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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 standa