate of 9.02%. For the floating rate term loan, the
LIBOR margin is 1.25% during the first 36 months from the conversion date,
1.375% during the next 36 months and 1.625% thereafter. The base rate margin is
0.25% during the first 36 months from the conversion date, 0.375% during the
next 36 months and 0.625% thereafter. The LIBOR margin for the revolving
working capital facility is 1.25% during the first 36 months from the
conversion date and 1.375% thereafter. The base rate margin is 0.25% during the
first 36 months from the conversion date and 0.375% thereafter. As of December
31, 2002, Liberty had $103 million and $165 million of the floating rate and
fixed rate portions of the facility outstanding, respectively. A $17 million
letter of credit was also outstanding under the Liberty credit agreement.
The lenders under the Liberty credit agreement have a security interest in
substantially all of the assets of Liberty. The Liberty credit agreement
contains affirmative and negative covenants, including a negative pledge, that
must be met to borrow funds or obtain letters of credit. Liberty is currently
unable to access the working capital facility (see note 14(l)). Additionally,
the Liberty credit agreement restricts Liberty's ability to, among other
things, make dividend distributions unless Liberty satisfies various
conditions. As of December 31, 2002, restricted cash under the Liberty credit
agreement totaled $27 million.
For additional information regarding the Liberty credit agreement related
issues and concerns, see note 14(l). Given that we believe that it is probable
that a default will occur and thus make the obligation callable before December
31, 2003, we have classified the debt as a current liability.
Reliant Energy Channelview L.P. In 1999, a special purpose project
subsidiary of Reliant Energy Power Generation, Inc. (REPG), Reliant Energy
Channelview L.P., 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 was (a) $92 million in equity bridge loans for the purpose of
paying or reimbursing project costs, (b) $369 million in loans to finance the
construction of the project and (c) $14 million in revolving loans for general
working capital purposes.
As of December 31, 2001, the project subsidiary had drawn $389 million in
equity bridge and construction loans. In November 2002, the construction loans
were converted to term loans. On the conversion date, subsidiaries of REPG
contributed cash equity and subordinated debt of $92 million into Channelview,
which was used to repay a like amount of equity bridge loans advanced by the
lenders. As of December 31, 2002, Channelview had $368 million and $5 million
of term loans and revolving working capital facility loans outstanding,
respectively. The outstanding borrowings related to the Channelview credit
agreement are non-recourse to Reliant Resources. The term loans have final
maturities ranging from 2017 to 2024. The revolving working capital facility
matures in 2007.
As of December 31, 2002, with the exception of two tranches which total $91
million, the term loans and revolving working capital facility loans bear a
floating rate interest at the borrower's option of either (a) a base rate of
prime plus a margin of 0.25% or (b) LIBOR plus a margin of 1.25%. For $252
million of the term loans and the working capital facility loans, the LIBOR
margin is 1.25% during the first 60 months from the conversion date, 1.45%
during the next 48 months, 1.75% during the following 48 months and 2.125%
thereafter. The base rate margin is 0.25% during the first 60 months from the
conversion date, 0.45% during the next 48 months, 0.75% during the following 48
months and 1.125% thereafter. For $30 million of the term loans, the LIBOR
margin is 1.25% during the first 60 months from the conversion date, 1.45%
during the next 48 months, 1.875% during the following 48 months and 2.25%
thereafter. The base rate margin is 0.25% during the first 60
F-48
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
months from the conversion date, 0.45% during the next 48 months, 0.875% during
the following 48 months and 1.25% thereafter. One tranche of $16 million bears
a floating rate interest at the borrower's option of either (a) a base rate
plus a margin of 2.407% or (b) LIBOR plus a margin of 3.407% throughout its
term. A second tranche of $75 million bears interest at a fixed rate of 9.547%
throughout its term.
Obligations under the term loans and revolving working capital facility are
secured by substantially all of the assets of the borrower. The Channelview
credit agreement contains affirmative and negative covenants, including a
negative pledge, that must be met to borrow funds. These covenants are not
anticipated to materially restrict Channelview's ability to borrow funds under
the credit facility. Additionally, the Channelview credit agreement allows
Channelview 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. As of December 31, 2002,
restricted cash under the credit agreement totaled $13 million.
REMA Letter of Credit Facilities. REMA's lease obligations are currently
supported by three letters of credit issued under three separate unsecured
letter of credit facilities. See note 14(a) for a discussion of REMA's lease
obligations. The letter of credit facilities expire in August 2003. The amount
of each letter of credit is equal to an amount representing the greater of (a)
the next six months' scheduled rental payments under the related lease, or (b)
50% of the scheduled rental payments due in the next twelve months under the
related lease. Under the letter of credit facilities, REMA pays a fee based on
its assigned credit rating. As of December 31, 2002, the fee equaled 2.75% of
the total amount of the outstanding letters of credit. As of December 31, 2001
and 2002, there were $73 and $38 million, respectively, in letters of credit
outstanding under the facilities. While borrowings under the letter of credit
facilities are non-recourse to Reliant Resources, the guarantee issued by
REMA's subsidiaries relating to the lease obligations also covers REMA's
obligations under these facilities. REMA anticipates refinancing or replacing
the letter of credit facilities prior to their maturity. REMA anticipates that
the terms may be more restrictive and may include higher fees.
Reliant Energy Capital (Europe), Inc. In February 2000, one of our
subsidiaries, Reliant Energy Capital (Europe), Inc., established a Euro 600
million term loan facility ($630 million assuming the December 31, 2002
exchange rate of 1.0492 U.S. dollar per Euro) that was to terminate in March
2003. The facility bears interest at the inter-bank offered rate for Euros
(EURIBOR) plus 1.25%. At December 31, 2001 and 2002, $534 million and $630
million, respectively, under this facility was outstanding. This facility is
secured by a pledge of the shares of REPGB's indirect holding company.
Borrowings under this facility are non-recourse to Reliant Resources. This
facility contains affirmative and negative covenants, including a negative
pledge, and a requirement for Reliant Energy Capital (Europe), Inc. 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. In March 2003, we extended
the maturity of this facility (see notes 21(b) and 21(c)).
REPGB 364-day Revolver and REPGB Letter of Credit Facility. In July 2000,
REPGB entered into two unsecured credit facilities, which included (a) a
364-day revolving credit facility for Euro 250 million, which was initially
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 14(d)). Under the two facilities, there is no recourse
to Reliant Resources.
During July 2002, REPGB renewed its 364-day revolving credit facility for
another year. The term of this facility is now scheduled to expire in July
2003. The amount of the revolving credit facility was reduced from Euro 250
million (approximately $262 million) to Euro 184 million (approximately $194
million). An option was added that permits REPGB to utilize up to Euro 100
million (approximately $105 million) of the facility for
F-49
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
letters of credit. The 364-day revolving credit facility bears interest at
EURIBOR plus a margin depending on REPGB's credit rating. The EURIBOR margin as
of December 31, 2002 was 2.00%. At December 31, 2001 and 2002, borrowings of
$155 million and $0, respectively, were outstanding under this facility. At
December 31, 2001 and 2002, there were $0 and $18 million, respectively, of
letters of credit outstanding under the 364-day revolving credit facility. At
December 31, 2001 and 2002, under the $420 million letter of credit facility,
letters of credit of $272 million and $355 million, respectively, were
outstanding under the facility. These facilities contain affirmative and
negative covenants, including a negative pledge, that must be met by REPGB to
borrow funds or obtain letters of credit and 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 REPGB from borrowing funds or obtaining
letters of credit, as applicable, under these facilities. If the sale of our
European energy operations (see note 21(b)) does not close prior to the
maturity of these facilities, REPGB anticipates extending these credit
facilities.
(b) Other Short-term Debt.
As of December 31, 2001, we, through REPGB, had $50 million 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.
(c) Other Long-term Debt.
Orion Convertible Senior Notes. As of the acquisition date, Orion Power had
outstanding $200 million of aggregate principal amount of 4.5% convertible
senior notes, due on June 1, 2008. Pursuant to certain change of control
provisions, Orion Power commenced an offer to repurchase the convertible senior
notes on March 1, 2002, which expired on April 10, 2002. During the second
quarter of 2002, we repurchased $189 million in principal amount under the
offer to repurchase. During the fourth quarter of 2002, the remaining $11
million aggregate principal amount of the convertible senior notes were
repurchased for $8 million.
Orion Power Senior Notes. Orion Power has outstanding $400 million
aggregate principal amount of 12% senior notes due 2010. The senior notes are
senior unsecured obligations of Orion Power. Orion Power is not required to
make any mandatory redemption or sinking fund payments with respect to the
senior notes. The senior notes are not guaranteed by any of Orion Power's
subsidiaries and are non-recourse to Reliant Resources. In connection with the
Orion Power acquisition, we recorded the senior notes at an estimated fair
value of $479 million. The $79 million premium is amortized against interest
expense over the life of the senior notes. For the period February 20, 2002 to
December 31, 2002, $5 million was amortized to interest expense for the senior
notes. The fair value of the senior notes was based on our incremental
borrowing rates for similar types of borrowing arrangements as of the
acquisition date. The senior notes indenture contains covenants that include,
among others, restrictions on the payment of dividends by Orion Power.
Pursuant to certain change of control provisions, Orion Power commenced an
offer to repurchase the senior notes on March 21, 2002. The offer to repurchase
expired on April 18, 2002. There were no acceptances of the offer to repurchase
and the entire $400 million aggregate principal amount remains outstanding.
Before May 1, 2003, Orion Power may redeem up to 35% of the senior notes issued
under the indenture at a redemption price of 112% of the principal amount of
the notes redeemed, plus accrued and unpaid interest and special interest, with
the net cash proceeds of an equity offering provided that certain provisions
under the indenture are met.
European Energy. Outstanding long-term indebtedness of REPGB of $61 million
and $38 million at December 31, 2001 and 2002, respectively, consisted
primarily of medium term notes and loans maturing
F-50
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
through 2006. This debt is unsecured and non-recourse to Reliant Resources.
Some covenants under these loans restrict some actions by REPGB. 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.
(d) Interest-rate Swaps.
Certain of our subsidiaries are party to interest rate swap contracts with
an aggregate notional amount of $200 million and $1.1 billion as of December
31, 2001 and 2002, respectively, that fix the interest rate applicable to
floating rate long-term debt. As of December 31, 2002, floating rate
LIBOR-based interest payments are exchanged for weighted fixed rate interest
payments of 6.97%. These swaps qualify for hedge accounting as cash flow hedges
under SFAS No. 133 and the periodic settlements are recognized as an adjustment
to interest expense in the statements of consolidated operations over the term
of the swap agreements. See note 7 for further discussion of our cash flow
hedges.
In January 2002, we entered into forward-starting interest rate swaps having
an aggregate notional amount of $1.0 billion to hedge the interest rate on a
portion of future offerings of long-term fixed-rate notes. On May 9, 2002, we
liquidated $500 million of these forward-starting interest rate swaps. The
liquidation of these swaps resulted in a loss of $3 million, which was recorded
in accumulated other comprehensive loss and will be amortized into interest
expense in the same period during which the forecasted interest payment affects
earnings. In November 2002, we liquidated the remaining $500 million of swaps
at a loss of $52 million that was recorded in accumulated other comprehensive
loss and will be amortized into interest expense in the same period during
which the forecasted interest payment affects earnings. For 2002, we recognized
$16 million as interest expense relating to the reclassification of the
deferred components in accumulated other comprehensive loss for forecasted
interest payments that were probable of not occurring. Should other forecasted
interest payments become probable of not occurring, any applicable deferred
amounts will be recognized immediately as an expense. At December 31, 2002, the
unamortized balance of such loss was $39 million.
(10) 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, we used $147 million of the net proceeds to repay certain
indebtedness owed to CenterPoint. We used the remainder of the net proceeds of
our IPO for repayment of third party borrowings, capital expenditures,
repurchases of our common stock and payment of taxes, interest and other
payables.
(b) Treasury Stock Purchases.
In July 2001, our board of directors authorized us to purchase up to one
million shares of our common stock in anticipation of funding benefit plan
obligations expected to be funded prior to the Distribution. On September 18,
2001, our board of directors authorized us to purchase up to 10 million
additional shares of our common stock through February 2003. During 2001, we
purchased 11 million shares of our common stock at an average price of $17.22
per share, or an aggregate purchase price of $189 million. The 11 million
shares in
F-51
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
treasury stock purchases increased CenterPoint's percentage ownership in us
from approximately 80% to approximately 83%. CenterPoint recorded the
acquisition of treasury shares under the purchase method of accounting and
pushed down the effect to us. As such, we recorded a decrease in property,
plant and equipment of $67 million and an increase in accumulated deferred
income tax assets of $24 million related to REPGB and a decrease in additional
paid-in capital of $43 million.
On December 6, 2001, our board of directors authorized us to purchase up to
an additional 10 million shares of our common stock through June 2003. Any
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
authorization, we have not purchased any shares of our common stock under this
program. Based on the refinancing of certain credit facilities in March 2003,
we are restricted from purchasing treasury stock, see note 21(a).
(c) Treasury Stock Issuances and Transfers.
We did not issue or transfer any treasury stock during 2001. During 2002, we
issued 1,326,843 shares of treasury stock to employees under our employee stock
purchase plan. In addition, during 2002, we transferred 308,936 shares of
treasury stock to our employee savings plan and issued 165,455 shares of
treasury stock to fund a portion of our restricted stock awards. See note 12(a)
for further discussion.
(11) EARNINGS PER SHARE
The following table presents Reliant Resources' basic and diluted earnings
(loss) per share (EPS) calculation for 2001 and 2002. There were no dilutive
reconciling items to net income (loss).
Year Ended
December 31,
--------------------
2001 2002
-------- --------
(shares in thousands)
Diluted Weighted Average Shares Calculation:
Weighted average shares outstanding............................ 277,144 289,953
Plus: Incremental shares from assumed conversions:
Stock options........................................... 2 --
Restricted stock........................................ 244 --
Employee stock purchase plan............................ 83 --
-------- --------
Weighted average shares assuming dilution................... 277,473 289,953
======== ========
Basic and Diluted EPS:
Income (loss) before cumulative effect of accounting change. $ 2.02 $ (1.12)
Cumulative effect of accounting change, net of tax.......... 0.01 (0.81)
-------- --------
Net income (loss)........................................... $ 2.03 $ (1.93)
======== ========
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.
For 2002, as we incurred a loss from continuing operations, we do not assume
any potentially dilutive shares in the computation of diluted EPS. The
computation of diluted EPS excludes incremental shares from assumed
F-52
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
conversions for stock options of 273,921 shares, restricted stock of 1,120,865
shares, and employee stock purchase plan rights of 132,580 shares for 2002.
These incremental shares from assumed conversions exclude purchase options for
15,875,183 shares of common stock that have an exercise price (ranging from
$8.50 to $34.03) greater than the per share average market price ($8.15) 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 affect a
240,000 to 1 stock split of our common stock on January 5, 2001.
(12) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS
(a) Stock-Based Incentive Compensation Plans.
At December 31, 2002, our eligible employees participate in four incentive
plans described below.
The Long-Term Incentive Plan of Reliant Resources, Inc. (2001 LTIP) and
Reliant Resources, Inc. 2002 Long-Term Incentive Plan (2002 LTIP) permit us to
grant awards (stock options, restricted stock, stock appreciation rights,
performance awards and cash awards) to all of our employees, non-employee
directors and other eligible individuals. Subject to adjustment as provided in
each plan, the aggregate number of shares of our common stock that may be
issued under each plan may not exceed 16,000,000 shares and 17,500,000 shares,
respectively. Upon the adoption of the 2002 LTIP plan, the shares remaining
available for grant under the 2001 LTIP, totaling approximately 3.5 million,
were effectively cancelled and considered in determining the authorized shares
available for grant under the 2002 LTIP.
The Reliant Resources, Inc. 2002 Stock Plan (2002 Stock Plan) permits us to
grant awards (stock options, restricted stock, stock appreciation rights,
performance awards and cash awards) to all of our employees (excluding
officers). The shares available for grant are based on the 6,000,000 shares
authorized upon adoption of the 2002 Stock Plan plus an additional number of
shares to be added to the plan on January 1/st/ of each year, adjusted for new
grants, exercises, forfeitures, cancellations and terminations of outstanding
awards under the plan throughout the year.
Prior to the IPO, eligible employees participated in a CenterPoint Long-Term
Incentive Compensation Plan and other incentive compensation plans
(collectively, the CenterPoint Plans) that provided for the issuance of
stock-based incentives including performance-based shares, restricted shares,
stock options and stock appreciation rights, to key employees including
officers. The Reliant Resources, Inc. Transition Stock Plan (Transition Plan)
was adopted to govern the outstanding restricted shares and options of
CenterPoint common stock held by our employees prior to the Distribution date,
under the CenterPoint Plans. There were 9,100,000 shares authorized under the
Transition Plan and as of December 31, 2002, no additional shares will be
issued.
In addition, in conjunction with the Distribution, we entered into an
employee matters agreement with CenterPoint. This agreement covered the
treatment of outstanding CenterPoint equity awards (including performance-based
shares, restricted shares and stock options) under the CenterPoint Plans held
by our employees and CenterPoint employees. According to the agreement, each
CenterPoint equity award granted to our employees and CenterPoint employees
prior to the agreed upon date of May 4, 2001, that was outstanding
F-53
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
under the CenterPoint Plans as of the Distribution date, was adjusted. This
adjustment resulted in each individual, who was a holder of a CenterPoint
equity award, receiving an adjusted equity award of our common stock and
CenterPoint common stock, immediately after the Distribution. The combined
intrinsic value of the adjusted CenterPoint equity awards and our equity
awards, immediately after the record date of the Distribution, was equal to the
intrinsic value of the CenterPoint equity awards immediately before the record
date of the Distribution.
Performance-based Shares and Restricted Shares. Performance-based shares
and restricted shares have been granted to employees without cost to the
participants. 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 five-year
period. During 2000, 2001 and 2002, we recorded compensation expense of $6.7
million, $8.2 million and $3.6 million, respectively, related to
performance-based and restricted share grants.
Prior to the Distribution, our employees and CenterPoint employees held
outstanding performance-based shares and restricted shares of CenterPoint's
common stock under the CenterPoint Plans. On the Distribution date, each
performance-based share of CenterPoint common stock outstanding under the
CenterPoint Plans, for the performance cycle ending December 31, 2002, was
converted to restricted shares of CenterPoint's common stock based on a
conversion ratio provided under the employee matters agreement. Immediately
following this conversion, outstanding restricted shares of CenterPoint common
stock were converted to restricted shares of our common stock, which shares
were subject to their original vesting schedule under the CenterPoint Plans.
The conversion ratio was determined using the intrinsic value approach
described above. As such, our employees and CenterPoint's employees held
302,306 and 87,875 restricted shares, respectively, outstanding under
CenterPoint Plans which were converted to 238,457 and 69,334 restricted shares,
respectively, of our common stock, of which a majority vested on December 31,
2002.
The following table summarizes Reliant Resources' performance-based shares
and restricted shares grant activity for 2001 and 2002:
Performance-based Restricted
Shares Shares
----------------- ----------
Outstanding at December 31, 2000....................................... -- --
Granted............................................................. 693,135 156,674
---------- ---------
Outstanding at December 31, 2001.................................... 693,135 156,674
---------- ---------
Granted............................................................. 754,182 671,803
Shares relating to conversion of CenterPoint's restricted shares at
Distribution...................................................... -- 307,791
Released to participants............................................ -- (253,071)
Canceled............................................................ (361,785) (127,930)
---------- ---------
Outstanding at December 31, 2002....................................... 1,085,532 755,267
---------- ---------
Weighted average grant date fair value of shares granted for 2001...... $ 30.00 $ 33.11
========== =========
Weighted average grant date fair value of shares granted for 2002...... $ 10.59 $ 9.26
========== =========
Stock Options. Under both CenterPoint's and our plans, stock options
generally vest over a three-year period and expire after ten years from the
date of grant. The exercise price is based on the fair market value of the
applicable common stock on the grant date.
F-54
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of the record date of the Distribution, CenterPoint converted all
outstanding CenterPoint stock options granted prior to May 4, 2001 (totaling
7,761,960 stock options) to a combination of CenterPoint stock options totaling
7,761,960 stock options at a weighted average exercise price of $17.84 and
Reliant Resources stock options totaling 6,121,105 stock options with a
weighted-average exercise price of $8.59. The conversion ratio was determined
using an intrinsic value approach as described above.
The following table summarizes Reliant Resources stock option activity for
2001 and 2002:
Weighted
Average
Exercise
Options Price
---------- --------
Outstanding at December 31, 2000................................................. -- --
Granted....................................................................... 8,826,432 $29.82
Canceled...................................................................... (245,830) 28.28
----------
Outstanding at December 31, 2001................................................. 8,580,602 29.86
----------
Granted....................................................................... 7,141,267 10.57
Options relating to conversion of CenterPoint's stock options at Distribution. 6,121,105 8.59
Canceled...................................................................... (2,674,238) 22.25
----------
Outstanding at December 31, 2002................................................. 19,168,736 16.99
----------
Options exercisable at December 31, 2001......................................... 6,500 30.00
==========
Options exercisable at December 31, 2002......................................... 8,232,294 16.16
==========
The following table summarizes, with respect to Reliant Resources, the range
of exercise prices and the weighted-average remaining contractual life of the
options outstanding and the range of exercise prices for the options
exercisable at December 31, 2002:
Options Outstanding Options Exercisable
---------------------------------- ---------------------
Weighted-
Weighted- Average Weighted-
Average Remaining Average
Options Exercise Contractual Options Exercise
Outstanding Price Life (Years) Outstanding Price
----------- --------- ------------ ----------- ---------
Ranges of Exercise Prices Exercisable at:
$ 1.83-$10.00......................... 5,607,360 $ 7.84 6.1 4,276,541 $ 8.26
$10.01-$20.00......................... 6,636,731 11.19 8.3 1,136,293 11.66
$20.01-$34.03......................... 6,924,645 29.95 7.5 2,819,460 29.95
---------- ---------
Total............................. 19,168,736 16.99 7.4 8,232,294 16.16
========== =========
Of the outstanding and exercisable stock options as of December 31, 2002,
17,438,954 and 6,931,212, respectively, relate to our employees. The remainder
of outstanding and exercisable stock options as of December 31, 2002, primarily
relate to employees of CenterPoint.
F-55
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Exercise prices for CenterPoint stock options outstanding and held by our
employees ranged from $12.87 to $36.25. The following table provides
information with respect to outstanding and exercisable CenterPoint stock
options held by our employees at December 31, 2001 and 2002:
December 31, 2001 December 31, 2002
------------------- -------------------
Weighted- Weighted-
Average Average
Exercise Exercise
Options Price Options Price
--------- --------- --------- ---------
Outstanding 5,886,119 $24.81 5,449,021 $18.05
--------- ---------
Exercisable 2,683,755 25.62 4,535,211 18.28
--------- ---------
Employee Stock Purchase Plan. In the second quarter 2001, we established
the Reliant Resources, Inc. Employee Stock Purchase Plan (ESPP) under which we
are authorized to sell up to 3,000,000 shares of our common stock to our
employees. Under the ESPP, employees may contribute up to 15% of their
compensation, as defined, towards the purchase of shares of our common stock at
a price of 85% of the lower of the market value at the beginning of the
offering period or end of each six-month offering period. The initial purchase
period began on the date of the IPO and ended December 31, 2001. The market
value of the shares acquired in any year may not exceed $25,000 per individual.
Under the ESPP, 550,781 shares, 776,062 shares and 717,931 shares of our common
stock were sold to employees at a price of $14.07, $7.44 and $2.66 per share
related to the January 2002, July 2002 and January 2003 purchase, respectively.
Pro Forma Effect on Net Income (Loss). In accordance with SFAS No. 123, we
apply the intrinsic value method contained in APB No. 25 and disclose the
required pro forma effect on net income (loss) and earnings (loss) per share as
if the fair value method of accounting for stock compensation was used. The
weighted average grant date fair value for an option to purchase our common
stock granted during 2001 and 2002 was $13.35 and $5.09, respectively. The
weighted average grant date fair value of a purchase right issued under our
ESPP during 2001 and 2002 was $9.24 and $4.51, respectively. The weighted
average grant date fair value for an option to purchase CenterPoint common
stock granted during 2000 and 2001 was $5.07 and $9.25, respectively. The fair
values were estimated using the Black-Scholes option valuation model with the
following weighted-average assumptions:
Reliant Resources
Stock Options
----------------
2001 2002
--------- -----
Expected life in years........ 5 5
Risk-free interest rate....... 4.94% 4.43%
Estimated volatility.......... 42.65% 46.99%
Expected common stock dividend 0% 0%
Reliant Resources
Purchase Rights
under ESPP
----------------
2001 2002
----- --------
Expected life in months....... 8 6
Risk-free interest rate....... 3.92% 1.89%
Estimated volatility.......... 46.48% 71.32%
Expected common stock dividend 0% 0%
F-56
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
CenterPoint
Stock Options
-------------
2000 2001
----- ----
Expected life in years.......................... 5 5
Risk-free interest rate......................... 6.57% 4.87%
Estimated volatility of CenterPoint common stock 24.00% 31.91%
Expected common stock dividend.................. 3.46% 5.75%
The Black-Scholes option valuation model was developed for use in estimating
the fair value of traded options, which have no vesting restrictions and are
fully transferable. In addition, option valuation models require the input of
highly subjective assumptions including the expected stock price volatility.
Because our employee stock options and purchase rights have characteristics
significantly different from those of traded options, and because changes in
the subjective input assumptions can materially affect the fair value estimate,
in our opinion, the existing models do not necessarily provide a reliable
single measure of the fair value of our employee stock options and purchase
rights.
For the pro forma computation of net income (loss) and earnings (loss) per
share as if the fair value method of accounting had been applied to all stock
awards, see note 2(h).
(b) Pension.
We sponsor multiple noncontributory defined benefit pension plans covering
certain union and non-union employees. Depending on the plan, the benefit
payment is either based on years of service with final average salary and
covered compensation, or in the form of a cash balance account which grows
based on a percentage of annual compensation and accrued interest.
Prior to March 1, 2001, we participated in CenterPoint's noncontributory
cash balance pension plan. Effective March 1, 2001, we no longer accrued
benefits under this noncontributory pension plan for our domestic non-union
employees (Resources Participants). Effective March 1, 2001, each Resources
Participant's unvested pension account balance became fully vested and a
one-time benefit enhancement was provided to some qualifying participants.
During the first quarter of 2001, we incurred a charge to earnings of $83
million (pre-tax) for a one-time benefit enhancement and a gain of $23 million
(pre-tax) related to the curtailment of CenterPoint's pension plan. In
connection with the Distribution, we incurred a loss of $65 million (pre-tax)
related to the accounting settlement of the pension obligation. In connection
with recording the accounting settlement, CenterPoint contributed certain
benefit plan deferred losses, net of taxes, totaling $18 million that were
deemed to be associated with our benefit obligation. Upon the Distribution, we
effectively transferred to CenterPoint our pension obligation. After the
Distribution, each Resources Participant may elect to have his accrued benefit
(a) left in the CenterPoint pension plan for which CenterPoint is the plan
sponsor, (b) rolled over to our savings plan or an individual retirement
account, or (c) paid in a lump-sum or annuity distribution.
Our 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
short-term investments, common stocks and high-quality, interest-bearing
obligations.
REPGB is a foreign subsidiary and participates along with other companies in
the Netherlands in making payments to pension funds, which are not administered
by us. We treat these as a defined contribution pension plan which provides
retirement benefits for most of our REPGB employees. The contributions are
principally
F-57
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
based on a percentage of the employee's base compensation and charged against
income as incurred. This expense was $6 million, $6 million and $5 million for
2000, 2001 and 2002, respectively.
Net pension cost (excluding REPGB) includes the following components:
Year Ended December 31,
---------------------
2000 2001 2002
----- ------ ------
(in millions)
Service cost--benefits earned during the period $ 3.6 $ 3.5 $ 6.4
Interest cost on projected benefit obligation.. 2.1 8.2 10.1
Expected return on plan assets................. (3.3) (11.9) (12.9)
Curtailment and benefits enhancements.......... -- 44.9 0.6
Accounting settlement charge................... -- -- 64.9
Net amortization............................... (0.3) 0.6 0.1
----- ------ ------
Net pension cost............................ $ 2.1 $ 45.3 $ 69.2
===== ====== ======
The significant weighted-average assumptions include the following:
Year Ended December 31,
-------------------------
2000 2001 2002
------- ------- -------
Discount rate.............................. 7.5% 7.25% 6.75%
Rate of increase in compensation levels.... 3.5-5.5% 3.5-5.5% 4.0-4.5%
Expected long-term rate of return on assets 10.0% 9.5% 8.5%
F-58
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Following are reconciliations of our beginning and ending balances of our
retirement plans' benefit obligation, plans' assets and funded status for 2001
and 2002 (excluding REPGB). The prepaid pension asset as of December 31, 2001
was primarily recorded in other long-term assets.
Year Ended
December 31,
---------------
2001 2002
------ -------
(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year........ $ 28.7 $ 137.6
Service cost................................. 3.5 6.4
Interest cost................................ 8.2 10.1
Curtailments and benefits enhancement........ 55.8 0.6
Transfers from affiliates.................... 35.4 (125.7)
Acquisitions................................. -- 39.8
Benefits paid................................ -- (6.2)
Plan amendments.............................. -- 2.0
Actuarial loss............................... 6.0 7.9
------ -------
Benefit obligation, end of year.......... $137.6 $ 72.5
====== =======
Change in Plans Assets
Plans assets, beginning of year.............. $ 27.3 $ 152.8
Transfers/allocations from affiliates........ 124.8 (147.0)
Employer contributions....................... 0.7 7.8
Benefits paid................................ -- (6.2)
Acquisitions................................. -- 20.9
Actual investment return..................... -- 1.2
------ -------
Plans assets, end of year................ $152.8 $ 29.5
====== =======
Reconciliation of Funded Status
Funded status................................ $ 15.2 $ (43.0)
Unrecognized transition asset................ (0.2) --
Unrecognized prior service cost.............. -- 2.0
Unrecognized actuarial loss.................. 14.8 18.2
------ -------
Net amount recognized at end of year..... $ 29.8 $ (22.8)
====== =======
As all distributions from the CenterPoint noncontributory plan to Resources
Participants after the Distribution will be made from CenterPoint plan assets,
actual investment returns on those plan assets above or below expected returns
on those plan assets are included in "transfers/allocations from affiliates" in
the above reconciliation in 2001.
The projected benefit obligation, accumulated benefit obligation, and fair
value of plan assets for the pension plans with accumulated benefit obligations
in excess of plan assets were $70.9 million, $48.7 million and $28.0 million,
respectively, as of December 31, 2002. The projected benefit obligation,
accumulated benefit obligation, and fair value of plan assets for one of our
pension plans, which had accumulated benefit obligations in excess of plan
assets as of December 31, 2001, was $6.6 million, $4.7 million and $1.7
million, respectively.
The actuarial loss during 2002 was primarily due to the decrease in the
economic assumptions used to value the benefit obligations as well as discount
rate and changes in demographics of the participants.
F-59
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Prior to the Distribution, we participated in CenterPoint's non-qualified
pension plan which allowed participants to retain the benefits to which they
would have been entitled under CenterPoint'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. Effective March 1, 2001,
we no longer provide future non-qualified pension benefits to our employees. In
connection with the Distribution, we assumed CenterPoint's obligation under the
non-qualified pension plan. The expense associated with this non-qualified plan
was $0.2 million, $2 million and $3 million in 2000, 2001 and 2002,
respectively. The accrued benefit liability for the non-qualified pension plan
was $30 million and $19 million as of December 31, 2001 and 2002, respectively.
In addition, the accrued benefit liabilities as of December 31, 2001 and 2002
include the recognition of minimum liability adjustments of $11 million and $4
million, respectively, which is reported as a component of comprehensive income
(loss), net of income tax effects. After the Distribution, participants in the
non-qualified pension plan were given the opportunity to elect to receive
distributions or have their account balance funded into a rabbi trust.
Accordingly, $14 million of the non-qualified pension plan account balances
were transferred to the rabbi trust, as discussed below.
(c) Savings Plan.
We have employee savings plans that are tax-qualified plans under Section
401(a) of the Internal Revenue Code of 1986, as amended (Code), and include a
cash or deferred arrangement under Section 401(k) of the Code for substantially
all our employees except for our foreign subsidiaries' employees. Prior to
February 1, 2002, our non-union employees, except for REMA non-union employees
and our foreign subsidiaries' employees, participated in CenterPoint's employee
savings plan that is a tax qualified plan under Section 401(a) of the Code, and
included a cash or deferred arrangement under Section 401(k) of the Code.
Under the various plans, participating employees may contribute a portion of
their compensation, pre-tax or after-tax, generally up to a maximum of 16% of
compensation with the exception of the Orion Power savings plan which
contributions are generally up to a maximum of 18% of compensation. Our savings
plans match and any payroll period discretionary employer contribution will be
made in cash; any discretionary annual employer contribution, as applicable,
may be made in our common stock, cash or both. All prior and future employer
contributions on behalf of such employees are fully vested, except some of
Orion Power employees' employer matching contributions, which may be subject to
a vesting schedule, and except some union employees as defined in their
collective bargaining agreement. Through March 1, 2001, a substantial portion
of CenterPoint's employee savings plan match was made in CenterPoint common
stock.
Our savings plans benefit expense was $6 million, $20 million and $24
million in 2000, 2001 and 2002, respectively.
(d) Postretirement Benefits.
Effective March 1, 2001, we discontinued providing subsidized postretirement
benefits to our domestic non-union employees. We incurred a pre-tax loss of $40
million during the first quarter of 2001 related to the curtailment of our
postretirement obligation. In connection with the Distribution, we incurred a
pre-tax gain of $18 million related to the accounting settlement of
postretirement benefit obligations. Prior to March 1, 2001, through a
CenterPoint subsidized postretirement plan, we provided some postretirement
benefits for substantially all of our retired employees. We continue to provide
subsidized postretirement benefits to certain union employees and Orion Power
employees. REPGB provides some postretirement benefits (primarily medical care
and life insurance benefits) for its retired employees, substantially all of
who may become eligible for these benefits when they retire. We fund our
portion of the postretirement benefits on a pay-as-you-go basis.
F-60
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Net postretirement benefit cost includes the following components:
Year Ended
December 31,
-----------------
2000 2001 2002
---- ----- ------
(in millions)
Service cost--benefits earned during the period $1.4 $ 2.0 $ 4.4
Interest cost on projected benefit obligation.. 2.0 2.7 5.1
Curtailment charge............................. -- 39.5 --
Accounting settlement gain..................... -- -- (17.6)
Net amortization............................... 0.4 0.1 0.3
---- ----- ------
Net postretirement benefit cost (benefit)... $3.8 $44.3 $ (7.8)
==== ===== ======
The significant assumptions include the following:
Year Ended December 31,
---------------------------
2000 2001 2002
------- -------- --------
Discount rate.......................... 6.6-7.5% 6.6-7.25% 6.6-6.75%
Rate of increase in compensation levels 2.0% 2.0% 3.5-4.5%
Following are reconciliations of our beginning and ending balances of our
postretirement benefit plans' benefit obligation and funded status for 2001 and
2002:
Year Ended
December 31,
--------------
2001 2002
------ ------
(in millions)
Change in Benefit Obligation
Benefit obligation, beginning of year........ $ 35.0 $ 48.5
Service cost................................. 2.0 4.4
Interest cost................................ 2.7 5.1
Benefit payments............................. (1.4) (1.1)
Transfers from affiliates.................... 9.8 --
Acquisitions................................. -- 31.0
Plan amendments.............................. -- 9.5
Foreign exchange impact...................... (2.5) 6.0
Accounting settlement gain................... -- (22.2)
Actuarial loss............................... 2.9 4.8
------ ------
Benefit obligation, end of year.......... $ 48.5 $ 86.0
====== ======
Reconciliation of Funded Status
Funded status................................ $(48.5) $(86.0)
Unrecognized prior service cost.............. -- 9.5
Unrecognized actuarial loss.................. 5.7 6.6
------ ------
Net amount recognized at end of year..... $(42.8) $(69.9)
====== ======
In 2001, we assumed health care rate increases of 9.0% that gradually
decline to 5.5% by 2010. In 2002, we assumed health care rate increases of
12.0% that gradually decline to 5.5% by 2012. The actuarial loss is due to
changes in actuarial assumptions.
F-61
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
If the health care cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2002 would
increase by approximately 18.2%. The annual effect of the 1% increase on the
total of the service and interest costs would be an increase of approximately
17.1%. If the health care cost trend rate assumptions were decreased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2002 would
decrease by approximately 14.5%. The annual effect of the 1% decrease on the
total of the service and interest costs would be a decrease of 14.1%.
During 2002, the retiree medical benefits for certain union employees were
redesigned to allow for a company-provided subsidy for premium coverage
attributable to qualifying employees. This resulted in a $9.5 million increase
in the accumulated postretirement benefit obligation during 2002.
(e) Postemployment Benefits.
We record 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 insignificant
for 2000, 2001 and 2002.
(f) Other Non-qualified Plans.
Effective January 1, 2002, select key and highly compensated employees are
eligible to participate in our non-qualified 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 our 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. We fund 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 our designated investment funds within the rabbi trust.
Through 2001, certain eligible employees participated in CenterPoint's
deferred compensation plans, which permit participants to elect each year to
defer a percentage of that year's salary and up to 100% of that year's annual
bonus. Interest generally accrued 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. We recorded interest
expense related to these deferred compensation obligations of $1 million, $4
million and $2 million in 2000, 2001 and 2002, respectively. Each of our
employees that participated in this plan has elected to have his CenterPoint
non-qualified deferred compensation plan account balance, after the
Distribution: (a) paid in a lump-sum distribution, (b) placed in a new deferred
compensation plan established by us, which generally mirrors the former
CenterPoint deferred compensation plans, or (c) rolled over to our deferred
compensation and restoration plan discussed above.
Our discounted deferred compensation obligation recorded by us was $29
million as of December 31, 2001 related to the CenterPoint deferred
compensation plan. Our discounted deferred compensation obligation related to
the deferred compensation obligation under the plan that mirrors the
CenterPoint plan was $12 million as of December 31, 2002. Our deferred
compensation and restoration liability related to the deferred compensation and
restoration plan established effective January 1, 2002 (discussed above) was
$23 million and the related investment in the rabbi trust was $23 million as of
December 31, 2002.
F-62
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(g) Other Employee Matters.
As of December 31, 2002, approximately 32% of our employees are subject to
collective bargaining arrangements, of which contracts covering 6% of our
employees will expire prior to December 31, 2003.
(13) INCOME TAXES
The components of income (loss) before income taxes, cumulative effect of
accounting change and extraordinary item are as follows:
Year Ended December 31,
---------------------
2000 2001 2002
------ ------ -------
(in millions)
United States......................................................... $198.5 $729.2 $ 215.3
Foreign............................................................... 112.6 105.5 (327.4)
------ ------ -------
Income (loss) before income taxes, cumulative effect of accounting
change and extraordinary item.................................... $311.1 $834.7 $(112.1)
====== ====== =======
Our current and deferred components of income tax expense (benefit) were as
follows:
Year Ended December 31,
----------------------
2000 2001 2002
------ ------ ------
(in millions)
Current
Federal................ $106.5 $240.8 $(74.9)
State.................. 16.9 3.8 31.9
Foreign................ -- (2.7) 2.0
------ ------ ------
Total current...... 123.4 241.9 (41.0)
------ ------ ------
Deferred
Federal................ (28.2) 20.8 204.5
State.................. 0.7 15.7 (4.7)
Foreign................ -- (4.0) 55.3
------ ------ ------
Total deferred..... (27.5) 32.5 255.1
------ ------ ------
Income tax expense........ $ 95.9 $274.4 $214.1
====== ====== ======
F-63
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:
Year Ended December 31,
-----------------------
2000 2001 2002
------ ------ -------
(in millions)
Income (loss) before income taxes.............................. $311.1 $834.7 $(112.1)
Federal statutory rate......................................... 35% 35% 35%
------ ------ -------
Income tax expense at statutory rate........................... 108.9 292.1 (39.2)
------ ------ -------
Net addition (reduction) in taxes resulting from:
State income taxes, net of valuation allowances and federal
income tax benefit........................................ 11.4 12.7 17.7
European energy goodwill impairment......................... -- -- 168.7
REPGB tax holiday........................................... (37.8) (49.9) (5.1)
Goodwill amortization....................................... 2.1 8.6 -
Federal and foreign valuation allowance..................... 12.8 3.3 22.6
Future distributions from foreign equity investment......... - - 44.6
Other, net.................................................. (1.5) 7.6 4.8
------ ------ -------
Total................................................... (13.0) (17.7) 253.3
------ ------ -------
Income tax expense............................................. $ 95.9 $274.4 $ 214.1
====== ====== =======
Effective rate................................................. 30.8% 32.9% NM (1)
====== ====== =======
- --------
(1) Not meaningful as we had a pre-tax loss of $112.1 million and income tax
expense of $214.1 million. The primary reason is due to the European energy
segment's goodwill impairment of $482 million, for which no tax benefit can
be recognized as the goodwill is non-deductible.
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%. During 2002, there was a $5.1
million reconciling item as a result of the tax holiday as the results of our
European energy segment are consolidated on a one-month-lag basis. The effect
of the change in the enacted tax rate was not material to our results of
operations.
Future Distributions from Foreign Equity Investments. During 2002, we
accrued a $46 million United States federal tax provision for future cash
distributions from our equity investment in NEA. Based on our current tax
position, during 2002, we determined that we would be obligated to pay United
States taxes on future cash distributions from NEA in excess of our tax basis.
As of December 31, 2002, our investment in NEA was $210 million. For further
discussion of our investment in NEA, see notes 8 and 14(j).
Undistributed Earnings of Foreign Subsidiaries. The undistributed earnings
of foreign subsidiaries aggregated $266 million and $319 million as of December
31, 2001 and 2002, respectively, which, under existing tax law, will not be
subject to United States income tax until distributed. Provisions for United
States income 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, we will be
subject to United States income taxes net of allowable foreign tax credits.
F-64
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Following were our tax effects of temporary differences between the carrying
amounts of assets and liabilities in the consolidated financial statements and
their respective tax bases:
Year Ended
December 31,
---------------
2001 2002
------ -------
(in millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts and credit provisions. $ 59.5 $ 30.7
Contractual rights and obligations.................... -- 13.7
Adjustment to fair value for debt..................... -- 10.9
Operating loss carryforwards.......................... -- 66.6
Other................................................. 4.8 7.0
------ -------
Total current deferred tax assets................. 64.3 128.9
------ -------
Non-current:
Employee benefits..................................... 44.3 55.3
Operating loss carryforwards.......................... 18.1 75.5
Environmental reserves................................ 15.0 26.5
Foreign exchange gains................................ 11.1 11.6
Non-trading derivative liabilities, net............... 133.7 24.5
Non-derivative stranded costs liability............... 73.1 --
Accrual for payment to CenterPoint Energy, Inc........ -- 48.7
Adjustment to fair value for debt..................... -- 50.4
Equity method investments............................. 4.0 10.0
Other................................................. 26.1 31.2
Valuation allowance................................... (15.6) (71.3)
------ -------
Total non-current deferred tax assets............. 309.8 262.4
------ -------
Total deferred tax assets......................... $374.1 $ 391.3
====== =======
Deferred tax liabilities:
Current:
Trading and marketing assets, net..................... $ 48.4 $ 37.0
Non-trading derivative assets, net.................... 0.8 23.7
Hedges of net investment in foreign subsidiaries...... 52.1 20.6
Other................................................. -- 7.3
------ -------
Total current deferred tax liabilities............ 101.3 88.6
------ -------
Non-current:
Depreciation and amortization......................... 133.6 653.6
Trading and marketing assets, net..................... 27.5 25.9
Stranded costs indemnification receivable............. 73.1 --
Contractual rights and obligations.................... -- 10.3
Future distributions from foreign equity investment... -- 46.4
Other................................................. 29.3 25.8
------ -------
Total non-current deferred tax liabilities........ 263.5 762.0
------ -------
Total deferred tax liabilities.................... $364.8 $ 850.6
------ -------
Accumulated deferred income taxes, net............ $ 9.3 $(459.3)
====== =======
F-65
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Tax Attribute Carryovers. At December 31, 2002, we had approximately $184
million, $893 million, $144 million and $0.5 million of federal, state and
foreign net operating loss carryovers and capital loss carryforwards,
respectively. The federal and state loss carryforwards can be carried forward
to offset future income through the year 2022. The foreign losses can be
carried forward indefinitely.
The valuation allowance reflects a net decrease of $5 million in 2001 and a
$56 million net increase in 2002. The net increase in 2002 results primarily
from increased state and foreign net operating losses and impairments on
capital assets. In addition, in connection with the Orion Power acquisition, we
recorded a valuation allowance of $30 million due to state net operating
losses. These net changes for 2001 and 2002 also resulted from a reassessment
of our future ability to use federal, state and foreign tax net operating loss
and capital loss carryforwards.
As discussed in note 14(j), 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, we 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 our statutorily allocated share of these
gas supply and electricity contracts. Prior to 2002, we believed that the costs
incurred by REPGB subsequent to the tax holiday ending in 2001 related to these
contracts would be deductible for Dutch tax purposes. However, due to the
uncertainties related to the deductibility of these costs, we recorded an
offsetting liability in other liabilities of $127 million as of December 31,
2001. We now believe, based upon discussions with the Dutch tax authorities in
2002, obtaining a tax deduction for these costs will require litigation in the
Netherlands, and accordingly, we reversed both the deferred tax asset and
related liability in 2002.
(14) COMMITMENTS AND CONTINGENCIES
(a) Lease Commitments.
In August 2000, we entered into separate sale-leaseback transactions with
each of three owner-lessors' respective 16.45%, 16.67% and 100% interests in
the Conemaugh, Keystone and Shawville generating stations, respectively,
acquired in the REMA acquisition. As lessee, we lease an interest in each
facility from each owner-lessor under a facility lease agreement. We expect to
make lease payments through 2029 under these leases, with total cash payments
of $1.4 billion remaining as of December 31, 2002. The lease terms expire in
2034. The equity interests in all the subsidiaries of REMA are pledged as
collateral for REMA's lease obligations and the subsidiaries have guaranteed
the lease obligations. Additionally, each of the lease obligations is backed by
an uncollateralized, irrevocable, unconditional stand-by letter of credit, see
note 9(a). In connection with the sale-leaseback transactions, we also issued
three series of pass through certificates, which represent undivided interests
in three pass through trusts. The property of each pass through trust consists
solely of nonrecourse secured lease obligation notes or lessor notes. The
amounts payable by REMA under the leases are sufficient to pay all payments of
principal and premium, if any, and interest on the lessor notes. The lessor
notes are secured by the relevant leased facility, the lease documents, and the
security for 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. As of December 31, 2001, REMA had $167 million of restricted funds
that were
F-66
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
available for REMA's working capital needs and to make future lease payments.
As of December 31, 2002, the various conditions were satisfied by REMA and
there was no restricted cash.
In the first quarter of 2001, we entered into tolling arrangements with a
third party to purchase the rights to utilize and dispatch electric generating
capacity of approximately 1,100 MW extending through 2012. Two gas-fired,
simple-cycle peaking plants generate this electricity. We did not pay any
amounts under these tolling arrangements during 2001. We paid $45 million in
tolling payments during 2002. The tolling arrangements qualify as operating
leases.
In February 2001, CenterPoint entered into a lease for office space for us
in a building under construction. CenterPoint assigned the lease agreement to
us in June 2001. The lease term, which commences in the second quarter 2003, is
15 years with two five-year renewal options.
The following table sets forth information concerning our cash obligations
under non-cancelable long-term operating leases as of December 31, 2002. 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)
2003........... $ 77 $ 85 $ 162
2004........... 84 91 175
2005........... 75 89 164
2006........... 64 87 151
2007........... 65 62 127
2008 and beyond 1,059 390 1,449
------ ---- ------
Total....... $1,424 $804 $2,228
====== ==== ======
Total lease expense for all operating leases was $24 million, $75 million
and $120 million during 2000, 2001 and 2002, respectively. During 2000, 2001
and 2002, we made lease payments related to the REMA sale-leaseback of $1
million, $259 million and $136 million, respectively. As of December 31, 2001
and 2002, we have recorded a prepaid lease obligation related to the REMA
sale-leaseback of $59 million and $59 million, respectively, in other current
assets and of $122 million and $200 million, respectively, in other long-term
assets.
(b) Construction Agency Agreements with Off-balance Sheet Special Purpose
Entities.
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. We
did not consolidate the special purpose entities as of December 31, 2002. As of
December 31, 2002, the special purpose entities have an aggregate financing
commitment from equity and debt participants (Investors) for three electric
generating facilities of $1.9 billion of which the last $515 million is
currently available only if cash collateralized. The availability of the $1.9
billion 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 29, 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. However, we
F-67
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
have generally limited our risk during construction to an amount not to exceed
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 the 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. Reliant Resources has guaranteed its
subsidiaries' obligations under the operative agreements 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, we may purchase a facility by paying an amount
approximately equal to the outstanding debt balance plus the equity balance and
any returns of equity plus any accrued and unpaid financing costs or we may
purchase the facility by assuming, directly or indirectly, the obligations of
the subsidiaries, in which case the guarantee must remain in place and lender
consent may be required. As of December 31, 2002, the special purpose entities
had property, plant and equipment of $1.3 billion, net other assets of $3
million and secured debt obligations of $1.3 billion. As of December 31, 2002,
$1.0 billion of the debt obligations outstanding bear interest at LIBOR plus a
margin of 2.25%, while the remaining $0.3 billion of the debt obligations
outstanding bear interest at a weekly floating interest rate. As of December
31, 2002, the special purpose entities had equity from unaffiliated third
parties of $49 million.
Due to the early adoption of FIN No. 46 (as explained in note 2(t)), we
began to consolidate these special purpose entities effective January 1, 2003.
The special purpose entities' financing agreement, the construction agency
agreements and the related guarantees were terminated as part of the
refinancing in March 2003. For information regarding the refinancing, see note
21(a).
(c) Off-balance Sheet Equipment Financing Structure.
We, through a subsidiary, entered into an agreement with a bank whereby the
bank, as owner, entered into contracts for the purchase and construction of
power generation equipment and our subsidiary, or its subagent, acted as the
bank's agent in connection with administering the contracts for such equipment.
The agreement was terminated in September 2002. Our subsidiary, or its
designee, had 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. We were required to cash
collateralize our obligation to administer the contracts. This cash collateral
was approximately equivalent to the total payments by the bank for the
equipment, interest and other fees. As of December 31, 2001, we had deposits of
$230 million in the collateral account.
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 collateral
deposits were returned to us. In May 2002, we were assigned and exercised a
purchase option for a contract for equipment totaling $20 million under which
payments and interest during construction totaled $8 million. We used $8
million of our collateral deposits to complete the purchase. After the
purchase, we canceled the contract and recorded a $10 million loss
F-68
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
on the cancellation of the contract, which included a $2 million termination
fee. Immediately prior to the expiration of the agreement in September 2002, we
terminated the agreement and were assigned and exercised purchase options for
contracts for steam and combustion turbines and two heat recovery steam
generators with an aggregate cost of $121 million under which payments and
interest during construction totaled $94 million. We used $94 million of our
collateral deposits to complete the purchase.
Pursuant to SFAS No. 144, we evaluated for impairment the steam and
combustion turbines and two heat recovery steam generators purchased in
September 2002. Based on our analysis, we determined this equipment was
impaired and accordingly recognized a $37 million pre-tax impairment loss that
is recorded as depreciation expense in 2002 in our statement of consolidated
operations. The fair value of the equipment and thus the impairments was
determined using a combination of quoted market prices and prices for similar
assets.
(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, 2002 of 1 to 22 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, 2002. 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,
2001 and 2002, the unamortized deferred gain on these transactions totaled $68
million and $73 million, respectively. The power plants, related equipment and
turbines remain on our consolidated financial statements and continue to be
depreciated. In February 2003, we signed a share purchase agreement to sell our
European energy operations to a Netherlands-based electricity distributor. See
note 21(b) for discussion.
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, 2002, are estimated to be $297 million. 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 and $355 million as of
December 31, 2001 and 2002, respectively. Commitments for these letters of
credit have been obtained as of December 31, 2002. As a result of REPGB's
downgrade by the credit rating agencies in November 2002, we were required to
increase the amounts of letters of credit posted as security. Further credit
rating downgrades, if any, will not require additional letters of credit to be
posted.
(e) Payment to CenterPoint in 2004.
We may be required to make a payment to CenterPoint in 2004 to the extent
the affiliated retail electric provider's price to beat for providing retail
electric service to residential and small commercial customers in CenterPoint's
Houston service territory during 2002 and 2003 exceeds the market price of
electricity. This payment is required by the Texas electric restructuring law,
unless the PUCT determines, on or prior to January 1, 2004, that 40% or more of
the amount of electric power that was consumed in 2000 by residential or small
commercial customers, as applicable, within CenterPoint's Houston service
territory is committed to be
F-69
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
served by retail electric providers other than us. This amount will not exceed
$150 per customer, multiplied by the number of residential or small commercial
customers, as the case may be, that we serve on January 1, 2004 in
CenterPoint's Houston service territory, less the number of residential or
small commercial electric customers, as the case may be, we serve in other
areas of Texas. Currently, we believe it is probable that we will be required
to make such payment to CenterPoint related to our residential customers. We
believe that the payment related to our residential customers will be in the
range of $160 million to $190 million (pre-tax), with a most probable estimate
of $175 million. We will recognize the total obligation over the period we
recognize the related revenues based on the difference between the amount of
the price to beat and the estimated market price of electricity multiplied by
the estimated energy sold through January 1, 2004 not to exceed the maximum cap
of $150 per customer. We recognized $128 million (pre-tax) during 2002. The
remainder of our estimated obligation will be recognized during 2003. In the
future, we will revise our estimates of this payment as additional information
about the market price of electricity and the market share that will be served
by us and other retail electric providers on January 1, 2004 becomes available
and we will adjust the related accrual at that time.
Currently, we believe that the 40% test for small commercial customers will
be met and we will not make a payment related to those customers. If the 40%
test is not met related to our small commercial customers and a payment is
required, we estimate this payment would be approximately $30 million.
(f) Other Commitments.
Property, Plant and Equipment Purchase Commitments. As of December 31,
2002, we had one generating facility under construction. Total estimated cost
of constructing this facility is $486 million. As of December 31, 2002, we had
incurred $332 million of the total forecasted project costs. In addition to
this generating facility, we are constructing facilities as construction agents
under construction agency agreements. These construction agency agreements were
terminated as part of the refinancing in March 2003 (see note 21(a)). See note
14(b) for further discussion of these agreements and the related special
purpose entities. As of December 31, 2002, we had additional purchase
commitments related to property, plant and equipment of $23 million.
Purchase Obligations for Trading and Marketing Assets and Liabilities,
Excluding Derivatives Accounted for under SFAS No. 133. We have cash purchase
obligations relating to our trading and marketing assets and liabilities, which
are not derivatives under SFAS No. 133. In addition, we have purchase
obligations relating to our trading and marketing assets and liabilities that,
effective January 1, 2003, pursuant to the application of EITF No. 02-03, will
be classified as "normal purchases contracts" under SFAS No. 133 and will not
be marked to market through earnings (see note 2(t)). The minimum purchase
obligations under these applicable contracts for the next five years and
thereafter as of December 31, 2002 is as follows:
Purchased
Power and
Transportation Electric Capacity Other Energy
Commitments Commitments Commitments
-------------- ----------------- ------------
(in millions)
2003............... $20 $85 $ 8
2004............... 16 7 5
2005............... 13 -- 5
2006............... 12 -- 2
2007............... 7 -- --
2008 and thereafter 17 -- --
--- --- ---
Total........... $85 $92 $20
=== === ===
F-70
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Fuel Supply, Commodity Transportation, Purchase Power and Electric Capacity
Commitments. We are 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 our consolidated balance sheet as of December 31,
2002, as these contracts meet the SFAS No. 133 exception to be classified as
"normal purchases contracts" (see note 7) or do not meet the definition of a
derivative. Minimum purchase commitment obligations under these agreements are
as follows, as of December 31, 2002:
Purchased
Power and
Fuel Transportation Electric Capacity
Commitments Commitments Commitments
----------- -------------- -----------------
(in millions)
2003............... $206 $ 83 $ 784
2004............... 130 106 174
2005............... 105 104 172
2006............... 22 104 176
2007............... 13 97 --
2008 and thereafter 214 1,117 --
---- ------ ------
Total........... $690 $1,611 $1,306
==== ====== ======
Our aggregate electric capacity commitments, including capacity auction
products, are for 17,000 MW, 4,202 MW, 4,420 MW, and 4,631 MW for 2003, 2004,
2005 and 2006, respectively. Included in the above purchase power and electric
capacity commitments are amounts acquired from Texas Genco. For additional
discussion of this commitment, see note 4(b).
The maximum duration under any individual fuel supply contract,
transportation contract, purchased power and electric and gas capacity contract
is 17 years, 21 years and 4 years, respectively.
Sale Commitments. As of December 31, 2002, we have sale commitments,
including electric energy and capacity sale contracts and district heating
contracts (see note 14(j)), which are not classified as non-trading derivative
assets and liabilities or trading and marketing assets and liabilities in our
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
$875 million, $446 million, $302 million, $245 million and $190 million in
2003, 2004, 2005, 2006 and 2007, respectively.
In addition, in January 2002, we began providing retail electric services to
approximately 1.7 million residential and small commercial customers previously
served by CenterPoint's electric utility division. Within CenterPoint's
electric utility division's territory, prices that may be charged to
residential and small commercial customers by our retail electric service
provider are subject to a specified price (price to beat) at the outset of
retail competition. The PUCT's regulations allow our 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.
We can request up to two adjustments to our price to beat in each year. During
2002, we requested and the PUCT approved two such adjustments. For a discussion
of the increase requested in January 2003, see note 21(d). We 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 PUCT determines that
40% or more of the
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RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
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. For
further information regarding the price to beat, see note 14(e).
Naming Rights to Houston Sports Complex. In October 2000, we acquired the
naming rights for a football stadium and other convention and entertainment
facilities included in the stadium complex. The agreement extends through 2032.
In addition to naming rights, the agreement provides us with significant
sponsorship rights. The aggregate cost of the naming rights will be
approximately $300 million. During the fourth quarter of 2000, we incurred an
obligation to pay $12 million in order to secure the long-term commitment and
for the initial advertising of which $10 million was expensed in the statement
of consolidated operations in 2000. Starting in 2002, we began to pay $10
million each year through 2032 for annual advertising under this agreement.
Long-term Power Generation Maintenance Agreements. We have entered into
long-term maintenance agreements that cover certain periodic maintenance,
including parts, on power generation turbines. The long-term maintenance
agreements terminate over the next 12 to 18 years based on turbine usage.
Estimated cash payments over the next five years for these agreements are as
follows (in millions):
2003..... $ 52
2004..... 30
2005..... 31
2006..... 31
2007..... 33
----
Total. $177
====
ANR Transportation Agreement. Prior to the merger of a subsidiary of
CenterPoint and RERC Corp., a predecessor of Reliant Energy Services, Inc.
(Reliant Energy Services) (a wholly-owned subsidiary) 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 us. The interest represented capacity
of 250 million cubic feet (Mmcf) per 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, a total of $84 million to ANR. As of December 31, 2001 and 2002,
Reliant Energy Services had recorded $31 million and $35 million, respectively,
to reflect our 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 made 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 CenterPoint entered into an agreement whereby the
subsidiary of CenterPoint agreed to reimburse Reliant Energy Services for any
transportation payments made under the ANR Agreement and for the $41 million
total refund discussed above. We have recorded a note receivable from
CenterPoint of $31 million and $35 million as of December 31, 2001 and 2002,
respectively.
Other Commitments. In addition to items discussed in our consolidated
financial statements, our other contractual commitments have various quantity
requirements and durations and are not considered material either individually
or in the aggregate to our results of operations or cash flows.
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RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(g) Guarantees.
We, along with certain subsidiaries, have issued guarantees, on behalf of
certain other entities, that provide financial assurance to third parties.
The following table details our various guarantees, including the maximum
potential amounts of future payments, assets held as collateral and the
carrying amount of the liabilities recorded on our consolidated balance sheet,
if applicable, as of December 31, 2002:
Carrying
Amount of
Maximum Liability
Potential Recorded on
Amount Assets Consolidated
of Future Held as Balance
Type of Guarantee Payments Collateral Sheet
----------------- --------- ---------- ------------
(in millions)
Guarantees under construction agency agreements(1). 1,325 -- --
REMA sale-leaseback operating leases(2)............ 818 -- --
Non-qualified benefits of CenterPoint's retirees(3) 58 -- --
Total Guarantees................................... $2,201 $-- $--
====== === ===
- --------
(1) See note 14(b) for discussion of our guarantees under the construction
agency agreements. These guarantees were terminated in March 2003; see note
21(a).
(2) See note 14(a) for discussion of the guarantee of the lease obligations
under the REMA sale/leaseback transactions by REMA's subsidiaries. The
guarantee expires in 2034.
(3) We have guaranteed, in the event CenterPoint becomes insolvent, certain
non-qualified benefits of CenterPoint's and its subsidiaries' existing
retirees at the Distribution. See note 4(a).
Unless otherwise noted, failure by the primary obligor to perform under the
terms of the various agreements and contracts guaranteed may result in the
beneficiary requesting immediate payment from the relevant guarantor. To the
extent liabilities exist under the various agreements and contracts that we or
our subsidiaries guarantee, such liabilities are recorded in our consolidated
balance sheet at December 31, 2002. We believe the likelihood that we would be
required to perform or otherwise incur any significant losses associated with
any of these guarantees is remote.
We have entered into contracts that include indemnification provisions as a
routine part of our business activities. Examples of these contracts include
asset purchase and sale agreements, commodity purchase and sale agreements,
operating agreements, lease agreements, procurement agreements and certain debt
agreements. In general, these provisions indemnify the counterparty for matters
such as breaches of representations and warranties and covenants contained in
the contract and/or against third party liabilities. In the case of commodity
purchase and sale agreements, generally damages are limited through liquidated
damages clauses whereby the parties agree to establish damages as the costs of
covering any breached performance obligations. In the case of debt agreements,
we generally indemnify against liabilities that arise from the preparation,
administration or enforcement of the agreement. Under our indemnifications, the
maximum potential amount is not estimable given that the magnitude of any
claims under the indemnifications would be a function of the extent of damages
actually incurred, which is not practicable to estimate unless and until the
event occurs. We consider the likelihood of making any material payments under
these provisions to be remote. For additional discussion of certain
indemnifications by us, see notes 4(a) and 14(h).
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RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(h) Environmental and Legal Matters.
We are involved in environmental and legal proceedings before various courts
and governmental agencies, some of which involve substantial amounts. In
addition, we are subject to a number of ongoing investigations by various
governmental agencies. Certain of these proceedings and investigations are the
subject of intense, highly charged media and political attention. As these
matters progress, additional issues may be identified that could expose us to
further proceedings and investigations. Our management regularly analyzes
current information and, as necessary, provides accruals for probable
liabilities on the eventual disposition of these matters that can be estimated.
We have an agreement with CenterPoint that requires us to indemnify
CenterPoint for matters relating to our business and operations prior to the
Distribution, as well as for any untrue statement of a material fact, or
omission of a material fact necessary to make any statement not misleading, in
the registration statement or prospectus that we filed with the SEC in
connection with our IPO. CenterPoint has been named as a defendant in many
legal proceedings relative to such matters and has requested indemnification
from us.
Legal Matters.
Unless otherwise indicated, the ultimate outcome of the following lawsuits,
proceedings and investigations cannot be predicted at this time. The ultimate
disposition of some of these matters could have a material adverse effect on
our financial condition, results of operations and cash flows.
California Class Actions. We, as well as certain of our present and former
officers, have been named as defendants in a number of class action lawsuits in
California. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in California in violation of California's antitrust and
unfair and unlawful business practices laws. The lawsuits seek injunctive
relief, 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. In general, these lawsuits can
be segregated into two groups based on their pre-trial status. The first group
consists of (a) three lawsuits filed in the Superior Court of the State of
California, San Diego County filed on November 27, 2000, November 29, 2000 and
January 16, 2001; (b) two lawsuits filed in the Superior Court of the State of
California, San Francisco County on January 18, 2001 and January 24, 2001; and
(c) one lawsuit filed in the Superior Court of the State of California, Los
Angeles County on May 2, 2001. These six lawsuits were consolidated and removed
to the United States District Court for the Southern District of California. In
December 2002, the court ordered these six lawsuits be remanded to state court
for further consideration. We, and our co-defendants, filed a petition with the
United States Court of Appeals for the Ninth Circuit seeking a review of the
order to remand. The petition is under consideration by the court. The second
group consists of two lawsuits filed in the Superior Court of the State of
California, San Mateo County filed on April 23, 2002 and May 15, 2002, two
lawsuits filed in the Superior Court of the State of California, San Francisco
County on May 14, 2002 and May 24, 2002, two lawsuits filed in the Superior
Court of the State of California, Alameda County on May 21, 2002, one lawsuit
filed in the Superior Court of the State of California, San Joaquin County on
May 10, 2002 and one lawsuit filed in the Superior Court of the State of
California, Los Angeles County on October 18, 2002. These eight lawsuits were
consolidated in the United States District Courts, six of which were removed to
the United States District Court for the Northern District of California, one
was removed to the United States District Court for the Eastern District of
California, and one was removed to the United States District Court for the
Central District of California. Additionally, on July 15, 2002, the Snohomish
County Public Utility District filed a class action lawsuit against us in
United States District Court for the Central District of California. In January
2003, the court granted our motion to dismiss this lawsuit on the
F-74
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
grounds that the plaintiffs' claims are barred by federal preemption and the
FERC filed rate doctrine. The plaintiffs have appealed to the United States
Court of Appeals for the Ninth Circuit.
Oregon Class Actions. On December 16, 2002, a class action lawsuit was
filed against us in the Circuit Court of the State of Oregon, County of
Multnomah. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in Oregon in violation of Oregon's consumer protection,
fraud and negligence laws. The lawsuit seeks injunctive relief, 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. This lawsuit was removed to the United States District Court for the
Northern District of California.
Washington Class Actions. On December 20, 2002, a class action lawsuit was
filed against us in United States District Court for the Western District of
Washington. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in Washington in violation of Washington's consumer
protection, fraud and negligence laws. The lawsuit seeks injunctive relief,
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.
California Attorney General Actions. On March 11, 2002, the California
Attorney General filed a lawsuit against us in Superior Court of the State of
California, San Francisco County. The California Attorney General alleges
various violations 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). The lawsuit seeks injunctive
relief, disgorgement of our alleged unlawful profits for sales of electricity
and civil penalties. We removed this lawsuit to the United States District
Court for the Northern District of California. In March 2003, the court granted
our motion to dismiss this lawsuit on the grounds that the plaintiffs' claims
are barred by federal preemption and the FERC filed rate doctrine.
On March 19, 2002, the California Attorney General filed a complaint against
us with the FERC. The complaint alleges that we, as a seller with market-based
rates, violated our tariffs by not filing with the FERC transaction-specific
information about all of our sales and purchases at market-based rates. The
California Attorney General argued that, as a result, all past sales should be
subject to a refund if they are found to be above just and reasonable levels.
In May 2002, the FERC issued an order that largely denied the complaint and
required only that we file revised transaction reports regarding prior sales in
California spot markets. In September 2002, the California Attorney General
petitioned the United States Court of Appeals for the Ninth Circuit for review
of the FERC orders. The California Attorney General's petition is under
consideration by the court.
On April 15, 2002, the California Attorney General filed a lawsuit against
us in San Francisco County Superior Court. The lawsuit is substantially similar
to the complaint described above filed by the California Attorney General with
the FERC. The lawsuit also alleges that we consistently charged unjust and
unreasonable prices for electricity and that each unjust charge violated
California law. The lawsuit seeks fines of up to $2,500 for each alleged
violation and such other equitable relief as may be appropriate. We removed
this lawsuit to the United States District Court for the Northern District of
California. In March 2003, the court granted our motion to dismiss this lawsuit
on the grounds that the plaintiffs' claims are barred by federal preemption and
the FERC filed rate doctrine.
On April 15, 2002, the California Attorney General and the California
Department of Water Resources filed a lawsuit against us in the United States
District Court for the Northern District of California. The plaintiffs allege
that our acquisition of electric generating facilities from Southern California
Edison in 1998 violated
F-75
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Section 7 of the Clayton Act, which prohibits mergers or acquisitions that
substantially lessen competition. The lawsuit alleges that the acquisitions
gave us market power, which we then exercised to overcharge California
consumers for electricity. The lawsuit seeks injunctive relief against alleged
unfair competition, divestiture of our California facilities, disgorgement of
alleged illegal profits, damages, and civil penalties for each alleged exercise
of illegal market power. In March 2003, the court dismissed the plaintiffs'
claim for damages and Section 7 of the Clayton Act but declined to dismiss the
plaintiffs' injunctive claim for divestiture of our California facilities.
California Lieutenant Governor Class Action. On November 20, 2002, the
California Lieutenant Governor filed a taxpayer representative lawsuit against
us in Superior Court of the State of California, Los Angeles County on behalf
of purchasers of gas and power in California. The plaintiffs allege that we
manipulated the pricing of gas and power by reporting false prices and
fraudulent trades to the publishers of various price indices. The lawsuit seeks
injunctive relief, disgorgement of profits and funds acquired by the alleged
unlawful conduct.
FERC Complaints. On April 11, 2002, the FERC set for hearing a series of
complaints filed by Nevada Power Company, which seek reformation of certain
forward power contracts with several companies, including two contracts with us
that have since been terminated. In December 2002, the presiding administrative
law judge in these consolidated proceedings issued recommended findings of fact
favorable to our positions and upholding the contracts. Those recommendations
are pending before the FERC for final decision. PacifiCorp Company filed a
similar complaint challenging two 90-day contracts with us. In February 2003,
the presiding administrative law judge issued an initial decision recommending
the dismissal of PacifiCorp Company's complaint and upholding the contracts.
The FERC has stated that it intends to issue final decisions in both complaints
in May 2003.
Trading and Marketing Proceedings and Investigations. We are party to the
following proceedings and investigations relating to our trading and marketing
activities, including our round trip trades and certain structured transactions.
In June 2002, the SEC advised us that it had issued a formal order in
connection with its investigation of our financial reporting, internal controls
and related matters. The investigation is focused on our round trip trades and
certain structured transactions. We are cooperating with the SEC staff.
As part of the Commodity Futures Trading Commission's (CFTC) industry-wide
investigation of so-called round trip trading, the CFTC has subpoenaed
documents, requested information and conducted discovery relating to our
natural gas and power trading activities, including round trip trades and
alleged price manipulation, occurring since January 1999. The CFTC is also
looking into the facts and circumstances surrounding certain events in June
2000 that were the subject of a settlement with FERC in January 2003 described
below. We are cooperating with the CFTC staff.
On March 26, 2003, the FERC staff issued a report entitled "Final Report on
Price Manipulation in Western Markets," which expanded and finalized the FERC
staff's August 13, 2002 initial report. Certain findings, conclusions and
observations in the FERC staff report, if adopted or otherwise acted on by the
FERC, could have a material adverse affect on us. The report recommends the
institution of proceedings directing certain entities, including us, to show
cause why bids submitted in markets operated by the Cal ISO and California
Power Exchange (Cal PX) from May to October 2000 did not constitute economic
withholding or inflated bidding in violation of the Cal ISO and Cal PX tariffs.
If adopted, such proceedings could require a disgorgement of revenues related
to some sales for the period May to October 2000. The report also recommends
the institution of proceedings directing certain entities, including us, to
show cause why certain behavior identified in a January 6, 2003 report by the
Cal ISO, entitled "Analysis of Trading and Scheduling Strategies Described in
the Enron
F-76
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Memos," did not constitute gaming in violation of the tariffs of the Cal ISO
and Cal PX, and if adopted, such proceedings could require a disgorgement of
revenues from certain transactions from the period January 1, 2000 through June
21, 2001, which the Cal ISO report identified as an amount less than $30.00
potentially attributable to us. We will have an opportunity to provide comments
on these recommendations before formal proceedings are commenced. Finally, the
report recommends that certain entities, including us, demonstrate that we no
longer sell natural gas at wholesale or have instituted certain practices with
regards to reporting natural gas price information, have disciplined employees
that participated in manipulation or attempted manipulation of public price
indices, and are cooperating fully with any government agency investigating our
prior price reporting practices. We do not know when FERC intends to act on the
staff's recommendations.
Also on March 26, 2003, the FERC instituted proceedings directing our
trading company and BP Energy Company (BP) to show cause why each company's
market-based rate authority should not be revoked. These proceedings arose in
connection with certain actions taken by one of our traders and one of BP's
traders relating to sales of electricity at the Palo Verde hub. If FERC were to
prospectively revoke our trading company's market-based rate authority, it
could have a material adverse affect on us. We must respond to the FERC within
twenty-one days and intend to contest the FERC's proposed remedy for the
alleged conduct.
On January 31, 2003, in connection with the FERC's investigation of
potential manipulation of electricity and natural gas prices in the Western
United States, the FERC approved a stipulation and consent agreement between
the FERC staff and us relating to certain actions taken by some of our traders
over a two-day period in June 2000. Under the agreement, we agreed to pay $14
million directly to customers of the Cal PX and certain other terms, including
a requirement to abide by a must offer obligation to submit bids for all of our
uncommitted, available capacity from our plants located in California into a
California spot market one additional year following termination of our
existing must offer obligation or until December 31, 2006, whichever is later.
We have received subpoenas and informal requests for information from the
United States Attorney for the Southern District of New York and the Northern
District of California for documents, interviews and other information
pertaining to the round trip trades, and our energy trading activities. We are
cooperating with both offices of the United States Attorney.
In connection with the PUCT's industry-wide investigation into potential
manipulation of the ERCOT market, we have provided information to the PUCT
concerning our scheduling and trading practices on and after July 31, 2001.
Also, we, and four other qualified scheduling entities in ERCOT, reached a
settlement relating to scheduling issues that arose during August 2001. The
PUCT approved the settlement on November 7, 2002.
Shareholder Class Actions. We, as well as certain of our present and former
officers and directors, have been named as defendants in 11 class action
lawsuits filed on behalf of purchasers of our securities and the securities of
CenterPoint. CenterPoint is also named as a defendant in three of the lawsuits.
Two of the lawsuits name as defendants the underwriters of our IPO, which we
have agreed to indemnify. One of those two lawsuits names our independent
auditors as a defendant. The dates of filing of these lawsuits are as follows:
two lawsuits on May 15, 2002; two lawsuits on May 16, 2002; one lawsuit on May
17, 2002; one lawsuit on May 20, 2002; one lawsuit on May 21, 2002; one lawsuit
on May 23, 2002; one lawsuit on June 19, 2002; one lawsuit on June 20, 2002;
and one lawsuit on July 1, 2002. Ten of the lawsuits were filed in the United
States District Court, Southern District of Texas, Houston Division. One
lawsuit was filed in the United States District Court, Eastern District of
Texas, Texarkana Division and subsequently transferred to the United States
District Court, Southern District of Texas, Houston Division. The lawsuits
allege that the defendants overstated revenues by including
F-77
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
transactions involving the purchase and sale of commodities with the same
counterparty at the same price and that we improperly accounted for certain
other transactions. The lawsuits seek monetary damages and, in one of the
lawsuits rescission, on behalf of a supposed class. In eight of the lawsuits,
the class is composed of persons who purchased or otherwise acquired our
securities and/or the securities of CenterPoint during specified class periods.
The three lawsuits that include CenterPoint as a named defendant were also
filed on behalf of purchasers of our securities and/or the securities of
CenterPoint during specified class periods.
Four class action lawsuits were filed on behalf of purchasers of the
securities of CenterPoint. CenterPoint and several of its officers are named as
defendants. The dates of filing of the four lawsuits are as follows: one on May
16, 2002; one on May 21, 2002; one on June 13, 2002; and one on June 17, 2002.
The lawsuits were filed in the United States District Court, Southern District
of Texas, Houston Division. The lawsuits allege that the defendants violated
federal securities laws by issuing false and misleading statements to the
public. The plaintiffs allege that the defendants made false and misleading
statements as part of an alleged scheme to artificially inflate trading volumes
and revenues by including transactions involving the purchase and sale of
commodities with the same counterparty at the same price, to use the spin-off
to avoid exposure to our liabilities and to cause the price of our stock to
rise artificially, among other things. The lawsuits seek monetary damages on
behalf of persons who purchased CenterPoint securities during specified class
periods. The court consolidated all of the lawsuits pending in the United
States District Court, Southern District of Texas, Houston Division and
appointed the Boca Raton Police & Firefighters Retirement System and the
Louisiana School Employees Retirement System to be the lead plaintiffs in these
lawsuits. The lead plaintiffs seek monetary relief purportedly on behalf of
purchasers of CenterPoint common stock from February 3, 2000 to May 13, 2002,
purchasers of our common stock in the open market from May 1, 2001 to May 13,
2002 and purchasers of our common stock in our IPO or purchasers of common
stock that are traceable to our IPO. The lead plaintiffs allege, among other
things, that the defendants misrepresented our revenues and trading volumes by
engaging in round trip trades and improperly accounted for certain structured
transactions as cash flow hedges, which resulted in earnings from these
transactions being accounted for as future earnings rather than being accounted
for as earnings in 2001.
On February 7, 2003, a lawsuit was filed against us in United States
District Court for the Northern District of Illinois, Eastern Division. The
plaintiffs allege that we violated federal securities law, Illinois common law
and the Illinois Consumer Fraud and Deceptive Trade Practices Act. The lawsuit
makes allegations similar to those made in the above-described class action
lawsuits and seeks treble the amount of damages alleged, costs of suit and
attorneys' fees.
ERISA Action. On May 30, 2002, a class action lawsuit was filed in the
United States District Court, Southern District of Texas, Houston Division
against us, certain of our present and former officers and directors,
CenterPoint, certain of the present and former directors and officers of
CenterPoint and certain present and former members of the benefits committee of
CenterPoint on behalf of participants in various employee benefits plans
sponsored by CenterPoint. The lawsuit alleges that the defendants breached
their fiduciary duties to various employee benefits plans sponsored by
CenterPoint, in violation of the Employee Retirement Income Security Act. The
plaintiffs allege that the defendants permitted the plans to purchase or hold
securities issued by CenterPoint when it was imprudent to do so, including
after the prices for such securities became artificially inflated because of
alleged securities fraud engaged in by the defendants. The lawsuit seeks
monetary damages for losses suffered by a class of plan participants whose
accounts held CenterPoint securities or our securities, as well as equitable
relief in the form of restitution.
Shareholder Derivative Actions. On May 17, 2002, a derivative lawsuit was
filed against our directors and independent auditors in the 269th Judicial
District, Harris County, Texas. The lawsuit alleges that the defendants
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RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
breached their fiduciary duties to us. The shareholder plaintiff alleges that
the defendants caused us to conduct our business in an imprudent and unlawful
manner, including allegedly failing to implement and maintain an adequate
internal accounting control system, engaging in transactions involving the
purchase and sale of commodities with the same counterparty at the same price,
and disseminating materially misleading and inaccurate information regarding
our revenue and trading volume. The lawsuit seeks monetary damages on behalf of
us.
On October 25, 2002, a derivative lawsuit was filed against the directors
and officers of CenterPoint. The lawsuit was filed in the United States
District Court for the Southern District of Texas, Houston Division. The
lawsuit alleges breach of fiduciary duty, waste of corporate assets, abuse of
control and gross mismanagement by the defendants causing CenterPoint to
overstate the revenues through round trip and structured transactions and
breach of fiduciary duty in connection with the Distribution and our IPO. The
lawsuit seeks monetary damages on behalf of CenterPoint as well as equitable
relief in the form of a constructive trust on the compensation paid to the
defendants. A special litigation committee appointed by the board of directors
of CenterPoint is investigating similar allegations made in a June 28, 2002
demand letter from a stockholder of CenterPoint. The letter states that certain
shareholders of CenterPoint are considering filing a derivative suit on behalf
of CenterPoint and demands that CenterPoint take several actions in response to
the alleged round trip trades and structured transactions. The special
litigation committee is investigating the allegations made in the demand letter
to determine whether pursuit of a derivative lawsuit is in the best interest of
CenterPoint.
Environmental Matters.
REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see note 5(b)), we 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, 2002, REMA had liabilities associated with six future
ash disposal site closures and six current site investigations and
environmental remediations. We have recorded our estimate of these
environmental liabilities in the amount of $35 million as of December 31, 2002.
We expect approximately $13 million will be paid over the next five years.
REPGB Asbestos Abatement and Environmental Remediation. Prior to our
acquisition of REPGB (see note 5(c)), REPGB had a $25 million obligation
primarily related to asbestos abatement, as required by Dutch law, and soil
remediation at six sites. During 2000, we 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. As of December 31, 2002, the recorded undiscounted liability for
asbestos abatement, soil remediation and plant water system compliance was $20
million. We expect approximately $8 million will be paid over the next five
years.
Orion Power Environmental Contingencies. In connection with Orion Power's
acquisition of 70 hydro plants in northern and central New York and four
gas-fired or oil-fired plants in New York City, Orion Power assumed the
liability for the estimated cost of environmental remediation at several
properties. Orion Power developed remediation plans for each of these
properties and entered into Consent Orders with the New York State Department
of Environmental Conservation at two New York City sites and one hydro site for
releases of petroleum and other substances by the prior owners. As of December
31, 2002, the undiscounted liability assumed and recorded by us for these
assets was approximately $8 million, which we expect to pay out through 2006.
F-79
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
In connection with the acquisition of Midwest assets by Orion Power, Orion
Power became responsible for the liability associated with the closure of three
ash disposal sites in Pennsylvania. As of December 31, 2002, the liability
assumed and recorded by us for these disposal sites was approximately $14
million, with $1 million to be paid over the next five years.
Other Matters.
We are involved in other legal and environmental proceedings before various
courts and governmental agencies regarding matters arising in the ordinary
course of business, some of which involve substantial amounts. We believe that
the effects on our consolidated financial statements, if any, from the
disposition of these matters will not have a material adverse effect on our
financial condition, results of operations or cash flows.
(i) California Energy Sales Credit and Refund Provisions.
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. 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 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 in April 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 that portion of the
power demand that cannot be met from their own supply sources (net short load).
Pursuant to emergency legislation enacted by the California legislature, the
California Department of Water Resources (CDWR) negotiated and purchased power
through short and long-term contracts and through real-time markets operated by
the Cal ISO to serve the net short load requirements of PG&E and SCE. In
December 2001, the CDWR began making payments to the Cal ISO for real-time
transactions. In May 2002, the FERC issued an order stating that wholesale
suppliers, including us, should receive interest payments on past due amounts
owed by the Cal ISO and the CDWR. As a result, we recorded $5 million of net
interest receivable during 2002, discussed below. The CDWR has now made payment
through the Cal ISO for its real-time energy deliveries subsequent to January
17, 2001, although the Cal ISO's distribution of the CDWR's payment for the
month of January 2001, and the allocation of interest to past due amounts, are
the subjects of motions that we have filed with the FERC objecting to the Cal
ISO's failure to allocate the January payment and interest solely to post
January 17, 2001 transactions. In addition, we are prosecuting a lawsuit in
California to recover the market value of forward contracts seized by
California Governor Gray Davis in violation of the Federal Power Act. Governor
Davis' actions prevented the liquidation of the contracts by the Cal PX to
satisfy the outstanding obligations of SCE and PG&E to wholesale suppliers,
including us. The timing and ultimate resolution of this claim is uncertain at
this time.
California Credit Provision. We were owed a total receivable, including
interest, of $302 million (net of estimated refund provision of $15 million) as
of December 31, 2001, and $120 million (net of estimated refund provision of
$191 million) as of December 31, 2002, 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, 2002.
From January 1, 2003 through March 31, 2003, we have collected $7 million of
these receivable balances.
F-80
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
During 2000 and 2001, we recorded net pre-tax credit provisions against
receivable balances related to energy sales in California of $39 million and
$29 million, respectively. As of December 31, 2001, we had a pre-tax credit
provision of $68 million against receivable balances related to energy sales in
the California market. During 2002, $62 million of a previously accrued credit
provision for energy sales in California was reversed. The reversal resulted
from collections of outstanding receivables during the period, a determination
that credit risk had been reduced on the remaining outstanding receivables as a
result of payments in 2002 to the Cal PX and due to the write-off of
receivables as a result of a May 15, 2002 FERC order and related
interpretations and a March 26, 2003 FERC order on proposed findings on refund
liability, discussed below. As of December 31, 2002, we had a remaining pre-tax
credit provision of $6 million against these receivable balances. We will
continue to assess the collectability of these receivables based on further
developments.
FERC Refunds. In response to the filing of a number of complaints
challenging the level of wholesale prices in California, the FERC initiated a
staff investigation and issued a number of orders implementing a series of
wholesale market reforms. In these orders, the FERC also instituted a refund
proceedings, described below. Prior to proposing a methodology for calculating
refunds in the refund proceeding discussed below, the FERC identified amounts
charged by us for sales in California to the Cal ISO and the Cal PX for the
period January 1, 2001 through June 19, 2001 as being subject to possible
refunds. Accordingly, during 2001, we accrued refunds of $15 million.
The FERC issued an order in July 2001 adopting a refund methodology and
initiating a hearing schedule to determine (a) revised mitigated prices for
each hour from October 2, 2000 through June 20, 2001, (b) the amount owed in
refunds by each electric wholesale supplier according to the methodology and
(c) the amount currently owed to each electric wholesale supplier. The FERC
issued an order on March 26, 2003, adopting in most respects the proposed
findings of the presiding administrative law judge that had been issued in
December 2002 following a hearing to apply the refund formula. The most
consequential change involved the adoption of a different methodology for
determining the gas price component of the refund formula. Instead of using
California gas indices, the FERC ordered the use of a proxy gas price based on
producing area price indices plus the posted transportation costs. In addition,
the order allows generators to petition for a reduction of the refund
calculation upon a submittal to the FERC of their actual gas costs and
subsequent FERC approval. Based on the proposed findings of the administrative
law judge, discussed above, adjusted for the March 2003 FERC decision to revise
the methodology for determining the gas price component of the formula, we
estimate our refund obligation to be between $191 million and $240 million for
energy sales in California (excluding the $14 million refund related to the
FERC settlement in January 2003, as discussed in note 14(h)). The low range of
our estimate is based on a refund calculation factoring in a reduction in the
total FERC refund based on the actual cost paid for gas over the proposed proxy
gas price. Our estimate of the range will be revised further as all components
of the FERC order can be analyzed. We cannot currently predict whether that
will result in an increase or decrease in our high and low points in the range.
The high range of our estimate of the refund obligation assumes that the refund
obligation is not adjusted for the actual cost paid for gas over the proposed
proxy gas price. During 2002, we recorded reserves for refunds of $176 million
related to energy sales in California. As discussed above, $15 million was
recognized during 2001. As of December 31, 2002, our reserve for refunds
related to energy sales in California is $191 million, excluding the $14
million related to the FERC settlement in January 2003, see note 14(h). The
California refunds, excluding the $14 million related to the FERC settlement
discussed in note 14(h), will likely be offset against unpaid amounts owed to
us for our prior sales in California.
Interest Calculation. In the fourth quarter of 2002, we recorded net
interest income of $5 million based on the December 2002 findings of the
presiding administrative law judge. The net interest income was estimated
F-81
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
using the low end of the potential refund, the receivable balance outstanding,
and the quarterly interest rates for the applicable time period designated by
the FERC.
(j) European Stranded Cost and Indemnification and Settlement of Stranded
Cost.
Background. In January 2001, the Dutch Electricity Production Sector
Transitional Arrangements Act (Transition Act) became effective. Among other
things, the Transition Act 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 three gas supply contracts
and four power contracts, entered into prior to the liberalization of the Dutch
wholesale electricity market and a contract relating to the construction of an
interconnection cable between Norway and the Netherlands subject to a long-term
power exchange agreement (the NorNed Project). REPGB's stranded cost
obligations also includes uneconomical district heating contracts that were
previously administrated by NEA prior to deregulation of the Dutch power market.
In January 2001, we recognized an out-of-market, net stranded cost liability
for our gas and electric import contracts and district heating commitments. At
such time, we recorded a corresponding asset of equal amount for the
indemnification of this obligation from REPGB's former shareholders and the
Dutch government, as applicable (as further discussed below).
The gas supply contract expires in 2016 and provides for gas imports
aggregating 2.283 billion cubic meters per year. In 2001, two of the stranded
cost power contracts were settled and terminated. In May 2002, the two
remaining stranded cost power contracts were amended. The district heating
obligations relate to three water heating supply contacts entered into with
various municipalities expiring from 2008 through 2015. Under the district
heating contracts, the municipal districts are required to take annually a
combined minimum of 5,549 terajoules (TJ) increasing annually to 7,955 TJ over
the life of the contracts.
Stranded Cost Indemnification. Until December 2001, the former shareholders
of REPGB were obligated to indemnify REPGB for up to NLG 1.9 billion
(approximately $766 million as of December 31, 2001) of its share of NEA's
stranded cost liabilities and the district heat stranded cost liabilities.
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
long-term district heating contracts. In July 2001, the European Commission
ruled that under certain conditions the Dutch government can provide financial
compensation for the district heating contracts. To the extent that this
compensation is not ultimately provided to the generation companies by the
Dutch government, REPGB is entitled to claim compensation directly from the
former shareholders of REPGB as further discussed below.
Settlement of Stranded Cost Indemnification Agreement. In December 2001,
REPGB and its former shareholders agreed to settle the indemnity obligations of
the former shareholders insofar as they related to
F-82
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
NEA's stranded cost gas supply and power contracts and other obligations
(excluding district heating obligations).
Under the settlement agreement, the former shareholders of REPGB paid REPGB
NLG 500 million ($202 million) in the first quarter of 2002. REPGB deposited
the settlement payment into an escrow account, withdrawals from which are at
the discretion of REPGB for use in discharging stranded cost obligations
related to the gas and electric import contracts. As of December 31, 2002, the
remaining escrow funds of $6 million are recorded in restricted cash. Any
remaining funds as of January 1, 2004 will be distributed to REPGB.
Prior to the settlement agreement, pursuant to the purchase agreement of
REPGB, as amended, REPGB was entitled to an approximately $51 million dividend
from NEA with any remainder owing to the former shareholders. Under the
settlement agreement, the former shareholders waived all rights to
distributions of NEA.
As a result of this settlement, we recognized in the fourth quarter of 2001
a net gain of $37 million for the difference between (a) the sum of the cash
settlement payment of $202 million and the additional rights to claim
distributions of the NEA investment of $248 million and (b) the sum of 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
our consolidated balance sheet.
In addition, under the settlement agreement, the former shareholders
continue to be under an obligation to indemnify REPGB for certain district
heating contracts. Under the terms of the settlement agreement, REPGB can elect
between two forms of indemnification after the Ministry of Economic Affairs of
the Netherlands publishes its regulations for compensation of stranded cost
associated with district heating projects. 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 approximately $28 million (assuming the December 31, 2002
exchange rate of 1.0492 U.S. dollar per Euro) and in certain circumstances this
payment can increase to approximately $36 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 approximately $333 million (assuming the December 31,
2002 exchange rate of 1.0492 U.S. dollar per Euro) less the amount of
compensation provided by the new compensation rules and certain proceeds
received from arbitrations. To date, the Ministry of Economic Affairs had not
published its compensation rules. Based on current assumptions, it is
anticipated that such rules will be published in 2003. If no compensation rules
have taken effect by December 31, 2003, REPGB is entitled, but not obligated,
to elect to seek compensation from the former shareholders, and as an
alternative, is also entitled to wait to make an election until regulations for
compensation are published.
Amendments to Stranded Cost Electricity Import Contracts. In May 2002, NEA
and its four shareholders (including REPGB) entered into agreements amending
the terms of the two remaining power supply agreements. These two contracts
provide for the following capacities and terms: (a) 300 MW through 2003, and
(b) 600 MW through March 2002, increasing to 750 MW through March 2009.
Under the terms of the settlement agreements, NEA paid the counterparties a
net aggregate payment of Euro 485 million, approximately $446 million (of which
REPGB's proportionate share as a NEA shareholder was Euro 109 million,
approximately $100 million). In July 2002, REPGB paid its share of the
settlement payment with funds from the stranded cost indemnity escrow account,
as discussed above. In exchange for its portion of the settlement payment, the
counterparties to the power contracts replaced the existing terms with a
market-based electricity price index for comparable electricity products in
addition to other changes.
F-83
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As a result of the settlement agreements, in the second quarter of 2002, we
recognized a pre-tax net gain of $109 million for the difference between (a)
the fair values of the original power contracts ($203 million net liability
previously recorded in non-trading derivative liabilities) and the fair values
of the amended power contracts ($6 million net asset recorded in trading and
marketing assets) and (b) the settlement payment of $100 million, as described
above. The pre-tax net gain of $109 million was recorded as a reduction of
purchased power expense in the statement of consolidated operations in the
second quarter of 2002.
Remaining Liability for Original Stranded Cost. As of December 31, 2001, we
have recorded a liability of $369 million for our stranded cost gas and
electric commitments in non-trading derivative liabilities and a liability of
$206 million for our district heating commitments in current and non-current
other liabilities. As of December 31, 2002, we have recorded a liability of
$154 million for our stranded cost gas contract in non-trading derivative
liabilities, an asset of $8 million for our amended power contracts in trading
and marketing assets, and a liability of $224 million for our district heating
commitments in current and non-current other liabilities. As of December 31,
2001 and 2002, we have recorded an indemnification receivable for the district
heating stranded cost liability of $206 million and $224 million, respectively.
Pursuant to SFAS No. 133, we mark-to-market the stranded cost gas contract.
Prior to the amendments to the remaining two power contacts, pursuant to SFAS
No. 133, the power contracts were marked-to-market. Subsequent to amending the
remaining power contracts, the power contracts are marked-to-market as a part
of our energy trading activities. Pursuant to SFAS No. 133, during 2002, we
recognized a $19 million net gain recorded in fuel expense related to changes
in the valuation of the stranded cost contracts, excluding the effects of the
gain related to amending the two power contracts discussed above and net of
derivative transactions entered into to hedge the economics of the stranded
cost gas contract. The valuation of the gas contract could be affected by,
among other things, changes in the price of coal, low sulfur fuel oil and the
value of the U.S. dollar relative to the Euro.
NorNed Project. NEA entered into commitments with certain Norwegian
counterparties (the Norwegian Counterparties) for the construction of a grid
interconnector cable between the Netherlands and Norway, subject to the
operation of a long-term power exchange agreement (25 years in duration). The
power exchange agreement contemplates, among other terms, exclusive use and
cost free access to the cable by NEA and the Norwegian counterparties. The
power exchange agreement is subject to, among other things, clearance by the
European Commission and the Dutch regulatory authorities of the terms and
conditions of the power exchange agreement. In 2001, NEA and the Norwegian
counterparties filed a notification request regarding the power exchange
agreement with the European Commission. If the European Commission or the Dutch
regulatory authorities do not unconditionally clear the terms and conditions of
the cable construction agreement or the power exchange agreement, NEA and the
Norwegian counterparties contractually will initiate a formal renegotiation
period. If the parties cannot agree within the formal renegotiation period, the
cable and power exchange agreement obligations are terminated. Under the
Transition Act, NEA is entitled to recover the cable construction costs from
TenneT, the Netherlands grid operator. However, at this early stage it is
uncertain how NEA will receive the transport tariff funds intended to recover
the construction costs of the cable. Assuming that the Transition Act is fully
implemented with respect to this matter, REPGB believes that NEA will
ultimately recover the cost of the cable.
Investment in NEA. During the second quarter of 2001, we recognized 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 our evaluation of
NEA's financial position and fair value. The fair value of our investment in
NEA is dependent upon the ultimate resolution of its
F-84
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
existing contingencies and proceeds received from liquidating its remaining net
assets. In addition, during 2001 in connection with the settlement of the
stranded cost indemnity, we recorded a $248 million increase in our investment
in NEA, as discussed above. In 2002, NEA distributed to REPGB Euro 141 million,
approximately $137 million. For additional information regarding our investment
in NEA, see note 8.
(k) Reliant Energy Desert Basin Contingency.
One of our subsidiaries, Reliant Energy Desert Basin (REDB), sells power to
Salt River Project (SRP) under a long-term power purchase agreement. Reliant
Resources guarantees certain of REDB's obligations under the agreement. In the
event we are downgraded to below investment grade by two major ratings
agencies, SRP can request performance assurance in the form of cash or a letter
of credit from REDB under the agreement or us under the guarantee. The total
amount of performance assurance cannot exceed $150 million. In September 2002,
following our downgrade to below investment grade by two rating agencies, SRP
requested performance assurance from us and REDB in the aggregate amount of
$150 million. We informed SRP that the agreement does not stipulate the amount
of performance assurance required in the event of a credit downgrade. We also
communicated to SRP that under prevailing market conditions and after giving
effect to other factors, a letter of credit in the amount of $3 million would
provide commercially reasonable assurance of REDB's ability to perform its
obligations under the agreement. Accordingly, we provided SRP with a $3 million
letter of credit. SRP subsequently notified us that it deemed the amount
inadequate and returned the letter of credit to us. SRP has alleged that we
breached the agreement by failing to provide the requested $150 million letter
of credit. We have communicated to SRP that we remain of the opinion that the
provision of a $3 million letter of credit fulfills the obligation of us and
REDB to provide performance assurance and that SRP would be in breach of the
agreement and liable to REDB for damages if it were to terminate the agreement
based on our refusal to provide performance assurance in the amount of $150
million. As of March 20, 2003, neither SRP nor we have taken steps to terminate
the agreement.
(l) Tolling Agreement for Liberty's Electric Generating Station.
The output of Liberty's electric generating station is contracted under a
tolling agreement between LEP and PG&E Energy Trading-Power, L.P. (PGET) for an
initial term through September 2016, with an option by PGET to extend the
initial term for an additional two years. Under the tolling agreement, PGET has
the exclusive right to receive all electric energy, capacity and ancillary
services produced by the Liberty generating station, and PGET must pay for all
fuel used by the Liberty generating station.
The tolling agreement requires PGET to maintain guarantees, issued by
entities having investment grade credit ratings, for its obligations under the
tolling agreement. During 2002, several rating agencies downgraded to
sub-investment grade the debt of the two guarantors of PGET, PG&E National
Energy Group, Inc. and PG&E Gas Transmission Northwest Corp. Due to the fact
that PGET did not post replacement security within the period required under
the tolling agreement, the downgrade constitutes an event of default by PGET
under the tolling agreement. The Liberty credit facility restricts the ability
of LEP to terminate the tolling agreement. There is also a requirement in the
Liberty credit facility that Liberty and LEP enforce all of their respective
rights under the tolling agreement. Liberty and LEP have received a waiver from
the lenders under the Liberty credit facility from the requirement that they
enforce all of their respective rights under the tolling agreement. In return
for this waiver, Liberty and LEP have agreed that for the term of the waiver,
they would not be able to make draws on the working capital facility that is
available under the Liberty credit facility. The current waiver expires on
April 30, 2003. There is no assurance that Liberty and LEP will be able to
receive an extension of this waiver. If Liberty is unable to obtain an
extension to the waiver, then the lenders may claim that Liberty is in breach
and, if said breach is not cured, that there is an event of default under the
Liberty credit facility.
F-85
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
In addition, on August 19, 2002, and September 10, 2002, PGET notified LEP
that it believed LEP had violated the tolling agreement by not following PGET's
instructions relating to the dispatch of the Liberty station during specified
periods. The September 10, 2002 letter also claims that LEP did not timely
provide PGET with certain information to make a necessary FERC filing. While
LEP does not agree with PGET's interpretation of the tolling agreement
regarding the dispatch issue, LEP agreed to (a) compensate PGET approximately
$17,000 for the alleged damages attributable to the claims raised in the August
19, 2002 letter and (b) treat several hours of plant outages as forced outages
for purposes of the tolling agreement, thereby resolving the issues raised in
the August 19 letter (which compensation and treatment are not believed to be
material). The tolling agreement generally provides that covenant-related
defaults must be cured within 30 business days or they will (if material)
result in an event of default, entitling the non-defaulting party to terminate.
PGET has extended this cure period (relating to the September 10, 2002 letter)
to April 11, 2003. LEP has made the necessary FERC filing and is in
negotiations with PGET regarding financial settlement for this issue for
approximately $1 million. Further, LEP also believes that it has settled the
monetary impact of any violation relating to the dispatch issue. While there
can be no assurances as to the outcome of this matter, LEP believes that it
will be able to resolve the issues raised in the September 10, 2002 letter
without causing an event of default under the tolling agreement. However, if
LEP is unable to resolve the issues and PGET declares an event of default, then
PGET would be in a position to terminate the tolling agreement. In addition to
the material adverse effect such a termination would have on Liberty as
discussed below, such a termination may also result in PGET drawing on the $35
million letter of credit posted by Reliant Resources on behalf of LEP under the
tolling agreement.
LEP currently receives a fixed monthly payment from PGET under the tolling
agreement. If the tolling agreement is terminated, (a) LEP would need to find a
power purchaser or tolling customer to replace PGET or sell the energy and/or
capacity in the merchant energy market and (b) the gas transportation agreement
that PGET utilizes in connection with the tolling agreement will revert to LEP,
and LEP will be required to perform the obligations currently being performed
by PGET under the gas transportation agreement, including the posting of $5
million in credit support.
No assurance can be given that LEP would have sufficient cash flow to pay
all of its expenses or enable Liberty to make interest and scheduled principal
payments under the Liberty credit facility as they become due if the tolling
agreement is terminated. The termination of the tolling agreement may cause
both Liberty and LEP to seek other alternatives, including reorganization under
the bankruptcy laws. We, including Orion Power, would not be in default under
our current debt agreements if any of these events occur at Liberty.
As of December 31, 2002, the combined net book value of LEP and Liberty was
$425 million, excluding the non-recourse debt obligations of $268 million.
In December 2002, we evaluated the Liberty station and the related tolling
agreement for impairment. Based on our analyses, there were no impairments. The
fair value of Liberty station was determined based on an income approach, using
future discounted cash flows; a market approach, using acquisition multiples,
including price per MW, based on publicly available data for recently completed
transactions; and a replacement cost approach. If the tolling agreement is
terminated and there is not a waiver from the lenders for this event of
default, it is possible the lender would initiate foreclosure proceedings
against LEP and Liberty. If the lenders foreclose on LEP and Liberty, we
believe we could incur a pre-tax loss of an amount up to our recorded net book
value with the potential of an additional loss due to an impairment of goodwill
allocated to LEP as a result of the foreclosure. Under the tolling agreement, a
non-defaulting party who terminates the tolling agreement is entitled to
calculate its damages in accordance with specified criteria; the non-defaulting
party is the only party entitled to damages. The defaulting party would be
entitled to refer such damage calculation to arbitration. The institution of
F-86
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
any arbitration could delay the receipt of such damages for an extended period
of time. In addition, if PGET is the defaulting party, the payment of damages,
if any, could be further delayed if PGET and one or more of the guarantors of
PGET's obligations seeks protection from creditors under the bankruptcy laws.
Such filings also may result in LEP receiving significantly less in damages
than to which it might otherwise be entitled. In the event of a termination, if
PGET is the defaulting party and LEP is entitled to the payment of damages as a
result of the termination, any amounts recovered from PGET would be handled in
accordance with the Liberty credit facility. The most likely result is that the
damages would be paid into an account that is managed by the lenders under the
credit facility and LEP would not recover any of such damages.
(15) RECEIVABLES FACILITY
In July 2002, we entered into a receivables facility arrangement with a
financial institution to sell an undivided interest in our accounts receivable
and accrued unbilled revenues from residential and small commercial retail
electric customers under which, on an ongoing basis, the financial institution
could invest a maximum of $250 million for its interest in such receivables. In
November 2002, the maximum amount of the receivables facility was reduced to
$200 million. In February 2003, this was further reduced to $125 million (see
below). This receivables facility expires July 2003 and may be renewed at our
option and the option of the financial institution participating in the
facility. If the receivables facility is not renewed on its termination date,
the collections from the receivables purchased will repay the financial
institution's investment and no new receivables will be purchased under the
receivables facility. There can be no assurance that the financial institution
participating in the receivables facility will agree to a renewal. The
receivables facility may be increased to an amount greater than $200 million on
a seasonal basis, subject to the availability of receivables and approval by
the participating financial institution.
We received net proceeds in an initial amount of $230 million at the
inception of this receivables facility. The amount of funding available to us
under the receivables facility will fluctuate based on the amount of
receivables available, which in turn, is effected by seasonal changes in demand
for electricity and by the performance of the receivables portfolio. As of
December 31, 2002, the amount of funding outstanding under our receivables
facility was $95 million.
Pursuant to the receivables facility, we formed a qualified special purpose
entity (QSPE), as a bankruptcy remote subsidiary. The QSPE was formed for the
sole purpose of buying and selling receivables generated by us. The QSPE is a
separate entity and its assets will be available first and foremost to satisfy
the claims of its creditors. We, irrevocably and without recourse, transfer
receivables to the QSPE. We continue to service the receivables and receive a
fee of 0.5% of cash collected. We received total fees of $8 million for the
year ended December 31, 2002. We have no servicing assets or liabilities,
because servicing fees are based on actual costs associated with collection of
accounts receivable. The QSPE, in turn, sells an undivided interest in these
receivables to the participating financial institution. We are not ultimately
liable for any failure of payment of the obligors on the receivables. We have,
however, guaranteed the performance obligations of the sellers and the
servicing of the receivables under the related documents.
The two-step transaction described in the above paragraph is accounted for
as a sale of receivables under the provisions of SFAS No. 140 "Accounting for
Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities," and as a result the related receivables are excluded from the
consolidated balance sheet. Cost associated with the sale of receivables, $10
million for the year ended December 31, 2002, primarily the discount and loss
on sale, is included in other expense in our statement of consolidated
operations. As of December 31, 2002, $277 million of the outstanding
receivables had been sold and the sales have been reflected as a reduction
F-87
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
of accounts receivable in our consolidated balance sheet. We have a note
receivable from the QSPE of approximately $170 million at December 31, 2002,
which is included in the consolidated balance sheet. This note is calculated as
the amount of receivables sold to the QSPE, less the interest in the
receivables sold by the QSPE to the financial institution, and the equity
investment in the QSPE, which is equal to 3% of the receivables balance. At
December 31, 2002, the equity investment balance was $8 million.
The book value of the accounts receivable is offset by the amount of the
allowance for doubtful accounts and customer security deposits. A discount rate
of 5.40% was applied to projected cash collections over a 6-month period. Our
collection experience indicated that 98% of the accounts receivables would be
collected within a 6-month period.
On December 2, 2002, we notified the financial institution under the
receivables facility of two violations of certain compliance ratio tests that
are considered amortization events whereby the financial institution has the
right to liquidate the receivables it owns to collect the total amount
outstanding under the terms of the receivables facility. On February 7, 2003,
we were granted an amendment to our receivables facility and a waiver of these
two compliance ratio violations from the financial institution. As part of the
amendment and waiver, the size of the receivables facility was reduced from
$200 million to $125 million.
In addition, an amortization event was added that requires us to attain by
February 17, 2003 either: (a) a consensual refinancing of certain credit
facilities or (b) another financing commitment. We received waivers of this
amortization event until March 31, 2003, at which time we refinanced certain
credit facilities, see note 21(a).
(16) RELIANT ENERGY COMMUNICATIONS
During the third quarter of 2001, management decided to exit our
communications business that 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, we
determined the goodwill associated with the communications business was
impaired. We 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, we 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 our net trading and marketing
liabilities to Enron of $55 million.
The non-trading derivatives with Enron were designated as cash flow hedges
(see note 7). The unrealized 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. During
2002, $52 million was reclassified into earnings related to these cash flow
hedges.
In early 2002, we commenced an action in the United States District Court to
recover from Enron Canada Corp., the only Enron party to our netting agreement
which is not in bankruptcy, the settlement amount of $78
F-88
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
million, which resulted from netting amounts owed by and among the five Enron
parties and our applicable subsidiaries. In March 2002, the United States
District Court dismissed our claim and we appealed the decision to the United
States Court of Appeals for the Fifth Circuit (the Fifth Circuit). Oral
arguments were heard in March 2003.
At this time we cannot predict whether our appeal will be successful. The
United States District Court, however, did determine that netting of amounts
owed by and among our parties and the Enron parties was proper. This portion of
the United States District Court's ruling has not been appealed. In other
proceedings initiated by Enron in the Bankruptcy Court for the Southern
District of New York, Enron is alleging that netting agreements, such as the
one it signed with us, are unenforceable. This contention is not currently at
issue in our appeal pending in the Fifth Circuit. We cannot currently predict
whether Enron will contest the enforceability of its netting agreement with us,
nor the outcome of such dispute. In January 2003, Enron filed a complaint in
the Bankruptcy Court of Southern District New York claiming that it is owed $13
million from us and disputing the enforceability of our netting agreement. Our
answer to the filed complaint is due in April 2003. We believe our netting
agreement with the Enron entities is enforceable as found by the United States
District Court, and will continue to defend such opinion.
(18) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS
The fair values of financial instruments, including cash and cash
equivalents, certain short-term and long-term borrowings (excluding any
fixed-rate debt and other borrowings as discussed below), trading and marketing
assets and liabilities (see note 7), and non-trading derivative assets and
liabilities (see note 7), are equivalent to their carrying amounts in the
consolidated balance sheets. The fair values of trading and marketing assets
and liabilities and non-trading derivative assets and liabilities as of
December 31, 2001 and 2002 have been determined using quoted market prices for
the same or similar instruments when available or other estimation techniques,
see note 7.
As of December 31, 2001, the carrying value of our fixed-rate debt of $121
million equaled the market value. The carrying value and related market value
of our fixed-rate debt, excluding Liberty's fixed-rate debt of $165 million,
was $637 million and $448 million, respectively, as of December 31, 2002. The
market value of our fixed-rate debt is based on our incremental borrowing rates
for similar types of borrowing arrangements. There was no active market for the
fixed-rate Liberty debt of $165 million as of December 31, 2002. Due to our
current situation with Liberty (see note 14(l)), if the holder of our
fixed-rate debt of $165 million were to have tried to sell such debt instrument
to a third party, the price which could have been realized could be
substantially less than the face value of the debt instrument and substantially
less than our carrying value as of December 31, 2002.
As of December 31, 2002, we have floating-rate debt with a carrying value of
$6.7 billion. There was no active market for our floating-rate debt obligations
as of December 31, 2002. Given our current liquidity and credit situation as of
December 31, 2002, if the holders of these borrowings were to have tried to
sell such debt instruments to third parties, the prices which could have been
realized could be substantially less than the face values of the debt
instruments and substantially less than our carrying values.
(19) RESTATED UNAUDITED QUARTERLY INFORMATION
Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis in the statements of
consolidated operations. For information regarding the presentation
F-89
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
of trading and marketing activities on a net basis, see notes 2(t) and 7. The
effect of the change to reporting on a net basis on previously reported
quarterly information is discussed in note 1 to the table below. Accordingly,
the unaudited quarterly information for the interim periods for 2001 and the
interim periods ended March 31, 2002 and June 30, 2002 have been reclassified
to conform to this presentation. During the third quarter of 2002, we completed
the transitional impairment test for the adoption of SFAS No. 142 on our
consolidated financial statements, including the review of goodwill for
impairment as of January 1, 2002 (see note 6). Based on this impairment test,
we recorded an impairment of our European energy segment's goodwill of $234
million, net of tax. This impairment loss was recorded retroactively as a
cumulative effect of a change in accounting principle for the quarter ended
March 31, 2002.
In addition, as discussed in note 1, the consolidated financial statements
for 2001 have been restated from amounts previously reported and we
miscalculated the amount of hedge ineffectiveness for the first three quarters
of 2002 for hedging instruments entered into prior to the adoption SFAS No.
133. In addition, we did not record the amount of ineffectiveness for any
hedging instruments during the first three quarters of 2001. As a result, the
unaudited quarterly information for each of the quarters in 2001 and the first
three quarters of 2002 have been restated from amounts previously reported. The
restatement had no impact on previously reported consolidated operating,
investing and financing cash flows for 2001 or 2002. The following is a summary
of the principal effects of the restatement for unaudited quarterly information
for the quarters ended March 31, 2001 and 2002, June 30, 2001 and 2002,
September 30, 2001 and 2002, and December 31, 2001: (Note--Those line items for
which no change in amounts are shown were not affected by the restatement.)
Year Ended December 31, 2001
-----------------------------------------
First Quarter Second Quarter
-------------------- --------------------
As As
As Previously As Previously
Restated Reported(1) Restated Reported(1)
-------- ----------- -------- -----------
(in millions)
Revenues...................................................... $1,393 $1,410 $1,526 $1,545
Trading margins............................................... 119 119 131 131
------ ------ ------ ------
Total revenues............................................. 1,512 1,529 1,657 1,676
Operating income.............................................. 97 114 275 294
Income before income taxes and cumulative effect of accounting
change...................................................... 93 110 329 348
Income tax expense............................................ 25 31 113 120
Income before cumulative effect of accounting change.......... 68 79 216 228
Net income.................................................... 71 82 216 228
Basic Earnings Per Share:
Income before cumulative effect of accounting change....... $ 0.28 $ 0.33 $ 0.78 $ 0.83
Cumulative effect of accounting change, net of tax......... 0.01 0.01 -- --
------ ------ ------ ------
Net income............................................. $ 0.29 $ 0.34 $ 0.78 $ 0.83
====== ====== ====== ======
Diluted Earnings Per Share:
Income before cumulative effect of accounting change....... $ 0.28 $ 0.33 $ 0.78 $ 0.82
Cumulative effect of accounting change, net of tax......... 0.01 0.01 -- --
------ ------ ------ ------
Net income............................................. $ 0.29 $ 0.34 $ 0.78 $ 0.82
====== ====== ====== ======
F-90
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Year Ended December 31, 2001
----------------------------------------
Third Quarter Fourth Quarter
-------------------- -------------------
As As
As Previously As Previously
Restated Reported(1) Restated Reported(1)
-------- ----------- -------- -----------
(in millions)
Revenues.................................................. $2,473 $2,400 $ 738 $ 767
Trading margins........................................... 62 62 57 57
------ ------ ----- -----
Total revenues......................................... 2,535 2,462 795 824
Operating income (loss)................................... 425 352 (27) 2
Income (loss) before income taxes and cumulative effect of
accounting change....................................... 437 364 (25) 4
Income tax expense (benefit).............................. 175 150 (39) (29)
Income before cumulative effect of accounting change...... 262 214 14 33
Net income................................................ 262 214 14 33
Basic Earnings Per Share:
Income before cumulative effect of accounting change... $ 0.87 $ 0.71 $0.05 $0.11
Cumulative effect of accounting change, net of tax..... -- -- -- --
------ ------ ----- -----
Net income......................................... $ 0.87 $ 0.71 $0.05 $0.11
====== ====== ===== =====
Diluted Earnings Per Share:
Income before cumulative effect of accounting change... $ 0.87 $ 0.71 $0.05 $0.11
Cumulative effect of accounting change, net of tax..... -- -- -- --
------ ------ ----- -----
Net income......................................... $ 0.87 $ 0.71 $0.05 $0.11
====== ====== ===== =====
Year Ended December 31, 2002
-----------------------------------------
First Quarter Second Quarter
------------------- --------------------
As As
As Previously As Previously
Restated Reported(1) Restated Reported(1)
-------- ----------- -------- -----------
(in millions)
Revenues...................................................... $1,754 $1,755 $2,226 $2,230
Trading margins............................................... 53 53 119 119
------ ------ ------ ------
Total revenues............................................. 1,807 1,808 2,345 2,349
General, administrative and development....................... 113 113 167 167
Operating income.............................................. 165 166 329 333
Income before income taxes and cumulative effect of accounting
change...................................................... 138 139 279 283
Income tax expense............................................ 42 42 104 105
Income before cumulative effect of accounting change.......... 96 97 175 178
Net (loss) income............................................. (138) (137) 175 178
Basic Earnings (Loss) Per Share:
Income before cumulative effect of accounting change....... $ 0.33 $ 0.34 $ 0.61 $ 0.62
Cumulative effect of accounting change, net of tax......... (0.81) (0.81) -- --
------ ------ ------ ------
Net (loss) income...................................... $(0.48) $(0.47) $ 0.61 $ 0.62
====== ====== ====== ======
Diluted Earnings (Loss) Per Share:
Income before cumulative effect of accounting change....... $ 0.33 $ 0.34 $ 0.60 $ 0.61
Cumulative effect of accounting change, net of tax......... (0.81) (0.81) -- --
------ ------ ------ ------
Net (loss) income...................................... $(0.48) $(0.47) $ 0.60 $ 0.61
====== ====== ====== ======
F-91
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Year Ended December 31, 2002
--------------------------
Third Quarter
-------------------
As
As Previously Fourth
Restated Reported Quarter
-------- ---------- -------
Revenues.................................................................... $5,225 $5,236 $2,043
Trading margins............................................................. 119 119 19
------ ------ ------
Total revenues........................................................... 5,344 5,355 2,062
General, administrative and development..................................... 224 224 161
Operating income (loss)..................................................... 271 282 (645)
Income (loss) before income taxes and cumulative effect of accounting change 189 200 (718)
Income tax expense (benefit)................................................ 138 142 (70)
Income (loss) before cumulative effect of accounting change................. 51 58 (648)
Net income (loss)........................................................... 51 58 (648)
Basic Earnings (Loss) Per Share:
Income (loss) before cumulative effect of accounting change.............. $ 0.17 $ 0.20 $(2.23)
Cumulative effect of accounting change, net of tax....................... -- -- --
------ ------ ------
Net income (loss).................................................... $ 0.17 $ 0.20 $(2.23)
====== ====== ======
Diluted Earnings (Loss) Per Share:
Income (loss) before cumulative effect of accounting change.............. $ 0.17 $ 0.20 $(2.23)
Cumulative effect of accounting change, net of tax....................... -- -- --
------ ------ ------
Net income (loss).................................................... $ 0.17 $ 0.20 $(2.23)
====== ====== ======
- --------
(1) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis as allowed by EITF
No. 98-10. Comparative financial statements for prior periods have been
reclassified to conform to this presentation. For information regarding the
presentation of trading and marketing activities on a net basis, see Note
2(t). Revenues, fuel and cost of gas sold expense and purchased power
expense have been reclassified to conform to this presentation.
Accordingly, the unaudited quarterly information for each of the interim
periods for 2001 and the interim periods ended March 31, 2002 and June 30,
2002 has been reclassified to conform to this presentation. The effect on
revenues was a net reduction of $7.1 billion, $6.2 billion, $6.3 billion
and $5.0 billion for the interim periods ended March 31, 2001, June 30,
2001, September 30, 2001 and December 31, 2001, respectively. The effect on
revenues was a net reduction of $5.2 billion and $6.2 billion for the
interim periods ended March 31, 2002 and June 30, 2002, respectively.
The quarterly operating results incorporate the results of operations of
Orion Power from our February 2002 acquisition date as discussed in note 5(a).
The variances in revenues from quarter to quarter for 2001 and 2002 were
primarily due to (a) the Orion Power acquisition (for 2002 only), (b) the
seasonal fluctuations in demand for electric energy and energy services, (c)
changes in energy commodity prices and (d) hedge ineffectiveness related to
certain long-term forward contracts for the sale of power in the California
market through December 2006 (for 2001 only). Changes in operating income
(loss) and net income (loss) from quarter to quarter for 2001 and 2002 were
primarily due to:
. the seasonal fluctuations in demand for electric energy and energy
services;
. changes in energy commodity prices;
. the timing of maintenance expenses on electric generation plants; and
. provisions related to energy sales and refunds in California.
In addition, operating income and net income changed from quarter to quarter
in 2001 by:
F-92
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
. a $100 million pre-tax, non-cash charge in the first quarter of 2001
relating to the redesign of some of CenterPoint's benefits plans in
anticipation of our separation;
. write-offs recorded in the fourth quarter of 2001 related to Enron of $85
million;
. $54 million pre-tax charges in 2001 related to exiting the communications
business;
. hedge ineffectiveness related to certain long-term forward contracts for
the sale of power in the California market through December 2006;
. a $51 million pre-tax gain in the second quarter of 2001 related to the
valuation of our interest in NEA; and
. a $37 million gain on the stranded cost indemnification settlement in the
fourth quarter of 2001.
Also, operating income (loss) and net income (loss) changed from quarter to
quarter in 2002 by:
. the impact of the Orion Power acquisition;
. a $128 million accrual recorded in the third and fourth quarters of 2002
for a payment to CenterPoint;
. a one-time $109 million pre-tax gain resulting from the amendment of our
stranded cost electricity supply contracts in the second quarter of 2002;
. a $47 million pre-tax, non-cash charge in the third quarter of 2002
relating to the accounting settlement of certain benefit obligations
associated with our separation from CenterPoint;
. impairment charges of $32 million pre-tax relating to certain cost method
investments ($27 million pre-tax in the fourth quarter) in 2002;
. change in refund reserves, credit provisions and interest income (all
net) of gain (loss) recognized of $33 million, $(29) million, $(15)
million and $(98) million (all pre-tax) in the first, second, third and
fourth quarters, respectively, during 2002 related to energy sales in the
California wholesale market in 2000 and 2001 (see note 14(i));
. costs related to plant cancellations and equipment impairments in the
second and third quarters of 2002;
. a $45 million tax accrual on future distributions from NEA in the third
quarter of 2002 (only impacted net loss);
. a cumulative effect of an accounting change of $234 million, net of tax,
in the first quarter of 2002 (only impacted net loss); and
. a $482 million goodwill impairment of our European energy segment in the
fourth quarter of 2002.
(20) REPORTABLE SEGMENTS
We have identified the following reportable segments: retail energy,
wholesale energy, European energy and other operations. For descriptions of the
financial reporting segments, see note 1. In February 2003, we signed a share
purchase agreement to sell our European energy operations. See note 21(b) for
further discussion. Our determination of reportable segments considers the
strategic operating units under which we manage sales, allocate resources and
assess performance of various products and services to wholesale or retail
customers.
F-93
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
Financial information for Orion Power and REMA are included in the segment
disclosures only for periods beginning on their respective acquisition dates.
Beginning in the first quarter of 2002, we began to evaluate segment
performance on earnings (loss) before interest expense, interest income and
income taxes (EBIT). Prior to 2002, we evaluated performance on operating
income. EBIT is not defined under accounting principles generally accepted in
the United States of America (GAAP), and should not be considered in isolation
or as a substitute for a measure of performance prepared in accordance with
GAAP and is not indicative of operating income (loss) from operations as
determined under GAAP. There were no material intersegment revenues during
2000, 2001 and 2002.
Long-lived assets include net property, plant and equipment, net goodwill,
net other intangibles and equity investments in unconsolidated subsidiaries.
Financial data for business segments, products and services and geographic
areas are as follows:
Retail Wholesale European Other
Energy Energy Energy Operations Eliminations Consolidated
------ --------- -------- ---------- ------------ ------------
(in millions)
As of and for the year ended December 31, 2000:
Revenues from external customers............ $ 64 $ 2,661 $ 544 $ 6 $ -- $ 3,275
Trading margins............................. -- 198 2 -- -- 200
Depreciation and amortization............... 4 108 76 6 -- 194
Operating (loss) income..................... (70) 505 84 (61) -- 458
EBIT........................................ (70) 572 89 (83) -- 508
Total assets................................ 131 10,766 2,473 105 -- 13,475
Equity investments in unconsolidated
subsidiaries.............................. -- 109 -- -- -- 109
Expenditures for long-lived assets.......... 22 1,966 995 59 -- 3,042
As of and for the year ended December 31, 2001:
Revenues from external customers............ 114 5,382 623 11 -- 6,130
Trading margins............................. 74 304 (9) -- -- 369
Depreciation and amortization............... 11 118 76 42 -- 247
Operating (loss) income..................... (13) 907 56 (180) -- 770
EBIT........................................ (13) 916 113 (158) -- 858
Total assets................................ 391 7,671 3,380 645 (368) 11,719
Equity investments in unconsolidated
subsidiaries.............................. -- 88 299 -- -- 387
Expenditures for long-lived assets.......... 117 658 21 44 -- 840
As of and for the year ended December 31, 2002:
Revenues from external customers............ 4,201 6,433 611 3 -- 11,248
Trading margins............................. 152 137 21 -- -- 310
European energy goodwill impairment......... -- -- 482 -- -- 482
Depreciation and amortization............... 26 337 58 15 -- 436
Operating income (loss)..................... 524 24 (371) (57) -- 120
EBIT........................................ 520 68 (356) (80) -- 152
Total assets................................ 1,517 12,803 2,811 916 (410) 17,637
Equity investments in unconsolidated
subsidiaries.............................. -- 103 210 -- -- 313
Expenditures for long-lived assets.......... 33 3,495 19 77 -- 3,624
F-94
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
As of and for the Year Ended
December 31,
---------------------------
2000 2001 2002
------ ------ -------
(in millions)
Reconciliation of Operating Income to EBIT and EBIT to Net Income (Loss):
Operating income...................................................... $ 458 $ 770 $ 120
(Losses) gains from investments, net.................................. (17) 22 (24)
Income of equity investment of unconsolidated subsidiaries............ 43 57 23
Other income, net..................................................... 24 9 33
------ ------ -------
EBIT.................................................................. 508 858 152
Interest expense...................................................... (42) (63) (304)
Interest income....................................................... 18 27 35
Interest (expense) income--affiliated companies, net.................. (173) 12 5
------ ------ -------
Income (loss) before income taxes and cumulative effect of accounting
change.............................................................. 311 834 (112)
Income tax expense.................................................... (95) (274) (214)
Cumulative effect of accounting change, net of tax.................... -- 3 (234)
Extraordinary item, net of tax........................................ 7 -- --
------ ------ -------
Net income (loss)................................................. $ 223 $ 563 $ (560)
====== ====== =======
Revenues by Products and Services:
Retail energy products and services................................... $ 64 $ 114 $ 4,201
Wholesale energy and energy related sales............................. 3,205 6,005 7,044
Energy trading margins................................................ 200 369 310
Other................................................................. 6 11 3
------ ------ -------
Total............................................................. $3,475 $6,499 $11,558
====== ====== =======
Revenues and Long-Lived Assets by Geographic Areas:
Revenues:
United States(1).................................................... $2,911 $5,908 $10,921
Netherlands(2)...................................................... 546 614 632
Canada(3)........................................................... 18 (23) 5
------ ------ -------
Total............................................................. $3,475 $6,499 $11,558
====== ====== =======
Long-lived assets:
United States....................................................... $3,078 $3,728 $ 9,674
Netherlands......................................................... 2,371 2,424 1,857
------ ------ -------
Total............................................................. $5,449 $6,152 $11,531
====== ====== =======
- --------
(1) For 2000, 2001 and 2002, revenues include trading margins of $180 million,
$401 million and $284 million, respectively.
(2) For 2000, 2001 and 2002, revenues include trading margins of $2 million,
($9) million and $21 million, respectively.
(3) For 2000, 2001 and 2002, revenues include trading margins of $18 million,
($23) million and $5 million, respectively.
F-95
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(21) SUBSEQUENT EVENTS
(a) Domestic Refinancings.
During March 2003, we refinanced our (a) $1.6 billion senior revolving
credit facilities (see note 9(a)), (b) $2.9 billion 364-day Orion acquisition
term loan (see note 9(a)), and (c) $1.425 billion construction agency financing
commitment (see note 14(b)), and we obtained a new $300 million senior priority
revolving credit facility. The refinancing combined the existing credit
facilities into a $2.1 billion senior secured revolving credit facility, a $921
million senior secured term loan, and a $2.91 billion senior secured term loan.
The refinanced credit facilities mature in March 2007. The $300 million senior
priority revolving credit facility matures on the earlier of our acquisition of
Texas Genco or December 15, 2004. The $300 million senior priority revolving
credit facility is secured with a first lien on substantially all of our
contractually and legally available assets. The other facilities totaling $5.93
billion are secured with a second lien on such assets. Our subsidiaries
guarantee both the refinanced credit facilities and the senior priority
revolving credit facility to the extent contractually and legally permitted.
In connection with the refinancing, we were required to make a prepayment of
$350 million under the senior revolving credit facility. This prepayment was
made from cash on hand and is available to be reborrowed under the senior
revolving credit facility. We must use the proceeds of any loans under the
senior priority revolving credit facility solely to secure or prepay our
ongoing commercial and trading obligations and not for other general corporate
or working capital purposes. We must use the proceeds of any loans under the
other senior revolving credit facility solely for working capital and other
general corporate purposes. We are not permitted to use the proceeds from loans
under any of these facilities to acquire Texas Genco.
The loans under the refinanced credit facilities bear interest at LIBOR plus
4.0% or a base rate plus 3.0% and the loans under the senior priority revolving
credit facility bear interest at LIBOR plus 5.5% or a base rate plus 4.5%. If
the refinanced credit facilities are not permanently reduced by $500 million,
$1.0 billion and $2.0 billion (cumulatively) by May 2004, 2005 and 2006,
respectively, we must pay a fee ranging from 0.50% to 1.0% of the amount of the
refinanced credit facilities still outstanding on each such date. Additionally,
we are required to make principal prepayments on the refinanced facilities (a)
of $500 million by no later than May 2006 and (b) with proceeds from certain
asset sales and issuances of securities and with certain cash flows in excess
of a threshold amount. Both the refinanced credit facilities and the new senior
priority revolving credit facility are evidenced by the same credit agreement,
which contains numerous financial, affirmative, and negative covenants.
Financial covenants include maintaining a debt to earnings before interest,
taxes, depreciation, amortization and rent (EBITDAR) ratio of a certain maximum
amount and a EBITDAR to interest ratio of a certain minimum amount. Our March
2003 credit facilities restrict our ability to take specific actions, subject
to numerous exceptions that are designed to allow for the execution of our
business plans in the ordinary course, including the completion of all four of
the power plants currently under construction, the preservation and
optimization of all of our existing investments in the retail energy and
wholesale energy businesses, the ability to provide credit support for our
commercial obligations and the possible exercise of the option to acquire a
majority interest in Texas Genco, and the financings related thereto. Such
restrictions include our ability to (a) encumber our assets, (b) enter into
business combinations or divest our assets, (c) incur additional debt or engage
in sale and leaseback transactions, (d) pay dividends or prepay other debt, (e)
make investments or acquisitions, (f) enter into transactions with affiliates,
(g) make capital expenditures, (h) materially change our business, (i) amend
our debt and other material agreements, (j) issue, sell or repurchase our
capital stock, (k) allow distributions from our subsidiaries and (l) engage in
certain types of trading activities. These covenants are not anticipated to
materially restrict our ability to borrow funds or obtain letters of credit
under the refinanced credit facilities or the senior priority credit facility.
We must be in compliance with each of the covenants before we can
F-96
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
borrow under the revolving credit facilities. Our failure to comply with these
covenants could result in an event of default that, if not cured or waived,
could result in us being required to repay these borrowings before their due
date.
In connection with our March 2003 refinancing, we issued to the lenders
warrants to acquire shares of our common stock that would represent 6.5% of our
outstanding shares effective as of March 28, 2003 on a fully-diluted basis
(after giving effect to such warrants). The exercise prices of the warrants are
based on average market prices of our common stock during specified periods in
proximity to the refinancing date. Of this 6.5%, warrants equal to 2.5% vested
in March 2003, 2% will vest if the refinanced credit facilities have not been
reduced by an aggregate of $1.0 billion by May 2005 and the remaining 2% will
vest if the refinanced credit facilities have not been reduced by an aggregate
of $2.0 billion by May 2006. The warrants are exercisable for a period of five
years from the date they become vested.
We incurred approximately $150 million in financing costs (which excludes
$15 million to be paid at maturity) and expensed approximately $33 million (of
which $11 million was expensed in 2002 and $22 million was expensed in 2003) in
fees and other costs related to our refinancing efforts.
(b) Sale of Our European Energy Operations.
In February 2003, we signed a share purchase agreement to sell our European
energy operations to N.V. Nuon (Nuon), a Netherlands-based electricity
distributor. Upon consummation of the sale, we expect to receive cash proceeds
from the sale of approximately $1.2 billion (Euro 1.1 billion). The sales price
is denominated in Euros; however, we have hedged our foreign currency exposure
of our net investment in our European energy operations. See below for further
discussion of the hedges. As additional consideration for the sale, we will
also receive 90% of the dividends and other distributions in excess of
approximately $115 million (Euro 110 million) paid by NEA to REPGB following
the consummation of the sale. The purchase price payable at closing assumes
that our European energy operations will have, on the sale consummation date,
net cash of at least $121 million (Euro 115 million). If the amount of net cash
is less on such date, the purchase price will be reduced accordingly.
We intend to use the cash proceeds from the sale first to prepay the Euro
600 million bank term loan borrowed by Reliant Energy Capital (Europe), Inc. to
finance a portion of the acquisition costs of our European energy operations.
The maturity date of the credit facility, which originally was scheduled to
mature in March 2003, has been extended (see notes 9(a) and 21(c)). We intend
to use the remaining cash proceeds of approximately $0.5 billion (Euro 0.5
billion) to partially fund our option to acquire Texas Genco in 2004 (see note
4(b)). However, if we do not exercise the option, we will use the remaining
cash proceeds to prepay debt.
The sale is subject to the approval of the Dutch and German competition
authorities. We anticipate that the consummation of the sale will occur in the
summer of 2003. No assurance can be given that we will obtain the approval of
the Dutch and German competition authorities or that such approvals can be
obtained in a timely manner.
As of December 31, 2002, our European energy operations had current assets
of $650 million, net property, plant and equipment of $1.6 billion, other
long-term assets of $429 million, $1.1 billion of current liabilities
(including debt of $631 million), long-term debt of $37 million and other
long-term liabilities of $676 million. These amounts exclude net intercompany
receivables and payables that will not be purchased by Nuon. We recognized a
loss of approximately $0.4 billion in the first quarter of 2003 in connection
with the anticipated sale. We do not anticipate that there will be a Dutch or
United States income tax benefit realized by us as a result of
F-97
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
this loss. We will recognize contingent payments, if any, in earnings upon
receipt. In the first quarter of 2003, we began to report the results of our
European energy operations as discontinued operations in accordance with SFAS
No. 144. For information regarding goodwill impairments of our European energy
segment recognized in the first and fourth quarters of 2002 of $234 million and
$482 million, respectively, see note 6.
In March 2003, we adjusted the hedge of our net investment in our European
energy operations to Euro 1.5 billion by selling foreign currency options of
Euro 400 million and purchasing Euro 520 million of foreign currency options
which expire in June 2003.
(c) Extension of Euro 600 Million Bank Term Loan Facility.
In March 2003, we reached an agreement with our lenders to extend the
maturity date of the Euro 600 million bank term loan facility of Reliant Energy
Capital (Europe), Inc., originally scheduled to mature on March 3, 2003. Based
on the terms of the extension, we will repay this term loan on the first to
occur of (a) completion of the above mentioned sale of our European energy
operations to Nuon, (b) December 31, 2003 and (c) the earlier of the maturity
dates of the two REPGB facilities, which are both July 2003, as they may be
extended. If the sale of our European energy operations does not occur prior to
July 2003, we will be required to repay this term loan in July 2003 unless
prior to that date we are able to obtain an extension of REPGB's credit
facilities. If the sale of our European energy operations does not close prior
to the maturity of these facilities, REPGB anticipates extending these credit
facilities.
In order to extend the Euro 600 million facility, we provided the following
additional security to the lenders:
. a guarantee of the facility from Reliant Energy (Europe), Inc.;
. security over certain intercompany payables from our European energy
operations (a portion of which will be repaid at consummation of the
sale) and the bank accounts into which Nuon will deposit the cash
proceeds of the sale; and
. a pledge of 65% of the shares in Reliant Energy Europe B.V., the holding
company of our European energy operations, which pledge will be released
upon the consummation of the sale.
In addition, we agreed to increase the interest rate under this credit
facility to EURIBOR plus a margin of 4.0% per year, 2.0% of which is payable
monthly and 2.0% of which will be paid in the event that the sale of our
European energy operations to Nuon does not occur. We pre-funded interest under
the facility through a security account, initially in an amount of
approximately $18 million (Euro 17 million) and, thereafter, we will replenish
this account in an amount equal to at least two months' interest service
coverage under the facility.
(d) Price to Beat Fuel Factor Adjustment.
In March 2003, the PUCT approved our request to increase the price to beat
fuel factor for residential and small commercial customers based on a 23.4%
increase in the price of natural gas from our previous increase in December
2002. The approved increase was based on a 10 trading-day, average forward
12-month natural gas price of $4.956 per MMbtu (one million British thermal
units). The increase represents an 8.2% increase in the total bill of a
residential customer using an average 12,000 kilowatt hours per year. For
additional information regarding the current price to beat fuel factor, see
note 14(f).
F-98
RELIANT RESOURCES, INC. AND SUBSIDIARIES
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS--(Continued)
For the Three Years Ended December 31, 2000, 2001 and 2002
(e) Interest Rate Caps
During January 2003, we purchased three-month LIBOR interest rate caps to
hedge our future floating rate risk associated with various credit facilities.
We have hedged $4.0 billion for the period from July 1 to December 31, 2003,
$3.0 billion for 2004 and $1.5 billion for 2005. The LIBOR interest rates are
capped at a weighted average rate of 2.06% for the period from July 1 to
December 31, 2003, 3.18% for 2004 and 4.35% for 2005. These interest rate caps
qualify for hedge accounting under SFAS No. 133 with any changes in fair market
value recorded to other comprehensive income (loss).
(f) Cash Collateralized Letter of Credit Facility.
In January 2003, we entered into a $200 million cash-secured, revolving
letter of credit facility with a financial institution. Outstanding letters of
credit are required to be 103% cash collateralized. Under the facility, letters
of credit may be issued until January 29, 2004 and may remain outstanding until
January 29, 2005. The facility is not cross-defaulted to any other facility.
The facility agreement contains certain limited affirmative and negative
covenants, but no financial covenants. This letter of credit facility is
subject to monthly letter of credit and unused lines fees that are calculated
on the outstanding letters of credit and the unused commitment, respectively.
* * *
F-99
RELIANT RESOURCES, INC. AND SUBSIDIARIES
SCHEDULE II--RESERVES
For the Three Years Ended December 31, 2002
(Thousands of Dollars)
Column A Column B Column C Column D Column E
-------- ---------- -------------------- ----------- ---------
Additions
--------------------
Balance at Charged to Deductions Balance
Beginning Charged Other from at End of
Description of Period to Income Accounts(1) Reserves(2) Period
----------- ---------- --------- ----------- ----------- ---------
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
Reserves 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, 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
Reserves 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, 2002:
Accumulated provisions:
Uncollectible accounts receivable........ 89,708 21,190 2,797 (44,596) 69,099
Reserves deducted from trading and
marketing assets....................... 97,849 (34,938) -- (17,437) 45,474
Reserves for accrue-in-advance major
maintenance............................ 19,376 14,211 2,841 (12,126) 24,302
Reserves for inventory................... 455 3,177 208 (148) 3,692
Reserves for severance................... 19,651 30,621 2,832 (29,617) 23,487
Deferred tax assets valuation............ 15,632 25,984 29,714 -- 71,330
- --------
(1) Charged to other accounts represents obligations acquired through business
acquisitions and effects of foreign currency exchange rate changes.
(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.
* * *
III-1
INDEPENDENT AUDITORS' REPORT
To the Members of El Dorado Energy, LLC
We have audited the accompanying balance sheets of El Dorado Energy, LLC
(the "Company") as of December 31, 2002 and 2001, and the related statements of
operations, members' equity and comprehensive income (loss), and cash flows for
each of the three years in the period ended December 31, 2002. These financial
statements 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 financial statements present fairly, in all material
respects, the financial position of the Company at December 31, 2002 and 2001,
and the results of its operations and its cash flows for each of the three
years in the period ended December 31, 2002, in conformity with accounting
principles generally accepted in the United States of America.
As discussed in Note 8 to the financial statements, the Company changed its
method of accounting for derivative instruments and hedging activities in 2001.
DELOITTE & TOUCHE LLP
Houston, Texas
March 31, 2003
III-2
EL DORADO ENERGY, LLC
STATEMENTS OF OPERATIONS
(Thousands of Dollars)
Year Ended December 31,
----------------------------
2002 2001 2000
-------- -------- --------
Revenues................................. $100,680 $132,574 $260,460
Expenses:
Fuel.................................. 79,918 110,623 129,059
Purchased power....................... 1,320 (280) 4,743
Operations and maintenance............ 12,706 17,028 6,500
Taxes other than income and insurance. 2,244 1,344 1,214
Depreciation.......................... 8,415 8,415 4,932
-------- -------- --------
Total Expenses.................... 104,603 137,130 146,448
Operating Income (Loss).................. (3,923) (4,556) 114,012
-------- -------- --------
Other Income............................. 43,719 246 --
-------- -------- --------
Income (Loss) Before Interest Expense.... 39,796 (4,310) 114,012
Interest Expense, Net.................... (8,965) (7,725) (6,461)
-------- -------- --------
Net Income (Loss)........................ $ 30,831 $(12,035) $107,551
======== ======== ========
See Notes to the Financial Statements
III-3
EL DORADO ENERGY, LLC
BALANCE SHEETS
(Thousands of Dollars)
December 31,
------------------
2002 2001
-------- --------
ASSETS
Current Assets:
Cash and cash equivalents........................... $ 34,305 $ 17,687
Restricted cash..................................... 4,432 --
Current portion of debt service reserve fund........ 7,154 --
Accounts receivable................................. 2,192 1,563
Inventories......................................... 1,906 1,832
Prepayments and other current assets................ 842 456
Prepaid long-term maintenance....................... 9,009 --
-------- --------
Total current assets............................ 59,840 21,538
-------- --------
Property, Plant and Equipment, Net..................... 224,035 227,906
Other Assets:
Debt issuance costs, net............................ 4,335 4,675
Debt service reserve fund........................... 7,009 14,415
Non-trading derivative asset........................ -- 184
-------- --------
Total other assets.................................. 11,344 19,274
-------- --------
Total Assets.................................... $295,219 $268,718
======== ========
LIABILITIES AND MEMBERS' EQUITY
Current Liabilities:
Current portion of long-term debt................... $ 6,312 $ 5,918
Accrued liabilities................................. 4,000 2,474
Non-trading derivative liability.................... 4,084 3,160
-------- --------
Total current liabilities....................... 14,396 11,552
-------- --------
Other Liabilities:
Non-trading derivative liability.................... 2,912 --
-------- --------
Total other liabilities......................... 2,912 --
-------- --------
Long-term Debt......................................... 138,864 145,176
Commitments and Contingencies (Note 13)................
Members' Equity:
Common stock........................................ 2 2
Members' capital contributions...................... 125,022 125,022
Retained earnings (deficit)......................... 21,018 (9,813)
Accumulated other comprehensive loss................ (6,995) (3,221)
-------- --------
Total members' equity........................... 139,047 111,990
-------- --------
Total Liabilities and Members' Equity........ $295,219 $268,718
======== ========
See Notes to the Financial Statements
III-4
EL DORADO ENERGY, LLC
STATEMENTS OF CASH FLOWS
(Thousands of Dollars)
Year Ended December 31,
----------------------------
2002 2001 2000
-------- -------- --------
Cash Flows from Operating Activities:
Net income (loss).................................................. $ 30,831 $(12,035) $107,551
Adjustments to reconcile net income (loss) to net cash provided by
operations:
Depreciation..................................................... 8,415 8,415 4,932
Amortization of debt issuance costs.............................. 340 340 85
Net change in non-trading derivative assets and liabilities...... 245 (245) --
Changes in assets and liabilities:
Restricted cash................................................ (4,432) -- --
Accounts receivable............................................ (629) 32,654 (31,902)
Inventories.................................................... (74) (475) (828)
Prepaid long-term maintenance.................................. 1,805 -- --
Other assets................................................... (386) (97) (285)
Other current liabilities...................................... 1,526 335 924
-------- -------- --------
Net cash flows provided by operating activities................ 37,641 28,892 80,477
-------- -------- --------
Cash Flows from Investing Activities:
Capital expenditures............................................... (9,107) (1,954) (6,707)
Performance guarantee settlements.................................. (6,250) (11,900) 19,900
-------- -------- --------
Net cash flows (used in) provided by investing activities.......... (15,357) (13,854) 13,193
-------- -------- --------
Cash Flows from Financing Activities:
Proceeds from long-term debt....................................... -- -- 8,800
Payments of long-term debt......................................... (5,918) (4,339) (2,367)
Changes in debt service reserve.................................... 252 -- (14,415)
Capital contributions.............................................. -- 16,977 6,899
Distributions...................................................... -- (67,056) (35,856)
-------- -------- --------
Net cash flows used in financing activities.................... (5,666) (54,418) (36,939)
-------- -------- --------
Net Change in Cash and Cash Equivalents............................... 16,618 (39,380) 56,731
Cash and Cash Equivalents, Beginning of Year.......................... 17,687 57,067 336
-------- -------- --------
Cash and Cash Equivalents, End of Year................................ $ 34,305 $ 17,687 $ 57,067
======== ======== ========
Supplemental Disclosure of Cash Flow Information:
Cash payments
Interest (net of amounts capitalized).......................... $ 8,561 $ 7,344 $ 6,376
See Notes to the Financial Statements
III-5
EL DORADO ENERGY, LLC
STATEMENTS OF MEMBERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(Thousands of Dollars, except share amounts)
Accumulated
Common Stock Members' Retained Other Total
------------- Capital Earnings Comprehensive Members' Comprehensive
Shares Amount Contributions (Deficit) Loss Equity Income (Loss)
------ ------ ------------- --------- ------------- -------- -------------
Balance December 31, 1999.............. 2,000 $2 $101,146 $ (2,417) $ 98,731
Capital contributions............... 6,899 6,899
Distributions to members............ (35,856) (35,856)
Net income.......................... 107,551 107,551 $107,551
----- -- -------- -------- ------- -------- --------
Comprehensive income................ $107,551
========
Balance December 31, 2000.............. 2,000 $2 $108,045 $ 69,278 $177,325
Capital contributions............... 16,977 16,977
Distributions to members............ (67,056) (67,056)
Net loss............................ (12,035) (12,035) $(12,035)
Other comprehensive loss:
Cumulative effect of adoption of
SFAS No. 133...................... $ 2,115 2,115 2,115
Deferred loss from cash flow
hedge............................. (4,339) (4,339) (4,339)
Reclassification of net deferred
gain from cash flow hedge in
net loss.......................... (997) (997) (997)
----- -- -------- -------- ------- -------- --------
Comprehensive loss.................. $(15,256)
========
Balance December 31, 2001.............. 2,000 $2 $125,022 $ (9,813) $(3,221) $111,990
Net income.......................... 30,831 30,831 $ 30,831
Other comprehensive loss:
Deferred loss from cash flow
hedge............................. (6,933) (6,933) (6,933)
Reclassification of net deferred
loss from cash flow hedge in
net income........................ 3,159 3,159 3,159
----- -- -------- -------- ------- -------- --------
Comprehensive income................ $ 27,057
========
Balance December 31, 2002.............. 2,000 $2 $125,022 $ 21,018 $(6,995) $139,047
===== == ======== ======== ======= ========
See Notes to the Financial Statements
III-6
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS
For the years ended December 31, 2002, 2001, and 2000
1. NATURE OF BUSINESS
El Dorado Energy, LLC (the "Company"), a Delaware limited liability company
formed on February 5, 1997, is jointly owned by Reliant Energy Power
Generation, Inc. ("REPG") and Sempra Energy Power I ("SEP I") (collectively,
the "Members"). REPG is a subsidiary of Reliant Resources, Inc. ("Reliant
Resources"). SEP I is a subsidiary of Sempra Energy, Incorporated ("Sempra").
The Company was formed to develop, construct, and operate a 470 megawatt
gas-fired power generation plant located in Boulder City, Nevada (the
"Project"). The Company is governed by a management committee with equal
representation from each of the Members.
Under the terms of the Company's limited liability agreement, the Company
will continue until the earliest of (a) such time as all of the Company's
assets have been sold or otherwise disposed of, (b) such time the Company's
existence has been terminated or (c) September 2048. The Members are not
personally liable for any amount in excess of their respective capital
contributions, and are not liable for any of the debts and losses of the
Company, except to the extent that a liability of the Company is founded upon
results from an unauthorized act or activity of such Member.
Construction on the Project began in December 1997 and conditions for
Provisional Performance Acceptance ("PPA") were achieved on May 3, 2000. Total
cost of the project was $272 million and was funded through a $157.8 million
credit agreement ("Credit Agreement") (see Note 3), and capital contributions
received from the Members.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Reclassifications.
Some amounts from the previous years have been reclassified to conform to
the 2002 presentation of financial statements. These reclassifications do not
affect earnings.
Use of Estimates.
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, and 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
these estimates.
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
Note 8. The Company is also subject to risks, among others, relating to the
supply of fuel and sales of electricity, effects of competition, changes in
interest rates, operation of deregulating power markets, seasonal weather
patterns, technological obsolescence, and the regulatory environment in the
United States.
Revenue Recognition.
Revenue consists primarily of energy sales. Power produced by the Project is
sold on an equal basis to affiliates of Reliant Resources and Sempra under the
provisions of separate power offtake agreements (See Note 7). Revenues not
billed by month-end are accrued based upon estimated energy or services
delivered.
III-7
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
Cash and Cash Equivalents.
Cash and cash equivalents include highly liquid investments with an original
maturity of three months or less which are readily convertible to cash.
Restricted Cash.
Restricted cash includes cash that is restricted by a financing agreement
but available to satisfy certain obligations. As of December 31, 2002 and 2001,
the Company had $4.4 million and $0 in restricted cash, respectively, recorded
in the balance sheet.
Inventory.
Inventory consists of materials and supplies held for consumption and is
stated at lower of weighted average cost or market.
Debt Service Reserve Fund.
In accordance with the Credit Agreement, the Company is required to maintain
a debt service reserve fund (see Note 3). The restricted funds are invested in
a money market fund.
Debt Issuance Costs.
Costs associated with executing the Credit Agreement were deferred and are
being amortized on a straight-line basis, which approximates the effective
yield method, over the life of the term note under the Credit Agreement (15
years) (see Note 3). As of December 31, 2002 and 2001, the Company had $4.3
million and $4.7 million, respectively, of net deferred financing costs
capitalized in its balance sheets.
Income Taxes.
The Company is a limited liability company not taxable for federal or state
income tax purposes. Any taxable earnings or losses and certain other tax
attributes are reported by the Members on their respective income tax returns.
Estimated Fair Value of Financial Instruments.
The recorded amounts for financial instruments of cash and cash equivalents,
accounts receivable, debt service reserve fund, and long-term debt approximate
fair value.
The Company enters into interest rate swap agreements to reduce its exposure
to fluctuations in interest rates. These contracts are with a major financial
institution and the risk of counterparty default is considered remote. The
Company periodically reviews its credit risk.
The Company does not hold or issue derivative financial instruments for
trading purposes.
See Note 8 for the Company's adoption of Statement of Financial Accounting
Standards ("SFAS") No. 133, "Accounting for Derivative Instruments and Hedging
Activities," as amended ("SFAS No. 133") on January 1, 2001.
III-8
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
Property, Plant and Equipment.
Property, plant, and equipment are stated at cost. Depreciation is computed
using the straight-line method over the estimated useful lives commencing when
assets, or major components thereof, are placed in service. Property, plant,
and equipment consisted of the following:
Estimated December 31,
Useful Lives ------------------
(Years) 2002 2001
------------ -------- --------
(in thousands)
Generation plant-in-service....... 30 $237,600 $233,307
Buildings......................... 30 2,653 2,653
Land improvements................. 20 3,933 3,933
Machinery and equipment........... 5 to 10 1,360 1,360
-------- --------
Total property, plant, & equipment 245,546 241,253
Less: Accumulated depreciation.... (21,511) (13,347)
-------- --------
Property, plant and equipment, net $224,035 $227,906
======== ========
New Accounting Pronouncements
In August 2001, the Financial Accounting Standards Board ("FASB") issued
SFAS No. 143, "Accounting for Asset Retirement Obligations" ("SFAS No. 143").
SFAS No. 143 requires the fair value of a liability for legal asset retirement
obligations 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 statement of operations in the
period of adoption. The Company is currently evaluating the impact of SFAS No.
143 on its 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 supersedes 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 did not materially change the methods
used by the Company to measure impairment losses on long-lived assets. The
Company adopted SFAS No. 144 on January 1, 2002.
III-9
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
3. LONG-TERM DEBT
In September 1998, the Company entered into a Credit Agreement with a group
of banks (the "Lenders") in order to finance a portion of the construction of
the Project. The Credit Agreement provides for $157.8 million of construction
and term loan financing. On September 29, 2000, all outstanding construction
borrowings were converted into a term loan provided within the Credit
Agreement. Principal payments under the term loan are payable in escalating
amounts over the 15-year term of the loan. The following table sets forth the
maturities of long-term debt for the Company as of December 31, 2002 (in
millions):
2003........ $ 6.3
2004........ 7.5
2005........ 9.1
2006........ 9.5
2007........ 9.5
2008 forward 103.3
------
Total.... $145.2
======
Upon conversion into a term loan, the Credit Agreement required that the
Company maintain a debt service reserve fund amount for the two succeeding
calendar quarter periods. Debt service means for any period all principal
payments, all interest payments, and all other fees made or required by the
Company during such period under the Credit Agreement and any other loan
document. This amount was increased to reserve twelve months of debt service as
a commitment from the Company until the later of (a) the Project achieving
Project Completion as defined in the Engineering, Procurement and Construction
Agreement ("EPC") or (b) May 1, 2003. At December 31, 2002 and 2001, the
Company had $14.2 million and $14.4 million, respectively, in the debt service
reserve fund account.
Interest payments on the term note accrue at variable rates based upon
either prime lending rates or the Eurodollar rate. At December 31, 2002 and
2001, the applicable interest rates under the Credit Agreement prior to
consideration of the interest rate swaps (see Note 8) were 3.05% and 3.24%,
respectively.
Borrowings under the Credit Agreement are secured by substantially all
assets of the Company. The Credit Agreement contains customary covenants and
default provisions, including limitations on, among other things, additional
indebtedness, liens, establishment of an additional debt service reserve,
retention, and major maintenance reserve accounts, and restricted payments. At
December 31, 2002, the Company was in compliance with these covenants.
In 2001, the Company, the Lenders, the Members and affiliates of the Members
entered into an Amended and Restated Waiver of Consent, and Amendment to the
Credit Agreement (the "Amendment") which required the affiliates to purchase
capacity and electric energy from the Company during the period from January
26, 2001 to June 30, 2001 (the "Waiver Period"), at certain prices designed to
ensure that the Company maintains a Cash Flow to Debt Service Ratio of 1.5:1 as
of any date of calculation for the immediately preceding quarter. The Amendment
also provided that during any outage period the Cash Flow to Debt Service Ratio
is satisfied by contributions of capital to the Company from the Members.
Through the Amendment, the Lenders agreed to waive compliance with certain
provisions of the Credit Agreement primarily relating to indices used in
calculating electricity sales prices during the Waiver Period.
The $5 million working capital facility under the Credit Agreement expired
in May 2002 and was replaced by two working capital facilities of $2.5 million
each provided by Reliant Resources and Sempra. The Company pays a commitment
fee based on the average daily, unused working capital commitment balance at a
rate of 0.38% per annum. At December 31, 2002 and 2001, there were no
borrowings under the working capital facility.
III-10
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
4. LEASE AGREEMENT
In April 1997, the Company entered into a 20-year lease agreement for
certain parcels of land on which the Project is constructed. The Company has
the option to extend the term of the lease through two renewal options of five
years each and intends to exercise that option. The Company's obligations under
this non-cancelable long-term operating lease as of December 31, 2002 are $0.8
million per year in each of 2003 through 2007 plus a contingent rental, which
is based on 2% of net income, adjusted for principal payments and a 16% return
on equity. Total lease expense was $0.8 million for each of the years ended
December 31, 2002 and 2001 and $1.3 million for the year ended December 31,
2000. The payment of the contingent rental fee is dependent upon the Company
achieving certain adjusted net income levels.
5. MEMBERS' EQUITY
The Company received capital contributions, pursuant to the Amendment to the
Credit Agreement discussed in Note 3, from its Members as follows (See Note 7):
2002 2001 2000
---- ------- ------
(in thousands)
REPG..... $-- $ 8,489 $3,449
SEP I.... -- 8,488 3,450
--- ------- ------
Total. $-- $16,977 $6,899
=== ======= ======
6. EMPLOYEE BENEFIT PLANS
The Company participates in a defined contribution employee savings plan
that is qualified under Section 401(a) of the Internal Revenue Code and ERISA
Section 404(c). The Company contributes an amount equal to 4% of each
employee's earnings into this account each year regardless of participation. It
then matches 75% of employee contributions up to 6% of the respective
employee's earnings (as defined in the savings plan). Participating employees
may contribute up to 11% of their pre-tax earnings under the plan. Savings plan
benefit expense for the years ended December 31, 2002, 2001 and 2000 was
$176,000, $67,000, and $65,000, respectively.
7. RELATED-PARTY TRANSACTIONS
The Company has entered into technical service agreements with REPG and SEP
I. REPG and SEP I bill the Company for the services based on the estimated cost
of their employees who are working on the Project and for certain payments that
were made on behalf of the Company. For the years ended December 31, 2002,
2001, and 2000 under the above agreements, the Company paid REPG $0.7 million,
$1.7 million, and $3.6 million, respectively, and SEP I $26,300, $0.2 million,
and $0.7 million, respectively.
In 2000, during the testing phase, the Company received $55,000 and $1.3
million of revenue from affiliates of Sempra and Reliant Resources,
respectively. These amounts were recorded as a reduction of the Project's total
construction costs.
The Company and certain affiliates of Sempra and Reliant Resources are
parties to separate offtake and gas supply agreements which provide for the
purchase of gas and the sale of electric energy attributable to the Company's
available capacity based on either a month-ahead or day-ahead nomination. The
electricity prices used in 2001 were based on the market clearing prices from
the California Power Exchange through January 25, 2001. For the period from
January 26, 2001 through June 30, 2001, the Company sold capacity and energy to
III-11
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
affiliates of the Members under the terms of the Amendment to the Credit
Agreement discussed in Note 3. For the period January 26, 2001 through February
28, 2001, the Company received revenues from the affiliates equal to the cost
of gas used in producing the electricity plus a fixed scheduling fee. For the
period March 1, 2001 through June 30, 2001, the Company received revenues from
the trading affiliates based on electricity prices derived from a natural gas
index, applicable heat rate and operations and maintenance charges. The Members
each contributed capital of $8.5 million in 2001 in order to maintain the
required Cash Flow to Debt Service Ratio for the Waiver Period discussed in
Note 3. From July 1, 2001 forward, under an amendment to the offtake and gas
supply agreements, the Company is paid based on the Dow Jones SP15 index. In
2000, the prices as established by the California Power Exchange served as the
basis of payment.
In 2002, 2001, and 2000, under these offtake and gas supply agreements, the
Company recorded gross margin of $11.7 million, $16.4 million, and $66.2
million from an affiliate of Reliant Resources, respectively, and $11.7
million, $8.5 million, and $62.4 million from an affiliate of Sempra,
respectively. At December 31, 2002, the Company had an estimated net receivable
of $1.1 million from each of the affiliates of Sempra and Reliant Resources.
The Company also paid each affiliate a monthly scheduling fee of $32,000.
The Company has purchased a $2.0 million surety bond securing its financial
and performance obligations under the terms of the service agreement for
transportation of customer secured natural gas. No draws were made under this
bond in 2002, 2001, or 2000.
8. DERIVATIVE FINANCIAL INSTRUMENTS
(a) Risk Management Activities.
Effective January 1, 2001, the Company adopted SFAS No. 133, which
establishes accounting and reporting standards for derivative instruments,
including certain hedging 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, (b) the exposure to variability in future
cash flows 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. The Company did
not enter into any fair value or foreign exchange hedges in 2002 or 2001.
Adoption of SFAS No. 133 on January 1, 2001 resulted in a cumulative
increase in accumulated other comprehensive income of approximately $2.1
million. The adoption also increased current assets and non-current assets by
$0.7 million and $1.4 million, respectively. During the year ended December 31,
2001, $0.7 million of the initial transition adjustment in other comprehensive
income was recognized in net loss.
The Company is exposed to various market risks. These risks are inherent in
the Company's financial statements and arise from transactions entered into in
the normal course of business. The Company uses interest rate swap agreements
to mitigate the effect of changes in interest rates on the borrowings under the
Credit Agreement discussed in Note 3.
(b) Non-Trading Activities.
Cash Flow Hedges. The Company applies hedge accounting for its derivative
financial instrument used in non-trading activities only if there is a high
correlation between price movements in the derivative and the item designated
as being hedged. The correlation, a measure of hedge effectiveness, is assessed
both at the inception
III-12
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
of the hedge and on an ongoing basis, with an acceptable level of correlation
of at least 80% to 125% required for hedge designation. If and when correlation
ceases to exist at an acceptable level, hedge accounting ceases and prospective
changes in fair value are recognized currently in the Company's results of
operations. During the years ended December 31, 2002 and 2001, the amount of
hedge ineffectiveness recognized in earnings from derivatives that are
considered cash flow hedges was $0.2 of loss and $0.2 million of gain,
respectively. No component of derivative gain or loss was excluded from the
assessment of effectiveness. When it becomes probable that an anticipated
transaction will not occur, the Company realizes in net income the deferred
gains or losses recognized in accumulated other comprehensive loss. During the
year ended December 31, 2002 and 2001, there were no deferred gains or losses
recognized as a result of the discontinuance of cash flow hedges where it was
no longer probable that the forecasted transaction would occur. Once the
forecasted transaction occurs, the accumulated deferred gain or loss recognized
in accumulated other comprehensive loss is reclassified to net income and
included in the Company's Statements of Operations under the caption interest
expense in the case of interest rate swap transactions. As of December 31,
2002, the Company expects $4.0 million of accumulated comprehensive loss to be
reclassified into net income during the next twelve months.
The maximum length of time the Company is hedging its exposure to payment of
variable interest rates is two years.
The Company has entered into an interest rate swap agreement with a
counterparty that fixes the interest rate applicable to the Company's floating
rate debt (see Note 3). As of December 31, 2002, floating rate LIBOR-based
interest payments are exchanged for fixed-rate interest payments of 5.34%. The
notional amount of the interest rate swap agreement was $108.1 million and
$112.5 million at December 31, 2002 and 2001, respectively.
9. EPC CONTRACT CLOSEOUT SETTLEMENT
Kiewit Industrial Company ("Kiewit") was the engineering, procurement and
construction contractor for the Project. In December 2000, the Company drew on
Kiewit's $19.9 million performance guarantee letter of credit because several
issues remained unresolved with Kiewit related to the construction of the
Project. The issues included performance shortfall and guarantee payments, late
completion payments, delayed start up claims, completion of punchlist items,
and outstanding warranty items.
In April 2001, in order to resolve EPC performance shortfall issues and
remaining contract obligations with Kiewit, the Company entered into a Project
Closeout Agreement with Kiewit and Siemens Westinghouse Power Corporation, the
manufacturer of certain equipment at the Project. The agreement provides for
the return of $18.2 million of the $19.9 million drawn on Kiewit's letter of
credit in December 2000 upon successful completion of various modifications.
During 2002 and 2001, the Company returned $6.3 million and $11.9 million to
Kiewit, respectively. The Company will retain $1.7 million as compensation for
Kiewit's remaining contract obligations, which has been recorded as a reduction
of property, plant and equipment.
10. LONG-TERM POWER GENERATION MAINTENANCE AGREEMENT
On September 30, 2002, the Company entered into a long-term power generation
maintenance agreement that covers certain periodic maintenance, including
parts, on power generation turbines. The term of the agreement is based on
turbine usage which the Company estimates would extend no longer than 12 years.
The amount recognized in operations and maintenance expense under the terms of
this agreement during 2002 was $2.9 million.
Payments under the agreement include fees for administration and management
and a variable fee based on a charge for each hour the unit runs. The fee is
also adjusted annually for escalation and may be adjusted based on the number
of times a unit is started.
III-13
EL DORADO ENERGY, LLC
NOTES TO FINANCIAL STATEMENTS--(Continued)
For the Years Ended December 31, 2002, 2001 and 2000
The payments are classified as prepayments on the balance sheet and are
expensed as the services are provided. While some services are provided ratably
throughout the year, the primary driver of the expense will be planned outages
at the facility and are subject to fluctuations based on the timing and scope
of the services being provided.
As of December 31, 2002, no payments have been made under the long-term
maintenance agreements. Estimated cash payments over the five succeeding fiscal
years are as follows (in millions):
2003..... $ 8
2004..... 9
2005..... 7
2006..... 8
2007..... 8
---
Total. $40
===
11. POWER PURCHASE AGREEMENT
On December 18, 2002, the Company entered into a power purchase agreement
with the City of Boulder City, Nevada (the "City") for the sale of up to 10 MW
per year beginning on April 1, 2003 and terminating on March 31, 2023. The
contract gives the City the option to purchase energy from the Company at a
rate that is based on a fixed heat rate, variable natural gas price at the time
of energy consumption, and a fixed margin. No revenues were earned in 2002
under this contract.
12. INSURANCE PROCEEDS
During 2002, the Company received proceeds for certain business interruption
and property insurance claims for $37.4 million and $6.3 million, respectively.
These proceeds relate to the steam turbine outage that occurred on March 13,
2001. The proceeds are classified as other income in the statements of
operations.
13. COMMITMENTS AND CONTINGENCIES
The Company is involved in various claims and lawsuits regarding matters
arising in the ordinary course of business. The Company believes that the
effects on the 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.
* * *
III-14
ITEM 9. Changes in and Disagreements with Accountants on Accounting and
Financial Disclosure.
None.
PART III
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 our 2003 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 our 2003 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 and
Related Stockholder Matters.
The information called for by Item 12 will be set forth in the definitive
proxy statement relating to our 2003 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.
The information called for by Item 12 will be set forth in the definitive
proxy statement relating to our 2003 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 14. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures
Our chief executive officer and chief financial officer have evaluated the
effectiveness of our disclosure controls and procedures (as such term is
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934) as of a date, the evaluation date, within 90 days prior to the filing
date of this Form 10-K. Based on such evaluation, such officers have concluded
that, as of the evaluation date, our disclosure controls and procedures are
effective in alerting them on a timely basis to material information required
to be included in our reports filed or submitted under the Securities Exchange
Act of 1934.
It should be noted that the design of any system of controls is based, in
part, upon certain assumptions about the likelihood of future events, and there
can be no assurance that any design will be successful in achieving its stated
goal under all potential future conditions, regardless of how remote.
Changes in Internal Controls
Since the evaluation date, there have not been any significant changes in
our internal controls or in other factors that could significantly affect such
controls.
III-15
ITEM 15. Exhibits, Financial Statement Schedules and Reports on Form 8-K.
(a)(1) Reliant Resources, Inc. and Subsidiaries Financial Statements.
Independent Auditors' Report..................................................... F-2
Statements of Consolidated Operations for the Years Ended December 31, 2000, 2001
and 2002....................................................................... F-3
Consolidated Balance Sheets as of December 31, 2001 and 2002..................... F-4
Statements of Consolidated Cash Flows for the Years Ended December 31, 2000, 2001
and 2002....................................................................... F-5
Statements of Consolidated Stockholders' Equity and Comprehensive Income (Loss)
for the Years Ended December 31, 2000, 2001 and 2002........................... F-6
Notes to Consolidated Financial Statements....................................... F-7
(a)(2) Financial Statement Schedules for the Years Ended December 31, 2000,
2001 and 2002.
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.
El Dorado Energy, LLC Financial Statements.
The following financial statements of our unconsolidated investment of El
Dorado Energy, LLC are presented pursuant to Rule 3-09 of Regulation S-X.
Independent Auditors' Report................................................. III-2
Statements of Operations for the Years Ended December 31, 2002, 2001 and 2000 III-3
Balance Sheets as of December 31, 2002 and 2001.............................. III-4
Statements of Cash Flows for the Years Ended December 31, 2002, 2001 and 2000 III-5
Statements of Members' Equity and Comprehensive Income (Loss) for the Years
Ended December 31, 2002, 2001 and 2000..................................... III-6
Notes to Financial Statements................................................ III-7
(a)(3) Exhibits
See Index of Exhibits, 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.
. Current Report on Form 8-K dated September 30, 2002, as filed with the
SEC on October 11, 2002 (Items 5 and 7).
. Current Report on Form 8-K dated October 29, 2002, as filed with the SEC
on October 29, 2002 (Items 5, 7 and 9).
. Current Report on Form 8-K dated November 11, 2002, as filed with the SEC
on November 12, 2002 (Items 5 and 7).
. Current Report on Form 8-K dated November 13, 2002, as filed with the SEC
on November 21, 2002 (Items 5 and 7).
. Current Report on Form 8-K dated November 25, 2002, as filed with the SEC
on November 25, 2002 (Items 7 and 9).
III-16
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Annual Report on Form
10-K to be signed on its behalf by the undersigned, thereunto duly authorized.
RELIANT RESOURCES, INC.
(Registrant)
By: /s/ R. STEVE LETBETTER
-----------------------------
R. Steve Letbetter
Chairman and Chief Executive
Officer
April 4, 2003
Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed by the following persons on behalf
of the Registrant and in the capacities and on the dates indicated:
Signature Title Date
--------- ----- ----
/s/ MARK M. JACOBS Executive Vice President and April 4, 2003
- ----------------------------- Chief Financial Officer
Mark M. Jacobs (Principal Financial
Officer)
/s/ THOMAS C. LIVENGOOD Vice President and Controller April 4, 2003
- ----------------------------- (Principal Accounting
Thomas C. Livengood Officer)
/s/ E. WILLIAM BARNETT Director April 4, 2003
- -----------------------------
E. William Barnett
/s/ LAREE E. PEREZ Director April 4, 2003
- -----------------------------
Laree E. Perez
/s/ DONALD J. BREEDING Director April 4, 2003
- -----------------------------
Donald J. Breeding
/s/ JOEL V. STAFF Director April 4, 2003
- -----------------------------
Joel V. Staff
/s/ WILLIAM L. TRANSIER Director April 4, 2003
- -----------------------------
William L. Transier
III-17
CERTIFICATIONS
I, R. Steve Letbetter, certify that:
1. I have reviewed this Annual Report on Form 10-K of Reliant Resources,
Inc.;
2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this Annual Report;
3. Based on my knowledge, the financial statements, and other financial
information included in this Annual Report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the Registrant as of, and for, the periods presented in
this Annual Report;
4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this Annual Report
is being prepared;
(b) evaluated the effectiveness of the Registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this Annual Report (the "Evaluation Date"); and
(c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The Registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the Registrant's auditors and the
audit committee of Registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the Registrant's ability to
record, process, summarize and report financial data and have
identified for the Registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Registrant's internal
controls; and
6. The Registrant's other certifying officers and I have indicated in this
Annual Report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: April 4, 2003 /s/ R. STEVE LETBETTER
------------------------------------
R. Steve Letbetter
Chairman and Chief Executive Officer
CERTIFICATIONS
I, Mark M. Jacobs, certify that:
1. I have reviewed this Annual Report on Form 10-K of Reliant Resources,
Inc.;
2. Based on my knowledge, this Annual Report does not contain any untrue
statement of a material fact or omit to state a material fact necessary
to make the statements made, in light of the circumstances under which
such statements were made, not misleading with respect to the period
covered by this Annual Report;
3. Based on my knowledge, the financial statements, and other financial
information included in this Annual Report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the Registrant as of, and for, the periods presented in
this Annual Report;
4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and
we have:
(a) designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within those
entities, particularly during the period in which this Annual Report
is being prepared;
(b) evaluated the effectiveness of the Registrant's disclosure controls
and procedures as of a date within 90 days prior to the filing date
of this Annual Report (the "Evaluation Date"); and
(c) presented in this Annual Report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;
5. The Registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the Registrant's auditors and the
audit committee of Registrant's board of directors (or persons
performing the equivalent function):
(a) all significant deficiencies in the design or operation of internal
controls which could adversely affect the Registrant's ability to
record, process, summarize and report financial data and have
identified for the Registrant's auditors any material weaknesses in
internal controls; and
(b) any fraud, whether or not material, that involves management or other
employees who have a significant role in the Registrant's internal
controls; and
6. The Registrant's other certifying officers and I have indicated in this
Annual Report whether or not there were significant changes in internal
controls or in other factors that could significantly affect internal
controls subsequent to the date of our most recent evaluation, including
any corrective actions with regard to significant deficiencies and
material weaknesses.
Date: April 4, 2003 /s/ MARK M. JACOBS
----------------------------------------
Mark M. Jacobs
Executive Vice President and Chief Financial Officer
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 Registration Exhibit
Number Document Description Report or Registration Statement Number Reference
- ------- -------------------- ------------------------------------ ------------ ---------
2.1 Agreement Plan of Merger dated as of Reliant Resources, Inc. Current 1-16455 2.1
September 26, 2001 by and Among Orion Report on Form 8-K dated
Power Holdings, Inc., Reliant Resources, Inc. September 27, 2002
and Reliant Energy Power Generation Merger
Sub, Inc .
3.1 Restated Certificate of Incorporation. Reliant Resources, Inc. Registration 333-48038 3.1
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, Reliant Energy, Incorporated's 1-3187 4.2
2001 between Reliant Resources, Inc. and The Quarterly Report on Form 10-Q for
Chase Manhattan Bank, as Rights Agent, the Quarterly Period Ended
including a form of Rights Certificate. March 31, 2001
10.1 Master Separation Agreement between Reliant Reliant Energy, Incorporated's 1-3187 10.1
Resources and Reliant Energy, dated Quarterly Report on Form 10-Q for
December 31, 2000. the Quarterly Period Ended
March 31, 2001
10.2 Transition Services Agreement between Reliant Energy, Incorporated's 1-3187 10.2
Reliant Resources and Reliant Energy, dated Quarterly Report on Form 10-Q for
December 31, 2000. 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 Quarterly Report on Form 10-Q for
December 31, 2000. the Quarterly Period Ended
March 31, 2001
10.4 Texas Genco Option Agreement between Reliant Energy, Incorporated's 1-3187 10.4
Reliant Resources and Reliant Energy, dated Quarterly Report on Form 10-Q for
December 31, 2000. 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 Quarterly Report on Form 10-Q for
December 31, 2000. the Quarterly Period Ended
March 31, 2001
10.6 Retail Agreement between Reliant Resources Reliant Energy, Incorporated's 1-3187 10.6
and Reliant Energy, dated December 31, 2000. Quarterly Report on Form 10-Q for
the Quarterly Period Ended
March 31, 2001
10.7 Registration Rights Agreement between Reliant Energy, Incorporated's 1-3187 10.7
Reliant Resources and Reliant Energy, dated Quarterly Report on Form 10-Q for
December 31, 2000. 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 Quarterly Report on Form 10-Q for
December 31, 2000. the Quarterly Period Ended
March 31, 2001
SEC File or
Exhibit Registration Exhibit
Number Document Description Report or Registration Statement Number Reference
- ------- -------------------- ------------------------------------ ------------ ---------
*10.9 Reliant Resources, Inc. Annual Incentive Reliant Resources, Inc.'s Annual 1-16455 10.9
Compensation Plan effective January 1, 2001. Report on Form 10-K for the year
ended December 31, 2001
*10.10 Reliant Resources, Inc. 2001 Long-Term Reliant Resources, Inc.'s Annual 1-16455 10.10
Incentive Plan effective January 1, 2001. Report on Form 10-K for the year
ended December 31, 2001
*10.11 Reliant Energy, Incorporated's Executive Reliant Resources, Inc. Registration 333-48038 10.11
Benefits Plan effective June 1, 1982, including Statement on Form S-1
the first, 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 Reliant Resources, Inc. Registration 333-48038 10.12
Restoration Plan, as amended and restated Statement on Form S-1
effective July 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 Reliant Energy, Incorporated's 1-3187 10.2
March 29, 1999 among Reliant Energy Quarterly Report on Form 10-Q for
Wholesale Holdings (Europe) Inc., Provincie the quarter ended March 31, 1999.
Noord Holland, Gemeente Amsterdam, N.V.,
Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy Power
Generation, Inc. and UNA.
10.14 Share Purchase Agreement dated March 29, Reliant Energy, Incorporated's 1-3187 10.3
1999 among Reliant Energy Wholesale Quarterly Report on Form 10-Q for
Holdings (Europe) Inc., Provincie Noord the quarter ended March 31, 1999.
Holland, Gemeente Amsterdam, N.V.,
Provinciaal En Gemeenelijk Utrechts
Stroomleveringsdedrijf, Reliant Energy Power
Generation, Inc. and UNA.
10.15 Deed of Amendment dated September 2, 1999 Reliant Energy, Incorporated's 1-3187 2(b)(3)
among Reliant Energy Wholesale Holdings Annual Report on Form 10-K for
(Europe) Inc., Provincie Noord Holland, the year ended December 31, 1999.
Gemeente Amsterdam, N.V., Provinciaal En
Gemeenelijk Utrechts Stroomleveringsdedrijf,
Reliant Energy Power Generation, Inc. and
UNA.
10.16 Purchase Agreement dated as of February 19, Reliant Energy, Incorporated's 1-3187 2(c)
2000 among Reliant Energy Power Generation, Annual Report on Form 10-K for
Reliant Energy Sithe Energies, Inc. and Sithe the year ended December 31, 1999.
Northeast Generating Company, Inc.
10.17 Facility Lease Agreement dated as of Registration Statement on Form S-4 333-51464 4.6a
August 14, 2000 between Conemaugh Lessor of REMA.
Genco LLC and 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.
10.19 Series A Pass Through Trust Agreement dated Registration Statement on Form S-4 333-51464 4.4a
as 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.
SEC File or
Exhibit Registration Exhibit
Number Document Description Report or Registration Statement Number Reference
- ------- -------------------- ------------------------------------ ------------ ---------
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 Registration Statement on Form S-4 333-51464 4.5a
24, 2000 among Conemaugh Lessor Genco of REMA.
LLC, as Owner 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. Registration 333-48038 10.25
Compensation Plan effective as of Statement on Form S-1
September 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. Registration 333-48038 10.26
Compensation Plan, as amended and restated 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. Registration 333-48038 10.27
Compensation Plan, as amended and restated 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. Registration 333-48038 10.28
Restoration Plan effective January 1, 1991, 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. Registration 333-48038 10.29
Benefits Plan effective January 1, 1992, 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).
*10.30 Reliant Energy, Incorporated's Executive Life Reliant Resources, Inc. Registration 333-48038 10.30
Insurance Plan effective January 1, 1994, 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).
SEC File or
Exhibit Registration Exhibit
Number Document Description Report or Registration Statement Number Reference
- ------- -------------------- ------------------------------------ ------------ ---------
*10.31 Employment and Supplemental Benefits Reliant Resources, Inc. Registration 333-48038 10.31
Agreement dated September 4, 1984 between Statement on Form S-1
Reliant Energy, Incorporated and Hugh Rice
Kelly (Reliant Resources has adopted Reliant
Energy, Incorporated's obligations under this
agreement).
10.32 REPGB Stranded Cost Settlement Agreement Reliant Resources, Inc.'s Annual 1-16455 10.32
Report on Form 10-K for the year
ended December 31, 2001
*10.33 Retention Agreement effective May 4, 2001 Reliant Resources, Inc.'s Annual 1-16455 10.33
between Reliant Resources, Inc. and R. Steve Report on Form 10-K for the year
Letbetter ended December 31, 2001
*10.34 Retention Agreement effective May 4, 2001 Reliant Resources, Inc.'s Annual 1-16455 10.34
between Reliant Resources, Inc. and Robert W. Report on Form 10-K for the year
Harvey ended December 31, 2001
*10.35 Retention Agreement effective May 4, 2001 Reliant Resources, Inc.'s Annual 1-16455 10.35
between Reliant Resources, Inc. and Stephen Report on Form 10-K for the year
W. Naeve ended December 31, 2001
*10.36 Retention Agreement effective May 4, 2001 Reliant Resources, Inc.'s Annual 1-16455 10.36
between Reliant Resources, Inc. and Joe Bob Report on Form 10-K for the year
Perkins ended December 31, 2001
*10.37 Reliant Resources, Inc. Transition Stock Plan, Reliant Resources, Inc.'s Annual 1-16455 10.37
effective May 4, 2001 Report on Form 10-K for the year
ended December 31, 2001
10.38 Form of Amended and Restated Construction Reliant Resources, Inc.'s Annual 1-16455 10.38
Agency Agreement for a Facility Report on Form 10-K for the year
ended December 31, 2001
10.39 Form of Amended and Restated Guaranty Reliant Resources, Inc.'s Annual 1-16455 10.39
regarding Restated Construction Agency Report on Form 10-K for the year
Agreement ended December 31, 2001
*10.40 Employment Agreement effective July 29, Reliant Resources, Inc. Quarterly 1-16455 10.1
2002 between Reliant Resources, Inc. and Report on Form 10-Q for the
Mark M. Jacobs quarter ended September 30, 2002
*10.41 Separation Agreement dated July 2, 2002 Reliant Resources, Inc. Quarterly 1-16455 10.2
between Reliant Resources, Inc. and Joe Bob Report on Form 10-Q for the
Perkins quarter ended September 30, 2002
21.1 Subsidiaries of Reliant Resources, Inc. Reliant Resources, Inc.'s Annual 1-16455 21.1
Report on Form 10-K for the year
ended December 31, 2001
+23.1 Consent of Deloitte & Touche LLP
+99.1 Certification of Chairman and Chief Executive
Officer of Reliant Resources, Inc. Certification
pursuant to Section 906 of the Sarbanes-Oxley
Act of 2002 (Subsections (a) and (b) of Section
1350, Chapter 63 of Title 18, United States
Code)
+99.2 Certification of Executive Vice President and
Chief Financial Officer of Reliant Resources,
Inc. Certification Pursuant to Section 906 of
the Sarbanes-Oxley Act of 2002 (Subsections
(a) and (b) of Section 1350, Chapter 63 of Title
18, United States Code)