Edgar Filing: RELIANT RESOURCES INC

AS FILED WITH THE SECURITIES AND EXCHANGE COMMISSION ON JULY 24, 2003

REGISTRATION NO. 333-
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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FORM S-3
REGISTRATION STATEMENT UNDER THE SECURITIES ACT OF 1933
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RELIANT RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 76-0655566
(State or Other Jurisdiction (I.R.S. Employer
of Incorporation or Organization) Identification Number)

1111 LOUISIANA STREET
HOUSTON, TEXAS 77002
(713) 497-3000
(Address, Including Zip Code, and Telephone Number, Including Area Code,
of Registrant's Principal Executive Offices)

MICHAEL L. JINES
SENIOR VICE PRESIDENT, GENERAL COUNSEL
AND CORPORATE SECRETARY
1111 LOUISIANA STREET
HOUSTON, TEXAS 77002
(713) 497-3000
(Name, Address, Including Zip Code, and Telephone Number,
Including Area Code, of Agent For Service)

COPIES TO:

MICHAEL P. ROGAN RICHARD B. AFTANAS
C. KEVIN BARNETTE SKADDEN, ARPS, SLATE, MEAGHER & FLOM LLP
SKADDEN, ARPS, SLATE, MEAGHER & FLOM LLP FOUR TIMES SQUARE
1440 NEW YORK AVENUE, N.W. NEW YORK, NEW YORK 10036
WASHINGTON, D.C. 20005 (212) 735-3000
(202) 371-7000

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APPROXIMATE DATE OF COMMENCEMENT OF PROPOSED SALE TO THE PUBLIC: As soon as
practicable after this Registration Statement becomes effective.

If the only securities being registered on this Form are being offered
pursuant to dividend or interest reinvestment plans, please check the following
box. [ ]

If any of the securities being registered on this Form are to be offered on
a delayed or continuous basis pursuant to Rule 415 under the Securities Act of
1933, other than securities offered only in connection with dividend or interest
reinvestment plans, check the following box. [X]

If this Form is filed to register additional securities for an offering
pursuant to Rule 462(b) under the Securities Act, please check the following box
and list the Securities Act registration statement number of the earlier
effective registration statement for the same offering. [ ]

If this Form is a post-effective amendment filed pursuant to Rule 462(c)
under the Securities Act, check the following box and list the Securities Act
registration statement number of the earlier effective registration statement
for the same offering. [ ]

If delivery of the prospectus is expected to be made pursuant to Rule 434,
please check the following box. [ ]
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CALCULATION OF REGISTRATION FEE

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PROPOSED MAXIMUM
TITLE OF EACH CLASS OF AMOUNT TO BE OFFERING PRICE AMOUNT OF
SECURITIES TO BE REGISTERED REGISTERED(1) PER NOTE(2) REGISTRATION FEE
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5.00% Convertible Senior Subordinated Notes due 2010.... $275,000,000 100% $22,247.50
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Common stock, par value $0.001.......................... 28,822,970(3) (4)
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(1) Represents the aggregate principal amount of the notes that were originally
issued by the Registrant.

(2) Equals the actual issue price of the aggregate principal amount of the notes
being registered. Estimated solely for the purpose of computing the
registration fee pursuant to Rule 457(o) under the Securities Act.

(3) Represents the number of shares of common stock that are currently issuable
upon conversion of the notes registered hereby. The number of shares of
common stock that may be issued in the future is indeterminate, and the
Registrant is also registering this indeterminate amount pursuant to Rule
416 of the Securities Act.

(4) No separate consideration will be received for the shares of common stock
issuable upon conversion of the notes and, therefore, no registration fee is
required pursuant to Rule 457(i) under the Securities Act.

THE REGISTRANT HEREBY AMENDS THIS REGISTRATION STATEMENT ON SUCH DATE OR
DATES AS MAY BE NECESSARY TO DELAY ITS EFFECTIVE DATE UNTIL THE REGISTRANT SHALL
FILE A FURTHER AMENDMENT WHICH SPECIFICALLY STATES THAT THIS REGISTRATION
STATEMENT SHALL THEREAFTER BECOME EFFECTIVE IN ACCORDANCE WITH SECTION 8(A) OF
THE SECURITIES ACT OF 1933 OR UNTIL THE REGISTRATION STATEMENT SHALL BECOME
EFFECTIVE ON SUCH DATE AS THE SECURITIES AND EXCHANGE COMMISSION, ACTING
PURSUANT TO SAID SECTION 8(A), MAY DETERMINE.
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THE INFORMATION IN THIS PROSPECTUS IS NOT COMPLETE AND MAY BE CHANGED. THE
SELLING SECURITY HOLDERS MAY NOT SELL THESE SECURITIES UNTIL THE REGISTRATION
STATEMENT FILED WITH THE SECURITIES AND EXCHANGE COMMISSION IS EFFECTIVE. THIS
PROSPECTUS IS NOT AN OFFER TO SELL THESE SECURITIES AND IT IS NOT SOLICITING
OFFERS TO BUY THESE SECURITIES IN ANY STATE WHERE THE OFFER OR SALE IS NOT
PERMITTED.

SUBJECT TO COMPLETION, DATED JULY 24, 2003

PRELIMINARY PROSPECTUS

(RELIANT RESOURCES LOGO)

$275,000,000

RELIANT RESOURCES, INC.
5.00% CONVERTIBLE SENIOR SUBORDINATED NOTES DUE 2010 AND SHARES OF
COMMON STOCK ISSUABLE UPON CONVERSION OF THE NOTES
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On June 24, 2003, we issued and sold $225,000,000 aggregate principal
amount of our 5.00% Convertible Senior Subordinated Notes due 2010 to Deutsche
Bank Securities Inc., Goldman, Sachs & Co., Banc of America Securities LLC,
Barclays Capital Inc., ABN AMRO Rothschild LLC and Commerzbank Capital Markets
Corp. (the initial purchasers) in a private placement. On July 2, 2003, we
issued and sold, at the option of the initial purchasers, an additional
$50,000,000 aggregate principal amount of the notes to the initial purchasers to
cover overallotments. This prospectus will be used by selling securityholders to
resell the notes and register the common stock issuable upon conversion of the
notes.

The notes will mature on August 15, 2010. You may convert the notes into
shares of Reliant Resources' common stock at any time prior to their maturity or
one business day prior to their redemption or repurchase by Reliant Resources.
The conversion rate is 104.8108 shares of common stock per each $1,000 principal
amount of notes, subject to adjustment in certain circumstances. This is
equivalent to a conversion price of approximately $9.54 per share. On July 21,
2003, the last reported sale price for the common stock on The New York Stock
Exchange was $5.15 per share. The common stock is listed under the symbol "RRI".

Reliant Resources will pay interest on the notes on February 15 and August
15 of each year. The first interest payment will be made on August 15, 2003. The
notes are subordinated in right of payment to all of Reliant Resources' existing
and future senior debt and effectively subordinated to all indebtedness and
liabilities of Reliant Resources' subsidiaries. As of March 31, 2003, the
aggregate amount of Reliant Resources' outstanding senior debt, as defined in
this prospectus, was approximately $5.1 billion and the aggregate amount of
indebtedness and other liabilities of Reliant Resources' subsidiaries was
approximately $6.5 billion (excluding $1.8 billion related to Reliant Resources'
European energy operations). The notes were issued only in denominations of
$1,000 and integral multiples of $1,000.

On or after August 20, 2008, Reliant Resources has the option to redeem the
notes, in whole or in part, at the prices described in this prospectus if the
last reported sale price of Reliant Resources' common stock is at least 125% of
the then effective conversion price for at least 20 trading days within a period
of 30 consecutive trading days ending on the trading day before the date of the
redemption notice. You have the option, subject to certain conditions, to
require Reliant Resources to repurchase any notes held by you in the event of a
change of control, as described in this prospectus, at a price equal to 100% of
the principal amount of the notes plus accrued and unpaid interest to the date
of repurchase.

The notes are evidenced by a global note deposited with a custodian for and
registered in the name of a nominee of The Depository Trust Company. Except as
described in this prospectus, beneficial interests in the global note will be
shown on, and transfers thereon will be effected only through, records
maintained by The Depository Trust Company and its direct and indirect
participants.

We will not receive any of the proceeds from the sale of the notes or the
shares of common stock by any of the selling securityholders. The notes and the
shares of common stock may be offered in negotiated transactions or otherwise,
at market prices prevailing at the time of sale or at negotiated prices. The
timing and amount of any sale are within the sole discretion of the selling
securityholders. In addition, the shares of common stock may be offered from
time to time through ordinary brokerage transactions on the New York Stock
Exchange. See "Plan of Distribution." The selling securityholders may be deemed
to be "underwriters" as defined in the Securities Act of 1933, as amended. Any
profits realized by the selling securityholders may be deemed to be underwriting
commissions. If the selling securityholders use any broker-dealers, any
commission paid to broker-dealers and, if broker-dealers purchase any notes or
shares of common stock as principals, any profits received by such
broker-dealers on the resale of the notes or shares of common stock may be
deemed to be underwriting discounts or commissions under the Securities Act.

NEITHER THE SECURITIES AND EXCHANGE COMMISSION NOR ANY STATE SECURITIES
COMMISSION HAS APPROVED OR DISAPPROVED OF THESE SECURITIES OR DETERMINED IF THIS
PROSPECTUS IS TRUTHFUL OR COMPLETE. ANY REPRESENTATION TO THE CONTRARY IS A
CRIMINAL OFFENSE.

SEE "RISK FACTORS" BEGINNING ON PAGE 16 TO READ ABOUT IMPORTANT FACTORS YOU
SHOULD CONSIDER BEFORE BUYING THE NOTES.
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Preliminary Prospectus dated , 2003.

TABLE OF CONTENTS

PAGE
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Where You Can Find More Information......................... i
Disclosure Regarding Forward-Looking Statements............. ii
Prospectus Summary.......................................... 1
Summary Selected Financial Data............................. 11
Risk Factors................................................ 16
Use of Proceeds............................................. 42
Price Range of Common Stock................................. 42
Dividend Policy............................................. 42
Capitalization.............................................. 43
Selected Financial Information and Other Data............... 44
Management's Discussion and Analysis of Financial Condition
and Results of Operations................................. 48
Our Business................................................ 49
Management.................................................. 73
Certain Relationships and Related Transactions.............. 79
Description of Other Indebtedness........................... 82
Description of Notes........................................ 88
Description of Capital Stock................................ 105
Selling Securityholders..................................... 112
United States Federal Income Tax Consequences............... 114
Plan of Distribution........................................ 117
Legal Matters............................................... 119
Experts..................................................... 119
Glossary of Terms........................................... A-1

WHERE YOU CAN FIND MORE INFORMATION

Reliant Resources files annual, quarterly and special reports, proxy
statements and other information with the Securities and Exchange Commission, or
SEC. You may read and copy any document Reliant Resources files at the SEC's
public reference room in Washington, D.C., 450 Fifth Street, N.W., Washington,
D.C. 20549. Please call the SEC at 1-888-SEC-0330 for further information on the
public reference room. Our SEC filings are also available to the public from the
SEC's web site at www.sec.gov or from Reliant Resources' web site at
www.reliantresources.com. However, the information on Reliant Resources' web
site does not constitute a part of this prospectus.

In this document, Reliant Resources "incorporates by reference" the
information it files with the SEC, which means that Reliant Resources can
disclose important information to you by referring to that information. The
information incorporated by reference is considered to be a part of this
prospectus, and later information filed with the SEC will update and supersede
this information. Reliant Resources incorporates by reference the documents
listed below and any future filings made with the SEC under Sections 13(a),
13(c), 14 or 15(d) of the Securities Exchange Act of 1934, or the Exchange Act,
after the date of the initial registration statement and prior to the
effectiveness of the registration statement and any filings thereafter and prior
to the termination of this offering:

- Reliant Resources' Annual Report on Form 10-K/A filed on May 1, 2003 for
the fiscal year ended December 31, 2002;

- Reliant Resources' Proxy Statement on Schedule 14A, filed on April 30,
2003;

- Reliant Resources' Quarterly Report on Form 10-Q filed on May 14, 2003
for the quarter ended March 31, 2003;

- Reliant Resources' Current Report on Form 8-K filed on January 10, 2003;

- Reliant Resources' Current Report on Form 8-K filed on February 3, 2003;

- Reliant Resources' Current Report on Form 8-K filed on February 24, 2003;

- Reliant Resources' Current Report on Form 8-K filed on March 17, 2003;

- Reliant Resources' Current Report on Form 8-K filed on March 24, 2003;

- Reliant Resources' Current Report on Form 8-K filed on March 28, 2003;

- Reliant Resources' Current Report on Form 8-K filed on April 1, 2003 (to
the extent filed by Reliant Resources under the Securities Exchange Act
of 1934);

- Reliant Resources' Current Report on Form 8-K filed on April 16, 2003
(other than Exhibit 99.2);

- Reliant Resources' Current Report on Form 8-K filed on May 12, 2003;

- Reliant Resources' Current Report on Form 8-K filed on June 5, 2003;

- Reliant Resources' Current Report on Form 8-K filed on June 18, 2003;

- Reliant Resources' Current Report on Form 8-K filed on June 24, 2003;

- Reliant Resources' Current Report on Form 8-K filed on June 30, 2003;

- Reliant Resources' Current Report on Form 8-K filed on July 11, 2003

- Reliant Resources' Current Report on Form 8-K filed on July 23, 2003; and

- the description of our common stock, par value $.001 per share contained
in our Registration Statement on Form 8-A, filed with the SEC on April
27, 2001, as amended by Amendment No. 1 thereto on Form 8-A/A, filed with
the SEC on May 1, 2001.

You may request a copy of these filings at no cost, by writing or
telephoning Reliant Resources at: P.O. Box 4567, Houston, Texas 77210-4567,
Attention: Investor Relations, telephone (713) 497-7000.

For our most recent annual consolidated financial statements and notes, see
our Current Report on Form 8-K filed on June 30, 2003 and incorporated by
reference herein. For our most recent annual "Management's Discussion and
Analysis of Financial Condition and Results of Operations," see our Current
Report on Form 8-K filed on June 5, 2003 and incorporated by reference herein.
For our most recent interim consolidated financial statements and notes and
interim "Management's Discussion and Analysis of Financial Condition and Results
of Operations," see our Current Report on Form 8-K filed on July 23, 2003 and
incorporated by reference herein.

You should rely only upon the information provided in this document or
incorporated in this document by reference. Reliant Resources has not authorized
anyone to provide you with different information. You should not assume that the
information in this document, including any information incorporated by
reference, is accurate as of any date other than the date indicated on the front
cover.

DISCLOSURE REGARDING FORWARD-LOOKING STATEMENTS

This prospectus includes statements concerning expectations, assumptions,
beliefs, plans, projections, objectives, goals, strategies and future events or
performance that are intended as "forward-looking statements". 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 "Risk Factors" beginning on page 16.

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.

iii

PROSPECTUS SUMMARY

In this prospectus, the words "Reliant Resources" and "RRI" refer to
Reliant Resources, Inc. and the words, "we", "our", "ours", and "us" refer to
Reliant Resources, Inc. and its subsidiaries. The following summary contains
basic information about us, the notes and our common stock. It does not contain
all of the information that may be important to you. For a complete
understanding of us, the notes and our common stock, we encourage you to read
this entire document and the documents we have referred you to herein. We
provide a glossary of terms used in this prospectus beginning on page A-1.

COMPANY OVERVIEW

We are based in Houston, Texas and provide electricity and energy services
to retail and wholesale customers. We provide a complete suite of energy
products and services to approximately 1.7 million electricity customers in
Texas under the Reliant Energy brand name. These customers range from residences
and small businesses to large commercial, industrial and institutional
customers. Our business includes approximately 22,000 MW of power generation
capacity in operation, under construction or under contract in the United
States. In addition, we have the exclusive option to acquire CenterPoint's 81%
ownership interest in Texas Genco, which owns approximately 14,000 MW of
generating capacity in Texas.

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 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 initial public offering of approximately 20%
of our common stock in May 2001. In September 2002, the distribution of the
remaining shares of our common stock owned by CenterPoint to its stockholders
was completed and, as a result, we are no longer a subsidiary of CenterPoint.

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. 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
approximately 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 approximately one MW (i.e., 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 approximately one MW or greater of peak demand).
We currently provide retail electric service to residential and small commercial
customers only in Texas and primarily in the Houston area. We have no near-term
plans to provide retail electric service to residential and small commercial
customers outside of Texas. However, we recently entered into contracts to
provide retail electric services to large commercial, industrial and
institutional customers in New Jersey beginning August 1, 2003, and we are
taking steps to provide electricity and related products and services to large
commercial, industrial and institutional customers in certain other states,
including Maryland and Pennsylvania where we have received licenses to provide
retail electric service. Included in our retail energy segment are our ERCOT
generation facilities which consist of ten power generation units completed or
under various stages of construction at seven facilities with an aggregate net
generation capacity of 805 MW located in Texas.

WHOLESALE ENERGY

Our wholesale energy segment provides energy and energy services with a
focus on the competitive segment of the United States wholesale energy markets.
We have built a diversified 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 market
electric energy, capacity and ancillary services and procure natural gas, coal,
fuel oil, natural gas transportation capacity and other energy-related
commodities to optimize our physical assets and provide risk management services
for our asset portfolio.

We own, own an interest in, or lease 120 operating electric power
generation facilities with an aggregate net generating capacity of 19,083 MW
located in five regions of the United States -- the Mid-Atlantic, New York, the
Mid-Continent, the Southeast and the West regions. The generating capacity of
these facilities consists of approximately 32% of base-load, 36% of intermediate
and 32% of peaking capacity. Our generating capacity is fueled 39% by natural
gas, 23% by coal, 3% by oil and 31% has dual-fuel capability. The remaining 4%
of our generating capacity is hydroelectric. We have two electric power
generation facilities and replacement or incremental electric power generation
units at two 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:

TOTAL NET
NUMBER OF GENERATING
GENERATION CAPACITY
REGION FACILITIES(1) (MW)(2) DISPATCH TYPE(3) FUEL TYPE
------ ------------- ---------- ------------------------ ------------------

MID-ATLANTIC
Operating(4)................ 22 4,795 Base, Intermediate, Peak Gas/Coal/Oil/Hydro
Under -- 1,120 Base, Intermediate Gas/ Coal
Construction(5)(6)(7).....
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Combined.................... 22 5,915
NEW YORK
Operating(8)................ 77 2,952 Base, Intermediate, Peak Gas/Oil/Hydro
MID-CONTINENT
Operating................... 9 4,484 Base, Intermediate, Peak Gas/Oil/Coal
Under Construction(5)....... 1 800 Intermediate, Peak Gas
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Combined.................... 10 5,284
SOUTHEAST
Operating(9)(10)............ 5 2,210 Base, Intermediate, Peak Gas/Oil
WEST
Operating(11)(12)(13)....... 7 4,642 Base, Intermediate, Peak Gas/Oil
Under Construction(5)....... 1 541 Base, Intermediate Gas
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Combined.................... 8 5,183
TOTAL
Operating................... 120 19,083
Under Construction.......... 2 2,461
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Combined.................... 122 21,544
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(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) 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.

(6) 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.

(7) 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.

(8) Excludes two hydro plants with a net generating capacity of 5 MW, which are
not currently operational.

(9) 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%.

(10) 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.

(11) 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.

(12) 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%.

(13) Includes our 588-megawatt Desert Basin plant, located in Casa Grande,
Arizona. On July 9, 2003, we entered into a definitive agreement to sell
our Desert Basin plant to SRP.

We seek to optimize our physical asset positions consisting of our power
generation asset portfolio, pipeline transportation capacity positions, pipeline
storage positions and fuel positions and provide risk management services for
our asset positions. We perform these functions through procurement, 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 is to optimize our assets. 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 marketing and hedging
activities related to our electric generating facilities, pipeline
transportation capacity positions, pipeline storage positions and fuel
positions.

DISCONTINUED OPERATIONS

We own and operate 13 electric power generation units organized into three
clusters 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 European energy segment produces, buys and sells electricity, gas and other
energy-related commodities primarily in the Netherlands wholesale market. The
primary customers in the Netherlands are electric distribution companies, large
industrial consumers and energy trading companies.

Our European trading and origination operations are currently centered in
the Netherlands, with an additional office in Germany. Our European trading and
origination operations 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. In September 2002, we decided to substantially exit our proprietary
trading activities in Europe.

In February 2003, we announced the sale of our European energy business to
Nuon for approximately Euro 1.1 billion (as of March 31, 2003, approximately
$1.2 billion). As additional contingent consideration for the sale, we will also
receive 90% of the dividends and other distributions in excess, if any, of
approximately Euro 110 million (as of March 31, 2003, approximately $120
million) paid by NEA to REPGB following consummation of the sale. We intend to
use the cash proceeds from the sale first to prepay the Euro 600 million bank
term loan borrowed by RECE to finance a portion of the original acquisition
costs of our European energy operations. We currently expect this sale to close
in the summer

of 2003. In accordance with current accounting standards, the results of these
operations are now reported as discontinued operations.

OBJECTIVES AND STRATEGY

We are committed to building a balanced wholesale and retail energy
business. Achievement of this goal will be facilitated by focusing on the
following strategic priorities:

OPTIMIZE OUR BUSINESS

Our retail energy business has a strong competitive position in Texas and
has provided us with a stable source of earnings. Following deregulation, as
anticipated, we have seen a loss of residential and small business market share
in the Houston area service territory. We are pursuing customers in other
markets outside of the Houston area service territory to mitigate the loss of
this market share. As a result of such marketing efforts, we have made
out-of-territory market share gains which have helped to offset losses within
the Houston area service territory. Further, our business which provides
electricity and energy services to customers with an aggregate peak demand of
greater than approximately one MW has grown its market share substantially since
deregulation and is poised to continue to grow in Texas. In addition, we have
recently opened an office in New Jersey and are focused on building a strong
position in the surrounding region.

Our wholesale energy business consists of a portfolio of diverse generation
assets which enable us to market electric energy, capacity and ancillary
services. In addition, we procure natural gas, coal, fuel oil, natural gas
transportation capacity and other energy-related commodities and maintain a
commercial infrastructure to optimize our physical assets and contractual
positions through marketing and hedging activities. We focus on contracting our
capacity and procuring the necessary fuel to generate that power, to lock in
energy margins. While current market conditions are generally weak, we expect
the profitability of our wholesale energy business to improve markedly when
markets return to more balanced supply and demand fundamentals and market rules
and regulations improve.

IMPROVE OUR CAPITAL STRUCTURE

Our March 2003 refinancing provided us liquidity and removed near-term debt
maturities which enhances our ability to access the capital markets. Our
business is an inherently cyclical one; consequently, we believe that we need a
more balanced capital structure, and we intend to replace the majority of our
bank debt with long-term fixed income debt and equity. Our first step in the
process was our issuances of $275 million of notes ($225 million in June 2003
and $50 million in July 2003) and $1.1 billion of senior secured notes in July
2003 (described below in "-- Recent Developments"). The net proceeds of the
notes were placed in an escrow account for the possible acquisition of Texas
Genco and the net proceeds of the senior secured notes were used to pay down our
bank debt.

OPPORTUNISTICALLY DIVEST NON-CORE ASSETS

We continuously evaluate our non-core assets. As we demonstrated by our
agreement to sell our European energy operations and by our recent agreement to
sell our 588-megawatt Desert Basin plant operations (described below in
"-- Recent Developments"), we will consider selling specific generation assets
in order to narrow our focus, bolster our liquidity and strengthen our financial
position.

CAPITALIZE ON UNIQUE OPPORTUNITIES

We will continue to pursue opportunities to enhance our businesses within
the parameters of our capital structure. We have the exclusive option to acquire
CenterPoint's 81% interest in Texas Genco, which could have strategic
advantages, including synergies and operational benefits, given that we source a
significant percentage of our electric energy supply from Texas Genco.

The continued expansion and growth of our residential and small commercial
retail energy business in Texas and our large commercial, industrial and
institutional retail energy business both in Texas and other strategic markets
in the United States also remain top priorities.

RECENT DEVELOPMENTS

In March 2003, we completed a $6.2 billion financing package that
refinanced $5.9 billion of our existing bank credit facilities with new credit
facilities and provided us with an additional $300 million senior priority
credit facility. The $5.9 billion of new credit facilities consists of a $2.1
billion revolving credit facility and a $3.8 billion term loan, all of which
mature in 2007 and do not require any mandatory principal payments prior to May
15, 2006. The $300 million senior priority credit facility provides us with
additional liquidity in the event of extreme movements in commodity prices. It
matures upon the earlier of our purchase of any of the outstanding common stock
of Texas Genco or December 15, 2004.

Concurrently with our offering of the notes, we issued and sold in a
private placement an aggregate principal amount of $1.1 billion of senior
secured notes. For additional information regarding the $1.1 billion of senior
secured notes, see "Description of Other Indebtedness -- Senior Secured Notes".
We also entered into an amendment to our new credit facilities to, among other
things, permit the senior secured note offering, share collateral with the
senior secured notes and certain future senior secured note offerings and
increase our flexibility to purchase CenterPoint's interest in Texas Genco. The
amendment allows us to negotiate a purchase of CenterPoint's interest in Texas
Genco outside the option at a price less than or equal to the price set under
the option and also extends the deadline for agreeing to purchase an interest in
Texas Genco until September 15, 2004. The amendment also revised the collateral
mechanics to replace the collateral agent with a collateral trustee for the
benefit of the banks and the secured noteholders, revised the mandatory
prepayment provisions so that the senior secured notes will share pro rata with
the banks any net proceeds from asset sales required to be paid to the banks and
separated the Orion Power Holdings, Inc. limited guaranty from the credit
agreement so it can ratably guaranty the bank debt and the senior secured notes.

On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant, located in Casa Grande, Arizona, to Salt River
Project Agricultural Improvement and Power District (SRP) of Phoenix for $289
million. Desert Basin, a combined-cycle facility that we developed, started
commercial operation in 2001 and is currently providing all of its power to SRP
under a 10-year power purchase agreement, which will be terminated in connection
with the sale. The Desert Basin plant is the only operation of REDB, an indirect
wholly-owned subsidiary of ours. The transaction is subject to regulatory
approvals, including the FERC, and certain third-party consents and approvals.
The transaction is expected to close by the end of 2003. We intend to use the
net proceeds of approximately $287 million to prepay indebtedness of our senior
secured debt or for the possible acquisition of direct or indirect ownership
interests in assets currently owned by Texas Genco.

disposal. SFAS No. 142 also requires us to test the recoverability of goodwill
in our remaining wholesale energy reporting unit as of July 2003. After the
allocation of goodwill to the Desert Basin plant operations, our wholesale
energy segment's remaining goodwill is estimated to be approximately $1.4
billion, which is being tested for impairment effective July 2003.

For further discussion regarding the anticipated sale of our Desert Basin
plant operations and our July 2003 goodwill impairment evaluation of our
wholesale energy reporting unit, see "Risk Factors -- Risks Related to Our
Wholesale Energy Operations".

Based on our results of operations of our wholesale energy and retail
energy segments for the second quarter of 2003 through May 31, 2003, we
currently anticipate that our results from continuing operations for this period
will be significantly less than our results from continuing operations for the
comparable period in 2002.

* * *

Our principal executive offices are located at 1111 Louisiana Street,
Houston, Texas 77002, and our telephone number is (713) 497-3000.

CORPORATE STRUCTURE AND COMPONENTS OF DEBT

The following simplified diagram presents our general corporate structure
and the components of our banking and credit facilities and other long-term debt
to third parties of Reliant Resources and its subsidiaries (excluding our
European energy discontinued operations) as of March 31, 2003 (in billions):

(DEBT STRUCTURE CHART)
---------------

(1) As of March 31, 2003, Reliant Resources had letters of credit outstanding of
$0.3 billion supporting the Seward Trust tax-exempt debt and $0.2 billion of
letters of credit relating to commercial activities under its senior secured
revolver. In addition, Reliant Resources had letters of credit outstanding
of $0.1 billion under its cash collateralized letter of credit facility.

(2) As of March 31, 2003, we had margin deposits supporting commercial
activities and collateral for letters of credit relating to commercial
activities aggregating $0.5 billion.

(3) Includes an aggregate of 14 generation facilities located in the states of
California, Arizona, Nevada, Florida, Illinois, Pennsylvania and
Mississippi.

(4) In August 2000, we entered into separate sale/leaseback transactions with
each of the three owner-lessors for our interests in three generating
stations acquired in the REMA acquisition. For additional discussion of
these lease transactions, see note 14(a) to our consolidated financial
statements incorporated by reference herein.

(5) In July 2002, we entered into a receivables facility arrangement with a
financial institution to sell an undivided interest in accounts receivable
from residential and small commercial retail electric customers, on an
ongoing basis. Pursuant to this receivables facility, we formed a QSPE as a
bankruptcy remote indirect subsidiary of RERH. For additional information
regarding this transaction, see note 15 to our consolidated financial
statements incorporated by reference herein.

(6) We issued $275 million of notes ($225 million in June 2003 and $50 million
in July 2003) and $1.1 billion of senior secured notes in July 2003. The net
proceeds of the notes were placed in an escrow account for the possible
acquisition of Texas Genco and the net proceeds of the senior secured notes
were used to pay down our bank debt. The above table does not reflect
issuances of the notes and the senior secured notes and the use of the
proceeds therefrom.

THE OFFERING

Issuer........................ Reliant Resources, Inc.

Notes Offered................. $275,000,000 in aggregate principal amount of
5.00% Convertible Senior Subordinated Notes due
2010 issued as of July 2, 2003.

Maturity...................... August 15, 2010.

Interest Payment Dates........ Interest on the notes is payable semi-annually
on February 15 and August 15 of each year,
commencing August 15, 2003.

Conversion.................... The notes are convertible at the option of the
holder into shares of our common stock at a
conversion rate of 104.8108 shares of common
stock per $1,000 in principal amount of notes.
This is equivalent to a conversion price of
approximately $9.54 per share. The conversion
rate is subject to adjustment in certain
events. The notes are convertible at the above
conversion rate at any time on or after
issuance and prior to the close of business on
the maturity date, unless we have previously
redeemed or repurchased the notes. Holders of
notes called for redemption or submitted for
repurchase will be entitled to convert the
notes up to the close of business on the
business day immediately preceding the date
fixed for redemption or repurchase, as the case
may be. See "Description of Notes -- Conversion
Rights".

Subordination................. The notes are subordinated to our existing and
future senior debt including the senior secured
notes. As of March 31, 2003, the aggregate
amount of Reliant Resources' outstanding debt
was approximately $5.1 billion and Reliant
Resources had approximately $651 million of
commitments that would have been available for
future borrowings as senior debt. As of March
31, 2003, the aggregate amount of indebtedness
and other liabilities of our subsidiaries was
approximately $6.5 billion (excluding $1.8
billion related to our European energy
operations) and our subsidiaries had
approximately $39 million (excluding $189
million related to our European energy
operations) of commitments that would have been
available for future borrowings as senior debt.
We will not be restricted under the indenture
from incurring senior debt or other additional
indebtedness. See "Description of Notes --
Subordination".

Global Note; Book-entry
System........................ The notes were issued only in fully registered
form without interest coupons and in minimum
denominations of $1,000 and integral multiples
of $1,000. The notes are evidenced by one or
more global notes deposited with the trustee
for the notes, as custodian for DTC. Beneficial
interests in the global note are shown on, and
transfers of those beneficial interest can only
be made through, records maintained by DTC and
its direct and indirect participants. See
"Description of Notes -- Form, Denomination,
Transfer, Exchange and Book-Entry Procedures".

Optional Redemption by Reliant
Resources..................... We may redeem the notes at our option at any
time on or after August 20, 2008, in whole or
in part, if the last reported sale price of our
common stock is at least 125% of the then
effective conversion price for at least 20
trading days within a period of 30
8

consecutive trading days ending on the trading
day before the date of the redemption notice at
the redemption prices set forth below under
"Description of Notes -- Optional Redemption by
RRI," plus accrued and unpaid interest to, but
excluding, the redemption date. We will
therefore be required to make at least ten
interest payments on the notes before being
able to redeem the notes.

Repurchase at Option of
Holders Upon a Change in
Control....................... Upon a change in control, you will have the
right to require us to repurchase all or part
of your notes at 100% of the principal amount
of the notes, plus accrued and unpaid interest
to, but excluding, the repurchase date. The
repurchase price is payable in cash, or, at our
option, in shares of common stock, or other
applicable securities if we are not the
surviving corporation of the change in control
transaction or transactions, valued at 95% of
the average closing prices of our common stock
or other applicable securities for the five
trading days immediately preceding the second
trading day prior to the repurchase date,
subject to certain conditions. See "Description
of Notes -- Repurchase at Option of Holders
Upon a Change in Control".

Events of Default............. The following are events of default under the
indenture for the notes:

- we fail to pay principal of or any premium,
if any, on any note when due, whether or not
the payment is prohibited by the
subordination provisions of the indenture;

- we fail to pay any interest, including any
special interest, on any note when due, which
failure continues for 30 days, whether or not
the payment is prohibited by the
subordination provisions of the indenture;

- we fail to comply with the notice and
repurchase provisions described under
"Description of the Notes -- Repurchase at
Option of Holders Upon a Change of Control",
which failure continues for 30 days following
notice whether or not the notice or
repurchase is prohibited by the subordination
provisions of the indenture;

- we fail to perform any agreement or other
covenant in the notes or the indenture, which
failure continues for 90 days following
notice as provided in the indenture;

- we fail to pay any indebtedness under any
bond, debenture, note or other evidence of
indebtedness for money borrowed by us or any
of our subsidiaries other than RECE and its
subsidiaries, Reliant Energy Channelview,
L.P. and its subsidiaries so long as, taken
together, they would not constitute a
significant subsidiary, Liberty Electric PA,
LLC, Liberty Electric Power, LLC and their
respective subsidiaries so long as, taken
together, they would not constitute a
significant subsidiary and Reliant Energy
Retail Holdings, LLC or any subsidiary
thereof in connection with a securitization
transaction in which the indebtedness
incurred by such entities is

non-recourse to Reliant Resources and its
other subsidiaries (or the payment of which
is guaranteed by us) in a principal aggregate
amount then outstanding in excess of
$100,000,000 at final maturity (either at its
stated maturity or upon acceleration);

- failure by Reliant Resources or any of our
subsidiaries other than RECE and its
subsidiaries, Reliant Energy Channelview,
L.P. and its subsidiaries so long as, taken
together, they would not constitute a
significant subsidiary, Liberty Electric PA,
LLC, Liberty Electric Power, LLC and their
respective subsidiaries so long as, taken
together, they would not constitute a
significant subsidiary and Reliant Energy
Retail Holdings, LLC or any subsidiary
thereof that has engaged in a securitization
transaction to pay final and non-appealable
judgments aggregating in excess of
$100,000,000, which are not covered by
indemnities or third-party insurance, which
judgments are not paid, discharged or stayed
for a period of 60 days; and

- certain events of bankruptcy, insolvency or
reorganization involving us or any of our
significant subsidiaries (other than RECE and
its subsidiaries).

See "Description of Notes -- Events of
Default".

Trading....................... The notes sold to qualified institutional
buyers are eligible for trading in the PORTAL
market; however, the notes resold pursuant to
this prospectus will no longer trade on the
PORTAL market. We do not intend to list the
notes on any national securities exchange or
the Nasdaq National Market.

Listing of Common Stock....... Our common stock is quoted on The New York
Stock Exchange under the symbol "RRI".

Use of Proceeds............... We will not receive any of the proceeds from
the sale by any selling securityholder of the
notes or shares of common stock offered under
this prospectus.

Common Shares................. As of July 21, 2003, there were 294,286,986
shares of our common stock issued and
outstanding.

SUMMARY SELECTED FINANCIAL DATA

The following tables present our summary selected consolidated financial
data for 1998 through 2002 and the three months ended March 31, 2002 and March
31, 2003. The financial data for 1998, 1999 and 2000 are derived from the
consolidated historical financial statements of CenterPoint. The financial data
for the three months ended March 31, 2002 and March 31, 2003 are derived from
our unaudited interim consolidated financial statements. The data set forth
below should be read together with "Management's Discussion and Analysis of
Financial Condition and Results of Operations" for the three years ended
December 31, 2000, 2001 and 2002 included in our Current Report on Form 8-K
filed on June 5, 2003, incorporated by reference herein, our historical
consolidated financial statements and the notes to those statements included in
our Current Report on Form 8-K filed on June 30, 2003, incorporated by reference
herein, "Management's Discussion and Analysis of Financial Condition and Results
of Operations" for the three months ended March 31, 2002 and 2003 included in
our Current Report on Form 8-K filed on July 23, 2003, incorporated by reference
herein, and our interim consolidated financial statements and the notes to those
statements included in our Current Report on Form 8-K filed on July 23, 2003,
incorporated by reference herein. The historical financial information may not
be indicative of our future performance and the historical financial information
for 1998, 1999 and 2000 does not reflect what our financial position and results
of operations would have been had we operated as a separate, stand-alone entity
during the periods presented.

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
------------------------------------------------------ ---------------------
1998 1999 2000 2001 2002 2002 2003
(1)(4) (1)(4) (1)(4)(5) (1)(2)(4)(5) (1)(3)(4) (1)(3)(4)(5) (1)
------ ------ --------- ------------ --------- ------------ ------
(IN MILLIONS, EXCEPT PER SHARE AMOUNT)

INCOME STATEMENT DATA:
Revenues.......................... $277 $601 $2,732 $5,507 $10,638 $1,607 $2,633
Trading margins................... 33 88 198 378 288 51 (74)
---- ---- ------ ------ ------- ------ ------
Total........................... 310 689 2,930 5,885 10,926 1,658 2,559
---- ---- ------ ------ ------- ------ ------
Expenses:
Fuel and cost of gas sold....... 102 293 911 1,576 1,086 163 375
Purchased power................. 13 149 926 2,498 7,421 1,031 1,708
Accrual for payment to
CenterPoint.................. -- -- -- -- 128 -- 47
Operation and maintenance....... 65 128 336 464 786 150 197
General, administrative and
development.................. 78 94 270 471 643 110 123
Depreciation and amortization... 15 23 118 171 378 57 89
---- ---- ------ ------ ------- ------ ------
Total........................ 273 687 2,561 5,180 10,442 1,511 2,539
---- ---- ------ ------ ------- ------ ------
Operating income.................. 37 2 369 705 484 147 20
---- ---- ------ ------ ------- ------ ------
Other income (expense):
Gains (losses) from
investments.................. -- 14 (22) 23 (23) 3 1
(Loss) income of equity
investments of unconsolidated
subsidiaries................. (1) (1) 43 7 18 4 (1)
Gain on sale of development
project...................... -- -- 18 -- -- -- --
Other, net...................... 1 1 -- 2 23 (3) (3)
Interest expense................ (2) -- (7) (16) (267) (29) (97)
Interest income................. 1 1 16 22 28 2 14
Interest income (expense) --
affiliated companies, net.... 2 (6) (172) 12 5 3 --
---- ---- ------ ------ ------- ------ ------
Total other income
(expense).................. 1 9 (124) 50 (216) (20) (86)
---- ---- ------ ------ ------- ------ ------
Income (loss) from continuing
operations before income
taxes........................... 38 11 245 755 268 127 (66)
Income tax expense (benefit).... 17 6 102 292 121 46 (20)
---- ---- ------ ------ ------- ------ ------
Income (loss) from continuing
operations...................... 21 5 143 463 147 81 (46)
---- ---- ------ ------ ------- ------ ------
Income (loss) from operations of
discontinued European energy
operations................... -- 15 73 79 (380) 12 (369)
Income tax (benefit) expense.... -- (4) (7) (18) 93 (3) 12
---- ---- ------ ------ ------- ------ ------
Income (loss) from discontinued
operations................... -- 19 80 97 (473) 15 (381)
---- ---- ------ ------ ------- ------ ------
Income (loss) before cumulative
effect of accounting changes.... 21 24 223 560 (326) 96 (427)
Cumulative effect of accounting
changes, net of tax............. -- -- -- 3 (234) (234) (25)
---- ---- ------ ------ ------- ------ ------
Net income (loss)................. $ 21 $ 24 $ 223 $ 563 $ (560) $ (138) $ (452)
==== ==== ====== ====== ======= ====== ======

BASIC EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing
operations................... $ 1.67 $ 0.51 $ 0.28 $(0.16)
Income (loss) from discontinued
operations, net of tax....... 0.35 (1.63) 0.05 (1.31)
------ ------- ------ ------
Income (loss) before cumulative
effect of accounting
changes...................... 2.02 (1.12) 0.33 (1.47)
Cumulative effect of accounting
changes, net of tax.......... .01 (0.81) (0.81) (0.08)
------ ------- ------ ------
Net income (loss)............... $ 2.03 $ (1.93) $(0.48) $(1.55)
====== ======= ====== ======
DILUTED EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing
operations................... $ 1.67 $ 0.50 $ 0.28 $(0.16)
Income (loss) from discontinued
operations, net of tax....... 0.35 (1.62) 0.05 (1.31)
------ ------- ------ ------
Income (loss) before cumulative
effect of accounting
changes...................... 2.02 (1.12) 0.33 (1.47)
Cumulative effect of accounting
changes, net of tax.......... .01 (0.80) (0.81) (0.08)
------ ------- ------ ------
Net income (loss)............... $ 2.03 $ (1.92) $(0.48) $(1.55)
====== ======= ====== ======

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
---------------------------------------------------- -------------------
1998 1999 2000 2001 2002 2002 2003
(1) (1) (1)(5) (1)(2)(5) (1)(3) (1) (1)
------- -------- -------- --------- -------- -------- --------
(IN MILLIONS, EXCEPT OPERATING DATA AND RATIO)

STATEMENT OF CASH FLOW DATA:
Cash flows from operating
activities................ $ (2) $ 38 $ 335 $ (152) $ 519 $ 396 $ (227)
Cash flows from investing
activities................ (365) (1,406) (3,013) (838) (3,486) (3,127) (190)
Cash flows from financing
activities................ 379 1,408 2,721 1,000 3,981 2,861 (314)
OTHER OPERATING DATA:
Capital Expenditures........ (31) (293) (918) (819) (641) (177) (189)
Trading and marketing
activity(6):
Natural gas (Bcf)(7)...... 1,115 1,481 2,273 3,265 3,449 951 360
Power sales (thousand
MWh)(7)................ 61,195 128,266 125,971 222,907 306,425 69,941 23,854
Power generation activity:
Wholesale power sales
(thousand MWh)(7)...... 2,973 10,204 39,300 62,825 128,812 21,503 27,097
Retail power sales (GWh).... -- -- -- 473 59,004 12,783 13,896
Net power generation
capacity (MW)............. 3,800 4,469 9,231 11,109 19,888 16,753 19,888
Ratio of earnings to fixed
Charges(8)(9)(10)......... 19.31 1.28 1.83 7.54 1.66 3.36 --

DECEMBER 31,
----------------------------------------------
1998 1999 2000 2001 2002 MARCH 31,
(1) (1) (1)(5) (1)(5) (1)(5) 2003
------ ------- ------- ------- ------- ---------
(IN MILLIONS)

BALANCE SHEET DATA:
Property, plant and equipment, net... $ 270 $ 643 $ 2,439 $ 3,108 $ 7,294 $ 8,738
Total assets......................... 1,409 5,624 13,475 11,726 17,637 18,838
Short-term borrowings................ -- -- -- 92 669 306
Long-term debt to third parties,
including current maturities....... -- 69 260 297 6,159 7,639
Accounts and notes (payable)
receivable -- affiliated companies,
net................................ (17) (1,333) (1,969) 445 -- --
Stockholders' equity................. 652 741 2,345 5,984 5,653 5,263

---------------

(1) Our results of operations include the results of the following
acquisitions, all of which were accounted for using the purchase method of
accounting, from their respective acquisition dates: the five generating
facilities in California substantially acquired in April 1998, a generating
facility in Florida acquired in October 1999, the REMA acquisition that
occurred in May 2000 and the Orion Power acquisition that occurred in
February 2002. See note 5 to our consolidated financial statements
incorporated by reference herein for further information about the
acquisitions occurring in 2000 and 2002. In October 1999, we acquired
REPGB, which is part of our European energy operations. In February 2003,
we signed an agreement to sell our European energy operations to Nuon. In
the first quarter of 2003, we began to report the results of our European
energy operations as discontinued operations in accordance with SFAS No.
144 and accordingly, reclassified prior period amounts. For further
discussion of the sale, see note 23 to our consolidated financial
statements incorporated by reference herein.

(2) Effective January 1, 2001, we adopted SFAS No. 133 which established
accounting and reporting standards for derivative instruments. See note 7
to our consolidated financial statements incorporated by reference herein
for further information regarding the impact of the adoption of SFAS No.
133.

(3) During the third quarter of 2002, we completed the transitional impairment
test for the adoption of SFAS No. 142 on our consolidated financial
statements, including the review of goodwill for impairment as of January
1, 2002. Based on this impairment test, we recorded an impairment of our
European energy segment's goodwill of $234 million, net of tax, as a
cumulative effect of accounting change. See note 6 to our consolidated
financial statements incorporated by reference herein for further
discussion.

(4) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis in the statements of
consolidated operations. Comparative financial statements for prior periods
have been reclassified to conform to this presentation. See note 2(t) to
our consolidated financial statements incorporated by reference herein for
further discussion.

(5) As described in note 1 to our consolidated financial statements
incorporated by reference herein, our consolidated financial statements for
2000 and 2001 and for the three months ended March 31, 2002 have been
restated from amounts previously reported. The restatement had no impact on
previously reported consolidated cash flows.

(6) Excludes financial transactions.

(7) Includes physical contracts not delivered.

(8) For purposes of calculating the ratio of earnings to fixed charges,
earnings consist of income (loss) from continuing operations before income
taxes less (a)(1) income of equity investments of unconsolidated
subsidiaries and (2) capitalized interest plus (b)(1) loss of equity
investments of unconsolidated subsidiaries, (2) fixed charges, (3)
amortization of capitalized interest and (4) distributed income of equity
investees. Fixed charges consist of (a) interest expense, (b) interest
expense -- affiliated companies, net, (c) capitalized interest and (d)
interest within rent expense.

(9) For the three months ended March 31, 2003, our earnings were insufficient
to cover our fixed charges by $80 million as fixed charges were $130
million and earnings were $50 million.

(10) The pro forma ratios of earnings to fixed charges for the year ended
December 31, 2002 and for the three months ended March 31, 2003 for the
issuance of the notes and the senior secured notes did not change from the
historical ratios by more than 10% since the specific debt that was repaid
with the issuance of the senior secured notes has only been outstanding
since March 31, 2003. However, had we assumed the notes and the senior
secured notes had been issued and outstanding as of January 1, 2002, and
had repaid debt, with the amount of the net proceeds from the senior
secured notes, that was in place prior to our March 31, 2003 refinancing,
our fixed charges would have increased by $96 million and $19 million for
the year ended December 31, 2002 and the three months ended March 31, 2003,
respectively. In addition, our ratio of earnings to fixed charges would
have been 1.30 for the year ended December 31, 2002 and our earnings would
have been insufficient to cover our fixed charges by $99 million for the
three months ended March 31, 2003.

RISK FACTORS

Prospective investors should carefully consider the following information
in conjunction with the other information in this prospectus and the documents
incorporated by reference.

RISKS RELATED TO OUR RETAIL ENERGY OPERATIONS

WE MAY LOSE A SIGNIFICANT NUMBER OF OUR RETAIL RESIDENTIAL AND SMALL
COMMERCIAL CUSTOMERS IN THE HOUSTON METROPOLITAN AREA.

In June 1999, the Texas legislature adopted the Texas electric
restructuring law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow full retail competition.
Beginning in 2002, all classes of Texas customers of most investor-owned
electric utilities, and those of any municipal utility and electric cooperative
that opted to participate in the competitive marketplace, were able to choose
their retail electric provider. In January 2002, we began to provide retail
electric services to all customers of CenterPoint who did not take action to
select another retail electric provider. As an affiliated retail electric
provider, we are initially required to sell electricity to these Houston area
residential and small commercial customers at a specified price, or price to
beat, whereas other retail electric providers will be allowed to sell
electricity to these customers at any price. We are not permitted to offer
electricity to these customers at a price other than the price to beat until
January 2005, unless before that date the PUCT determines that 40% or more of
the amount of electric power that was consumed in 2000 by the relevant class of
customers in the Houston metropolitan area is committed to be served by retail
electric providers other than us. Because we are not able to compete for
residential and small commercial customers on the basis of price in the Houston
area, we may lose a significant number of these customers to other providers.

WE MAY LOSE A SIGNIFICANT PORTION OF OUR MARKET SHARE OF LARGE COMMERCIAL,
INDUSTRIAL AND INSTITUTIONAL CUSTOMERS IN TEXAS.

We are providing commodity services to the large commercial, industrial and
institutional customers previously served by CenterPoint who did not take action
to contract with another retail electric provider. In addition, we have signed
contracts to provide electricity and energy efficiency services to large
commercial, industrial and institutional customers, both in the Houston area, as
well as in other parts of the ERCOT Region. We or any other retail electric
provider can provide services to these customers at any negotiated price. The
market for these customers is very competitive, and any of these customers that
selects us to be their provider may subsequently decide to switch to another
provider at the conclusion of the term of their contract with us.

THE RESULTS OF OUR RETAIL ELECTRIC OPERATIONS IN TEXAS ARE LARGELY DEPENDENT
UPON THE AMOUNT OF HEADROOM AVAILABLE IN OUR PRICE TO BEAT. FUTURE ADJUSTMENTS
TO THE PRICE TO BEAT MAY BE INADEQUATE TO COVER OUR COSTS TO PURCHASE POWER TO
SERVE OUR RESIDENTIAL AND SMALL COMMERCIAL CUSTOMERS.

The results of our residential and small commercial retail electric
operations in Texas are largely dependent upon the amount of headroom available
in our price to beat. Headroom may be a positive or negative number. Our current
price is based on a wholesale energy supply cost component, or "fuel factor",
based on the ten trading-day average forward 12-month natural gas price of
$4.956 per MMbtu. The PUCT's current regulations allow us to request an
adjustment of our fuel factor based on the percentage change in the forward
price of natural gas or as a result of changes in the price of purchased energy
up to twice a year. As part of a request to change the fuel factor for changes
in purchased energy prices, we would have to show that the fuel factor must be
adjusted to restore the amount of headroom that existed at the time the initial
price to beat fuel factor was set by the PUCT. We cannot estimate with any
certainty the magnitude and frequency of the adjustments required, if any, and
the eventual impact of such adjustments on the amount of headroom available in
our price to beat. If this adjustment and any future adjustments to our price to
beat are inadequate to cover future increases in our costs to purchase

power to serve our price to beat customers or are delayed by the PUCT, our
business, results of operations, financial condition and cash flows could be
materially adversely affected.

In March 2003, the PUCT approved a revised price to beat rule. The changes
from the previous rule include an increase in the number of days used to
calculate the natural gas price average from ten to 20, and an increase in the
threshold of what constitutes a significant change in the market price of
natural gas and purchased energy from 4% to 5%, except for filings made after
November 15th of a given year that must meet a 10% threshold. The revised rule
also provides that the PUCT will, after reaching a determination of stranded
costs in 2004, make downward adjustments to the price to beat fuel factor if
natural gas prices drop below the prices embedded in the then-current price to
beat fuel factor. In addition, the revised rule also specifies that the base
rate portion of the price to beat will be adjusted to account for changes in the
non-bypassable rates that result from the utilities' final stranded cost
determination in 2004. Adjustments to the price to beat will be made following
the utilities' final stranded cost determination in 2004. At this time, we
cannot predict the impact of the changes on our financial condition or results
of operations. In March 2003, the PUCT approved our request to increase the
price to beat fuel factor for residential and small commercial customers based
on a 23.4% increase in the price of natural gas from our previous increase in
December 2002. In June 2003 we filed our second and final request for 2003 with
the PUCT to increase the price to beat fuel factor based on a 23.1% increase in
the price of natural gas. Our requested increase was based on an average forward
12-month natural gas price of $6.1000/Mmbtu during the twenty-day trading period
beginning May 14, 2003 and ending June 11, 2003. The requested increase
represents an increase of 9.2% in the total bill of a residential customer
using, on average, 12,000 kilowatt hours per year. There can be no assurances
such request will be approved.

CenterPoint has recently filed a petition with the PUCT to terminate excess
mitigation credits. Excess mitigation credits serve as a credit to CenterPoint's
non-bypassable charges to its customers. If excess mitigation credits are
eliminated without a concurrent revision in price to beat, headroom would be
adversely affected. We have until August 6, 2003 to intervene in this case;
certain parties have already done so. We do not know whether the PUCT will grant
CenterPoint's request or whether the price to beat will be revised if
CenterPoint's request is granted.

WE FACE STRONG COMPETITION FROM AFFILIATED RETAIL ELECTRIC PROVIDERS OF
INCUMBENT ELECTRIC UTILITIES AND OTHER COMPETITORS OUTSIDE OF HOUSTON.

In most retail electric markets outside the Houston area, our principal
competitor is the local incumbent electric utility company's retail affiliate.
These retail affiliates have the advantage of long-standing relationships with
their customers. In addition to competition from the incumbent electric
utilities' affiliates, we face competition from a number of other retail
electric providers, including affiliates of other non-incumbent electric
utilities, independent retail electric providers and, with respect to sales to
large commercial, industrial and institutional customers, independent power
producers and wholesale power providers acting as retail electric providers.
Some of these competitors are larger and better capitalized than we are.

OUR RETAIL ENERGY OPERATIONS ARE SUBJECT TO EXTENSIVE MARKET OVERSIGHT.
CHANGES TO MARKET PROTOCOLS OR NEW REGULATION COULD HAVE A MATERIAL ADVERSE
EFFECT ON OUR BUSINESS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH
FLOWS.

The ERCOT ISO, which oversees the ERCOT Region, has and may continue to
modify the market structure and other market mechanisms in an attempt to improve
market efficiency. Moreover, existing regulations may be revised or
reinterpreted and new laws and regulations may be adopted or become applicable
to our commercial activities. These actions could have a material adverse effect
on our results of operations, financial condition and cash flows.

PAYMENT DEFAULTS BY AND LITIGATION WITH OTHER RETAIL ELECTRIC PROVIDERS TO
ERCOT COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR BUSINESS, RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

In the event of a default by a retail electric provider of its payment
obligations to ERCOT, the portion of the obligation that is unrecoverable by
ERCOT from the defaulting retail electric provider is assumed by the remaining
market participants in proportion to each participant's load ratio share. As a
retail electric provider and market participant in ERCOT, we would pay a portion
of the amount owed to ERCOT should such a default occur, and ERCOT is not
successful in recovering such amounts. The default of a retail electric provider
in its obligations to ERCOT could have a material adverse effect on our
business, results of operations, financial condition and cash flows.

In March 2003, TCE, a retail electricity provider in the ERCOT market,
filed for bankruptcy protection. The bankruptcy court approved an agreement by
TCE to pay pre-petition amounts owed to ERCOT. TCE recently sought to reduce the
payments that it had previously agreed to make. At a hearing on July 14, 2003,
TCE and ERCOT announced an agreement, whereby TCE will continue to repay
prepetition amounts owed to ERCOT on a revised schedule. ERCOT will also draw
the down the remaining $2.5 million available under the letters of credit, with
the other letters of credit being previously released or drawn down by ERCOT. No
assurance can be given that TCE will be able to satisfy its obligations to
ERCOT. According to information provided by ERCOT, TCE has not paid such amounts
according to the schedule.

On July 7, 2003, TCE filed a lawsuit against us and several other
participants in the ERCOT power market in the Corpus Christi Federal District
Court for the Southern District of Texas. TCE alleges that the defendants
conspired to illegally fix and artificially increase the price of electricity in
violation of state and federal antitrust laws, including price fixing, fraud,
negligent misrepresentation, breach of fiduciary duty, defamation and
disparagement to its business reputation, breach of contract, and negligence,
along with other claims not alleged against us. The lawsuit seeks alleged
damages in excess of $500 million, exemplary damages, treble damages, interest,
costs of suit and attorneys' fees. The ultimate outcome of this lawsuit cannot
be predicted at this time.

WE ARE HEAVILY DEPENDENT UPON THIRD PARTY PROVIDERS OF CAPACITY AND ENERGY TO
SUPPLY OUR RETAIL OBLIGATIONS.

We do not own sufficient generating resources in Texas to supply our retail
business. The capacity and energy to supply our retail business is purchased at
market prices from a variety of suppliers under contracts with varying terms.
Our retail customers are concentrated in the Houston metropolitan area, and
there is limited ability to serve these customers with generation located
outside the Houston metropolitan area. Texas Genco, located in the Houston
congestion zone, is the largest supplier of capacity and energy for our retail
business and is likely to remain our largest supplier for the foreseeable
future. There is a significant risk that our business, results of operations,
financial condition and cash flows could be materially adversely affected if we
are not able to purchase the capacity and energy from Texas Genco or otherwise
obtain sufficient capacity and energy required to serve our customers. The
failure of any of our third party suppliers to perform under the terms of
existing or future contracts could have a material adverse effect on our results
of operations, financial condition and cash flows.

WE MAY BE REQUIRED TO MAKE A SUBSTANTIAL PAYMENT TO CENTERPOINT IN 2004.

To the extent that our price to beat for electric service to residential
and small commercial customers in CenterPoint's Houston service territory during
2002 and 2003 exceeds the market price of electricity, we may be required to
make a significant payment to CenterPoint in 2004. As of March 31, 2003, our
estimate for the payment related to residential customers is between $160
million and $190 million, with a most probable estimate of $175 million. Unless
we are able to make this payment out of operating cash flows, we will be
required to incur additional debt to finance the payment.

Currently, we believe that the 40% test for small commercial customers will
be met and we will not make a payment related to those customers. If the 40%
test is not met related to our small commercial customers and a payment is
required, we estimate this payment would be approximately $30 million.

WE RELY ON THE INFRASTRUCTURE OF TRANSMISSION AND DISTRIBUTION UTILITIES AND
THE ERCOT ISO TO TRANSMIT AND DELIVER ELECTRICITY TO OUR RETAIL CUSTOMERS AND
TO OBTAIN INFORMATION ABOUT OUR RETAIL CUSTOMERS. IN ADDITION, WE RELY ON THE
RELIABILITY OF OUR OWN INFRASTRUCTURE AND SYSTEMS TO PERFORM ENROLLMENT AND
BILLING FUNCTIONS. ANY INFRASTRUCTURE FAILURE COULD NEGATIVELY IMPACT OUR
CUSTOMERS' SATISFACTION AND COULD HAVE A MATERIAL NEGATIVE IMPACT ON OUR
EARNINGS.

We are dependent on transmission and distribution utilities for maintenance
of the infrastructure through which we deliver electricity to our retail
customers. Any infrastructure failure that interrupts or impairs delivery of
electricity to our customers could negatively impact the satisfaction of our
customers with our service and could have a material adverse effect on our
results of operations, financial condition and cash flow. Additionally, we are
dependent on the transmission and distribution utilities for performing service
initiations and changes, and for reading our customers' energy meters. We are
required to rely on the transmission and distribution utility or, in some cases,
the ERCOT ISO, to provide us with our customers' information regarding energy
usage, and we may be limited in our ability to confirm the accuracy of the
information. The provision of inaccurate information or delayed provision of
such information by the transmission and distribution utilities or the ERCOT ISO
could have a material adverse effect on our business, results of operations,
financial condition and cash flow. In addition, any operational problems with
our new systems and processes could similarly have a material adverse effect on
our business, results of operations, financial condition and cash flow. For
additional information, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Retail Energy" for the three years ended
December 31, 2000, 2001 and 2002 and for the three months ended March 31, 2002
and 2003, incorporated by reference herein.

THE ERCOT ISO HAS EXPERIENCED A NUMBER OF PROBLEMS WITH ITS INFORMATION
SYSTEMS SINCE THE ADVENT OF COMPETITION IN THE TEXAS MARKET THAT HAVE RESULTED
IN DELAYS IN SWITCHING CUSTOMERS AND RECEIVING FINAL SETTLEMENT INFORMATION
FOR CUSTOMER ACCOUNTS. OUR OPERATING RESULTS MAY BE ADVERSELY AFFECTED IF
THESE PROBLEMS ARE NOT ALLEVIATED.

The ERCOT ISO is the independent system operator responsible for
maintaining reliable operations of the bulk electric power supply system in the
ERCOT Region and for acting as a central agent for the registration of customers
with their chosen retail electric supplier. Its responsibilities include
ensuring that information relating to a customer's choice of retail electric
provider, including data needed for ongoing servicing of customer accounts, is
conveyed in a timely manner to the appropriate parties. Problems in the flow of
information between the ERCOT ISO, the transmission and distribution utilities
and the retail electric providers have resulted in delays and other problems in
enrolling and billing customers. While the flow of information has improved
materially over the course of the first year of full market choice operations,
remaining system and process problems are still being addressed. When customer
enrollment transactions are not successfully processed by all involved parties,
ownership records in the various systems supporting the market are not
synchronized properly and subsequent transactions for billing and settlement are
adversely affected. The impact can include us not being the electric
provider-of-record for intended or agreed upon time periods, delays in receiving
customer consumption data from the ERCOT ISO that is necessary for billing, as
well as the incorrect application of rates or prices and imbalances in our
electricity supply and actual sales.

The ERCOT ISO is also responsible for handling, scheduling and settlement
for all electricity supply volumes in the ERCOT Region. The ERCOT ISO plays a
vital role in the collection and dissemination of metering data from the
transmission and distribution utilities to the retail electric providers. We and
other retail electric providers schedule volumes based on forecasts, which are
based, in part, on information supplied by the ERCOT ISO. To the extent that
these amounts are not accurate or timely, we could have incorrectly estimated
our scheduled volumes and supply costs.

The ERCOT ISO has been submitting final volume settlements to us, primarily
for the January 2002 time period. Their records indicate that our customers
utilized greater volumes than what our records indicate. We have disputed the
volume differences and the ERCOT ISO has denied these disputes. We are currently
pursuing the ERCOT Alternate Dispute Resolution mechanism to resolve the
differences,

The ERCOT ISO charges various fees to the retail electric providers based
primarily on each market participant's share of the volume of electricity
delivered. These fees have increased substantially during the past six months.
In addition, we may be billed a disproportionate share of these total fees if
the ERCOT ISO's records indicate that our volumes delivered were greater than
the volumes our records indicate.

For additional information regarding settlement issues, see "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Retail Energy" for the three years ended December 31, 2000, 2001
and 2002 and for the three months ended March 31, 2002 and 2003, incorporated by
reference herein.

RISKS RELATED TO OUR WHOLESALE ENERGY OPERATIONS

OUR RESULTS OF OPERATIONS WILL BE IMPACTED BY THE SALE OF OUR DESERT BASIN
PLANT OPERATIONS AND COULD BE IMPACTED BY A POSSIBLE FUTURE GOODWILL
IMPAIRMENT RELATED TO OUR WHOLESALE ENERGY SEGMENT.

On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant, located in Casa Grande, Arizona, to SRP for
$289 million. Desert Basin, a combined-cycle facility that we developed, started
commercial operation in 2001 and is currently providing all of its power to SRP
under a 10-year power purchase agreement, which will be terminated in connection
with the sale. The Desert Basin plant is the only operation of REDB, an indirect
wholly-owned subsidiary of ours. The transaction is subject to regulatory
approvals, including the FERC, and certain third-party consents and approvals.
The transaction is expected to close by the end of 2003. We intend to use the
net proceeds of approximately $287 million to prepay indebtedness of our senior
secured debt or for the possible acquisition of direct or indirect ownership
interests in assets currently owned by Texas Genco.

We will recognize a loss on the sale of our Desert Basin plant operations
in the third quarter of 2003 and in connection with the anticipated sale, we
will report the assets and liabilities to be sold as discontinued operations
effective July 2003. We preliminarily estimate the loss on disposition to be
approximately $75 million ($68 million after-tax), consisting of a loss of $18
million ($11 million after-tax) on the tangible assets and liabilities
associated with our actual investment in the Desert Basin plant operations and a
loss of $57 million ( pre-tax and after-tax due to the non-deductibility of
goodwill for income tax purposes) relating to the allocated goodwill of our
wholesale energy reporting unit. Determination of the actual amount of goodwill
to be allocated to this business requires developing an updated estimate of the
fair value of our wholesale energy reporting unit, which is expected to be
completed by the end of the third quarter of 2003. When this information is
available, the amount of goodwill to be allocated can be finalized and will
likely vary from the preliminary estimate noted above. For example, if the
estimated fair value of our wholesale energy segment increases or decreases by
10% from our most recent estimate as used in our November 1, 2002 impairment
analyses, then the loss on the sale of the Desert Basin plant operations related
to the goodwill allocated to it, will decrease or increase, respectively, by
approximately $5 million and $6 million, respectively. Our November 1, 2002
goodwill impairment test indicated that the fair value of our wholesale energy
reporting unit exceeded its carrying value by approximately five percent.

This anticipated sale of our Desert Basin plant operations requires us, in
accordance with SFAS No. 142, to allocate a portion of the goodwill in the
wholesale energy reporting unit to the Desert Basin plant operations on a
relative fair value basis as of July 2003 in order to compute the gain or loss
on disposal. SFAS No. 142 also requires us to test the recoverability of
goodwill in our remaining wholesale energy reporting unit as of July 2003. After
the allocation of goodwill to the Desert Basin plant operations, our wholesale
energy segment's remaining goodwill is estimated to be approximately $1.4
billion, which is being tested for impairment effective July 2003. The
assessment of goodwill requires developing an

updated estimate of the fair value of our wholesale energy reporting unit, which
is expected to be completed by the end of the third quarter of 2003.

During 2002 and 2003, margins on the sales of electricity in our industry
have decreased substantially. In response to continued depressed prices for
electric energy, capacity and ancillary services across much of the United
States and our current judgments regarding the state of the wholesale
electricity markets, we are in the process of evaluating our strategies and
activities. During the first quarter of 2003, we decided to exit our proprietary
trading activities. We anticipate internally restructuring certain commercial,
operational and support groups to reduce costs. In addition, we are evaluating
(a) further changes in our market strategies, (b) mothballing certain power
generation facilities, (c) deferring and/or materially reducing maintenance of
power generation facilities and (d) divesting of certain assets. Also, we are
evaluating the method of projecting future cash flows from our wholesale energy
segment operations. In connection with this effort, our future cash flow
projections and plans will be revised.

If the assumptions and estimates underlying our July 2003 goodwill
impairment evaluation for our wholesale energy reporting unit differ adversely
from the assumptions previously used due to changes in our wholesale energy
market outlook, strategies and activities, it is possible that a material amount
of goodwill might be impaired and any such impairment would be reflected in the
third quarter of 2003.

As noted previously, our goodwill impairment analysis estimates the fair
value of our reporting units using a combination of approaches, including an
income approach based on internal plans, a market approach based on transactions
in the marketplace for comparable types of assets, and a comparable public
company approach. The income approach used in our analysis is a discounted cash
flow analysis based on our internal plans and contains numerous assumptions made
by management, any number of which if changed could significantly affect the
outcome of the analysis. We believe that the income approach is the most
subjective of the approaches.

Our historical impairment analyses for our wholesale energy reporting unit
included numerous assumptions, including but not limited to:

- increases in demand for power that will result in the tightening of
supply surpluses and additional capacity requirements over the next three
to eight years, depending on the region;

- improving prices in electric energy, ancillary services and existing
capacity markets as the power supply surplus is absorbed; and

- our expectation that more balanced, fair market rules will be
implemented, which provide for the efficient operations of unregulated
power markets, including capacity markets or mechanisms in regions where
they currently do not exist.

The internal cash flow analyses used in our November 1, 2002 impairment
analysis ranged over a period of ten to 15 years with an assumed terminal value
for the value of our operations at the end of the analysis of an EBITDA
(earnings from continuing operations before depreciation and amortization,
interest expense, interest income and income taxes) multiple of primarily 6 to
7.5. For our annual impairment test as of November 1, 2002, these after-tax cash
flows (excluding interest) were discounted back to the date of the analysis at
an appropriate risk-adjusted discount rate of primarily 9% in order to determine
the fair value of the reporting unit under the income approach. The income
approach was weighted along with the other two approaches to determine the fair
value of the reporting unit. Our November 1, 2002 analyses assumed that the
demand for power would rise at an annual rate of approximately 2% over the next
several years. This growth over time was assumed to result in decreased reserve
margins in the areas where we operate. As reserve margins decrease, power
generation margins were assumed to rise substantially over time to a level
sufficient to attract new capacity (estimated to be in 2007 and 2008). We
assumed that this level of prices would be such that companies will build new
generation facilities and these new facilities will be able to cover all of
their operating expenses and yield an internal rate of return on their
investment of 9%.

These assumptions are consistent with the view that long run market prices
will reach levels sufficient to support an adequate rate of return on the
construction of new power generation, which we believe will be required to meet
increased demand for power. This view is currently being challenged in certain
markets as market rules unfold that provide more favorable returns to new
capacity entering the market than is provided to existing capacity.

Our current impairment analysis will reconsider these and other assumptions
including: estimates of future market prices, valuation of plant and equipment,
growth, competition and many other factors as of the determination date. The
resulting impairment analysis is highly dependent on these underlying
assumptions.

OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS ARE SUBJECT TO
MARKET RISKS, THE IMPACT OF WHICH WE CANNOT FULLY MITIGATE.

As part of our merchant electric generation business, we sell electric
energy, capacity and ancillary services and purchase fuel under short and
long-term contractual obligations and through various spot markets. We are not
guaranteed any rate of return on our capital investments through cost of service
rates, and our results of operations, financial condition and cash flows from
these businesses are subject to market risks which can be partially mitigated by
hedging long-term sales agreements and other management actions. However, a
substantial portion of market risk remains beyond our control. These market
risks include commodity price risk, counterparty risk, credit risk, transmission
risk and competitor actions.

WE RELY ON MARKET LIQUIDITY AND THE ESTABLISHMENT OF VALID PRICING TO PROPERLY
MANAGE OUR RISKS.

Our commercial businesses depend on sufficient market participation to
establish market liquidity and valid pricing to properly manage the risks
inherent in our businesses. The recent reduction in the number of market
participants has significantly decreased market liquidity and may impair our
ability to manage business risks. In addition, such a reduction may increase our
management's reliance on internal models for decision-making. Our internal
models may not accurately represent the markets in which we participate,
potentially causing us to make incorrect decisions. These factors could have a
material adverse effect on our results of operations, financial condition and
cash flows.

WE MAY NOT BE ABLE TO SATISFY THE GUARANTEES AND INDEMNIFICATION OBLIGATIONS
RELATING TO OUR COMMERCIAL ACTIVITIES IF THEY BECOME DUE AT THE SAME TIME.

In connection with our commercial businesses, we guarantee or indemnify the
performance of a significant portion of the obligations of certain of our
subsidiaries. For example, we routinely guarantee the obligations of Reliant
Energy Services and other subsidiaries of ours under substantially all of their
gas and electricity trading, marketing and origination contracts. The
obligations underlying these guarantees and indemnities are recorded on our
consolidated balance sheet as trading and marketing liabilities and non-trading
derivative liabilities. These obligations make up a significant portion of these
line items. In addition, we have, from time to time, executed guarantees of the
obligations of our subsidiaries under leases of real property, financing
documents and certain other miscellaneous contracts such as long-term turbine
maintenance contracts. Some of these guarantees and indemnities are for fixed
amounts, others have a fixed maximum amount and others do not specify a maximum
amount. If we were unable to successfully negotiate lower amounts or alternative
arrangements, we would not be able to satisfy all of these guarantees and
indemnification obligations if they were to all come due at the same time. For
additional information regarding our guarantees and indemnification obligations,
see note 14(f) to our consolidated financial statements incorporated by
reference herein.

WE RELY ON POWER TRANSMISSION AND NATURAL GAS TRANSPORTATION FACILITIES THAT
WE DO NOT OWN OR CONTROL. IF THESE FACILITIES FAIL TO PROVIDE US WITH ADEQUATE
TRANSMISSION CAPACITY, WE MAY NOT BE ABLE TO DELIVER OUR WHOLESALE POWER TO
OUR CUSTOMERS OR RECEIVE NATURAL GAS PRODUCTS AT OUR FACILITIES.

We depend on power transmission and distribution and natural gas
transportation facilities owned and operated by utilities and others to deliver
energy products to our customers. Our customers in turn either consume these
products or deliver them to the ultimate consumer. If transmission or
transportation is disrupted, or the capacity is inadequate, our ability to sell
and deliver our products may be hindered.

AS A RESULT OF EVENTS IN CALIFORNIA OVER THE PAST FEW YEARS, OUR WHOLESALE
POWER OPERATIONS IN OUR WEST REGION HAVE EXPERIENCED DELAYS IN THE COLLECTION
OF RECEIVABLES AND ARE SUBJECT TO UNCERTAINTY, INCLUDING POTENTIALLY MATERIAL
REFUND OBLIGATIONS, RELATING TO ONGOING LITIGATION AND GOVERNMENTAL
PROCEEDINGS RELATING TO OUR ACTIVITIES IN THE ELECTRICITY AND GAS MARKETS.

We are defendants in several class action lawsuits and other lawsuits filed
against us and a number of other companies that either owned generation plants
in California or sold electricity in California markets. These lawsuits
challenge the prices for wholesale electricity in California during parts of
2000 and 2001.

In particular, in FERC Docket Nos. EL00-95-000, et al., the FERC has
established a refund proceeding to reset the market clearing prices for sales
into the Cal ISO and Cal PX spot markets for the period from October 2000 to
mid-June 2001. Although this proceeding has not yet concluded, we are likely to
have a substantial net refund obligation as a result of this proceeding, which
we estimate to be between approximately $104 million and $230 million for energy
sales in California. For information regarding reserves against receivables, the
FERC refund methodology and uncertainty in the California wholesale energy
market, see note 13(e) to our interim consolidated financial statements
incorporated by reference herein.

We and other companies are also the subject of continuing investigations by
the FERC into potential manipulation of electric and natural gas prices in the
West region for the period from January 2000 to June 2001, as well as alleged
economic withholding. Refunds could be ordered if the FERC finds that we have
engaged in strategies that violated Cal ISO tariffs, or were otherwise unlawful
under the FPA. On March 26, 2003, the FERC issued a Show Cause order proposing
to revoke the market-based rate authority of Reliant Energy Services as a result
of certain trades with BP Energy Company at the Palo Verde trading hub in
Arizona. In the Show Cause order, the FERC established a refund effective date
of June 2, 2003. The significance of the refund effective date is that sales by
Reliant Energy Services subsequent to the refund date are subject to potential
refund in the event Reliant Energy Services' market-based rate authority is
revoked. The FERC also indicated in the Show Cause order an intention to act on
the proceeding by July 31, 2003. On July 18, 2003, the FERC issued a consent
order to BP Energy Company that required BP Energy Company to pay $3 million and
to pass its electricity sales through FERC review for the next six months, among
other things. BP Energy Company's settlement with the FERC may increase the
pressure on the FERC to act with respect to Reliant Energy Services' market-
based rate authority. However, we can not assure you that the FERC will handle
Reliant Energy Services' proceeding in the same manner and may conclude that,
despite the BP Energy Company settlement, revocation of market-based rate
authority would be appropriate. We are unable to predict with certainty whether
the FERC will revoke Reliant Energy Services' market-based rate authority, or
the market-based rate authority of any of Reliant Energy Services' affiliates,
or the extent of potential adverse consequences to us that would result from any
such revocation. There is the potential for serious harm to us if Reliant Energy
Services' market-based rate authority is revoked, including potential impairment
of our ability to access the debt and capital markets, loss of valuation of
assets, and defaults and/or triggering of collateral posting requirements.

Although the FERC's investigation into allegations of physical withholding
by owners of generating assets, including Reliant Resources, is still ongoing,
the FERC has approved a settlement agreement to resolve claims related to
alleged physical withholding by us on two days in June 2000. We agreed to refund
$14 million, found by the FERC staff to be the maximum amount by which the Cal
ISO day-

ahead market could have been affected by our actions. That settlement agreement
does not resolve any possible incidents of physical withholding.

Also, on March 26, 2003, the FERC staff issued a report on its
investigation into electric and gas prices in the West, and concluded that we
had engaged in "churning" of gas at the Topock delivery point over an eight
month period. While the FERC staff found that our gas trading practices inflated
the market prices for gas at that delivery point, it further found that those
practices did not violate any law or regulation and imposed no refund obligation
or penalty. However, the findings in the FERC staff report have formed the basis
for (1) the assertion by certain parties in the FERC refund proceedings that our
actions caused an increase in gas and electric prices of $2.75 billion and (2)
two class action suits to be filed against us in the Superior Court of
California. At least four lawsuits have been subsequently filed by various
parties, two of which are class action lawsuits.

Acting on recommendations in the March 26, 2003 report, the FERC on June
25, 2003 initiated an investigation of bids greater than $250/MWh during the
period from May 1, 2000 through October 2, 2000 to determine if any such bids
were the result of improper market conduct. On July 2, 2003, the FERC staff
issued a set of data requests in connection with the investigation. We are
cooperating fully with the FERC staff and will respond to the data requests on
July 24, 2003. Also on June 25, 2003, the FERC initiated a proceeding against us
and numerous other wholesale market participants to determine whether certain
trading activities identified in reports filed by the Cal ISO violated certain
market protocols and are subject to disgorgement of profits earned on such
activities. The actual scope of the proceeding has not been established, but we
will defend against all allegations of improper activities. The FERC has noticed
a Plenary Conference for July 24, 2003 to discuss procedural issues for
evidentiary hearings and the possibility of settlement negotiations.

The Nevada Power Company and PacifiCorp are counterparties to certain of
our long-term bilateral contracts, and have filed challenges to those contracts
at the FERC based on the alleged impact of spot market dysfunctions in Western
power markets in 2000 and 2001 on long-term forward markets. On June 25, 2003,
the FERC voted to approve the issuance of orders denying these challenges.
However, if the FERC determines on rehearing, or on remand on appeal to the
United States Court of Appeals, that the rates under any of these long-term
bilateral contracts should be modified as a result of the effect of such market
dysfunctions, then we could be subject to refund obligations.

On June 25, 2003, the FERC voted to approve the issuance of Orders to Show
Cause relating to certain alleged gaming and/or anomalous market behavior in
alleged violation of the Cal ISO and Cal PX tariffs by 43 market participants
during the period from January 1, 2000 through June 20, 2001, including Reliant
Resources, REPG and Reliant Energy Services, in Docket No. EL03-170-000. The
FERC stated that evidence relating to the Show Cause orders would be heard in a
trial-type evidentiary hearing before an administrative law judge. The Reliant
Resources entities named in the Show Cause order will have an opportunity to
bring forth evidence in the hearing to show that they did not engage in gaming
and other anomalous behavior. If the alleged violations are proved, the Reliant
Resources entities could be subject to disgorgement of profits, and certain
other non-monetary remedies that could include revocation of market-based rate
authority and/or additional required provisions in codes of conduct. The FERC
also issued an order instituting an internal FERC Investigation of Anomalous
Bidding Behavior and Practices in the Western Markets in Docket No. IN03-10-000.
In this investigation, the FERC will review evidence of alleged economic
withholding of generation. Specifically, the FERC determined that all bids into
the Cal PX and Cal ISO markets for more than $250/MW for the time period from
May 1, 2000 through October 1, 2000 should be considered prima facie excessive.
The FERC may issue additional data requests to market participants. To the
extent that any Reliant Resources entities are determined to have engaged in
improper bidding, we may be subject to disgorgement of alleged profits, and
other non-monetary actions, including possible revocation of market-based rate
authority and/or additional required provisions in codes of conduct.

In addition to the FERC investigations, several state and other federal
regulatory investigations are ongoing in connection with the wholesale
electricity and natural gas prices in California and neighboring

Western states to determine the causes of the high prices and potentially to
recommend remedial action. On July 9, 2003, the City of Los Angeles announced
that it had filed suit against us and one of our employees in the United States
District Court for the Central District of California. The lawsuit alleges that
we conspired to manipulate the price for natural gas in breach of our contract
to supply the Los Angeles Department of Water and Power with natural gas and
acted in violation of federal and state antitrust laws, the federal Racketeer
Influenced and Corrupt Organization Act and the California False Claims Act. The
lawsuit seeks treble damages for the alleged overcharges for gas purchased by
the Los Angeles Department of Water and Power of an estimated $218 million,
interest, costs of suit and attorneys' fees.

We may also face more stringent state regulations in the future. There have
been efforts in California to repeal deregulation. Also, a new California state
statute may give the CPUC authority to regulate the operations of our California
generating subsidiaries, beyond the existing state regulation regarding
environmental and other health and safety matters. The CPUC has recently
initiated the process of establishing the methods through which these new
requirements will be administered.

As these investigations proceed, additional matters could be discovered
that could result in the imposition of restrictions on our businesses, fines,
penalties or other adverse events. Furthermore, as events occur to other
companies in the retail and wholesale energy industry that lead to
investigations of such companies by regulatory authorities, we may also be
investigated by such regulatory authorities if they decide to broaden their
investigation to comparable companies in the industry.

OUR WHOLESALE ENERGY SEGMENT IS SUBJECT TO EXTENSIVE MARKET REGULATION.
CHANGES IN THESE REGULATIONS COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR
BUSINESS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

The FERC, which has jurisdiction over wholesale power rates, as well as
independent system operators that oversee some of these markets, has imposed and
may continue to impose price limitations, bidding rules and other mechanisms in
an attempt to address some of the price volatility in these markets and mitigate
market price fluctuations. These actions, along with potential changes to
existing mechanisms, could have a material adverse effect on our results of
operations, financial condition and cash flows.

We operate in a regulatory environment that is undergoing significant
changes as a result of varying restructuring initiatives at both the state and
federal levels. New regulatory policies, which may have a significant impact on
our industry, are now being developed and we cannot predict the future direction
of these changes or the ultimate effect that this changing regulatory
environment will have on our business.

Moreover, existing regulations may be revised or reinterpreted and new laws
and regulations may be adopted or become applicable to our facilities or our
commercial activities. Such future changes in laws and regulations may have a
detrimental effect on our business. In this connection, state officials, the Cal
ISO and the investor-owned utilities in California have argued to the FERC that
our California generating subsidiaries should not continue to have market-based
rate authority. (As discussed further above, in addition to these requests, the
FERC has also recently issued a number of "Show Cause" orders against various
market participants in the California markets, including a number of Reliant
Resources entities. These "Show Cause" orders relate to alleged market
manipulation and/or anomalous bidding practices, and could result in either
disgorgement of alleged profits or the loss of market-based rate authority for
various Reliant Resources entities. The FERC has also initiated an investigation
into economic withholding allegations that could result in similar remedies.) In
the event the market-based rate authority of any Reliant Resources entity is
revoked, the FERC has not provided guidance on how cost-based rates might be
implemented in a market regime. We cannot predict what actions the FERC may take
in the future. The impact of receiving cost-based rates on our California
portfolio is also not predictable given that the numerous details of any such
implementation are unknown at this time.

In addition to the FERC investigations, several state and other federal
regulatory investigations are ongoing in connection with wholesale electricity
prices to determine the causes of the high prices and potentially to recommend
remedial action. As these investigations proceed, additional matters could be
25

discovered that could result in the imposition of restrictions on our business,
fines, penalties or other adverse actions.

The Cal ISO has undertaken, at the FERC's direction, a market redesign
process that includes an ongoing obligation to offer available capacity in Cal
ISO markets, a $250 per MWh price cap, as well as "automated" mitigation of all
bids when any zonal clearing price for balancing energy exceeds $91.87 per MWh.
The automated mitigation is only applied to bids that exceed certain reference
prices and that would significantly increase the market price. However, in
February 2003, the Cal ISO stated that it intends to appeal in federal court the
FERC's decision regarding the application of automated mitigation to local
market power situations. While the FERC has adopted similar thresholds for both
local and system market power, Cal ISO is seeking to have a more restrictive
procedure applied to local market power. Additional features of the California
market redesign to be implemented in the future include a revised market
monitoring and mitigation structure, a revised congestion management mechanism
and an obligation for load-serving entities in California to maintain capacity
reserves. A new California state statute purports to give the CPUC new power to
regulate the operations and maintenance practices of our California generating
subsidiaries, beyond the existing state regulation, regarding environmental and
other health and safety matters. The CPUC has recently initiated the process of
establishing the methods through which these new requirements will be
administered.

The NY Market is subject to significant regulatory oversight and control.
The results of our operations in the NY Market are dependent on the continuance
of the current regulatory structure. The rules governing the current regulatory
structure are subject to change. We cannot assure you that we will be able to
adapt our business in a timely manner in response to any changes in the
regulatory structure, which could have a material adverse effect on our
financial condition, results of operations and cash flows. The primary
regulatory risk in this market is associated with the oversight activity of the
New York Public Service Commission, the NYISO and the FERC. Our assets located
in New York are subject to "lightened regulation" by the New York Public Service
Commission, including provisions of the New York Public Service Law that relate
to enforcement, investigation, safety, reliability, system improvements,
construction, excavation, and the issuance of securities. Because lightened
regulation was accomplished administratively, it could be revoked. The NYISO has
the ability to revise wholesale prices, which could lead to delayed or disputed
collection of amounts due to us for sales of electric energy and ancillary
services. The NYISO may in some cases, subject to the FERC approval, also impose
cost-based pricing and/or price caps. The NYISO has implemented automated
mitigation procedures under which day-ahead energy bids will be automatically
reviewed. If bids exceed certain pre-established thresholds and have a
significant impact on the market-clearing price, the bids are then reduced to a
pre-established market-based or negotiated reference bid. The NYISO has also
adopted, at the FERC's direction, more stringent mitigation measures for all
generating facilities in transmission-constrained New York City.

On June 25, 2003, the FERC announced that it was proposing new rules to
prevent market abuse. The rules would prohibit certain transactions and
practices under sellers' market-based rate electric tariffs and blanket gas
certificates. The new rules relate to market manipulation, communications,
reporting and record retention. Under the proposed rules, a seller found to have
engaged in prohibited behavior would be subject to disgorgement of unjust
profits and non-monetary remedies such as revocation of the seller's
market-based rate authority or blanket certificate authority. If the FERC adopts
its proposed market behavior rules, our future earnings may be adversely
affected by an open-ended refund obligation on sales at market-based rates or
under blanket certificate authority to the extent we were determined to have
violated the new tariff provisions required by the proposed rule.

The FERC also instituted a SMD rulemaking proceeding that proposes to
eliminate discrimination in transmission service and to standardize electricity
market design. The FERC's SMD proceeding would establish standardized
transmission service throughout the United States, a standard wholesale electric
market design, including forward and spot markets for energy and an ancillary
services market. Further, this proceeding is also expected to provide all RTOs
specifications regarding the entities that administer these markets and how
these entities perform market monitoring and mitigation. While we believe SMD is
a positive development for our business, significant opposition to SMD has been
voiced, and we cannot
26

predict at this time whether SMD will be adopted as proposed or what effect
standard market design, in whatever form it may take if and when it is adopted,
would have on our business growth prospects and financial results.

The FERC's RTO initiative, which began in May 1999, is making progress in
all areas of the country. If RTOs are established as envisioned by the FERC,
"rate pancaking," or multiple transmission charges that apply to a single
point-to-point delivery of energy will be eliminated within a region, and
wholesale transactions within the region and between regions will be
facilitated. The end result could be a more competitive, transparent market for
the sale of energy and a more economic and efficient use and allocation of
resources. However, considerable opposition exists in some regions of the United
States to the development of RTOs as envisioned by the FERC, and the timing for
completion of the developing RTOs is uncertain.

Additionally, federal legislative initiatives have been introduced and
discussed to address the problems being experienced in some power markets and to
enhance or limit the FERC authority. We cannot predict whether such proposals
will be adopted or their impact on industry restructuring. If the trend towards
competitive restructuring of the wholesale power markets is reversed,
discontinued or delayed, the business growth prospects and financial results of
our wholesale energy and retail energy segments could be adversely affected.

OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND THE COST
OF COMPLIANCE WITH NEW ENVIRONMENTAL LAWS COULD ADVERSELY IMPACT OUR
PROFITABILITY.

Our wholesale energy segment is subject to extensive environmental
regulation by federal, state and local authorities. We are required to comply
with numerous environmental laws and regulations, and to obtain numerous
governmental permits in operating our facilities, a number of which are
coal-fired and subject to particularly intense regulatory oversight. We may
incur significant additional costs to comply with these requirements. If we fail
to comply with these requirements, we could be subject to civil or criminal
liability and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to
us or our facilities, and future changes in environmental laws and regulations
could occur, including potential regulatory and enforcement developments related
to air emissions. If any of these events occur, our business, results of
operations and financial condition and cash flows could be materially adversely
affected. For more information regarding compliance with environmental laws, see
"Our Business -- Environmental Matters".

THE MAJORITY OF OUR HYDROELECTRIC FACILITIES ARE REQUIRED TO BE LICENSED UNDER
THE FEDERAL POWER ACT. ANY FAILURE TO OBTAIN OR MAINTAIN A REQUIRED LICENSE
FOR ONE OR MORE OF OUR HYDROELECTRIC FACILITIES COULD HAVE AN ADVERSE IMPACT
ON US.

The Federal Power Act gives the FERC exclusive authority to license
non-federal hydroelectric projects on navigable waterways and federal lands. The
FERC hydroelectric licenses are issued for terms of 30 to 50 years. Some of our
hydroelectric facilities, representing approximately 90 MW of capacity, have
licenses that expire within the next ten years. Facilities that we own
representing approximately 160 MW of capacity have new or initial license
applications pending before the FERC. Upon expiration of a FERC license, the
federal government can take over the project and compensate the licensee, or the
FERC can issue a new license to either the existing licensee or a new licensee.
In addition, upon license expiration, the FERC can decommission an operating
project and even order that it be removed from the river at the owner's expense.
In deciding whether to issue a license, the FERC gives equal consideration to a
full range of licensing purposes related to the potential value of a stream or
river. It is not uncommon for the relicensing process to take between four and
ten years to complete. Generally, the relicensing process begins at least five
years before the license expiration date and the FERC issues annual licenses to
permit a hydroelectric facility to continue operations pending conclusion of the
relicensing process. We expect that the FERC will issue to us new or initial
hydroelectric licenses for all the facilities with pending applications.
Presently, there are no applications for competing licenses and there is no
indication that the FERC will decommission or order any of the projects to be
removed.
27

INCREASING COMPETITION IN WHOLESALE POWER MARKETS MAY ADVERSELY AFFECT OUR
RESULTS OF OPERATIONS, FINANCIAL CONDITION, CASH FLOWS AND MAY REQUIRE
ADDITIONAL LIQUIDITY TO REMAIN COMPETITIVE.

Our wholesale energy segment competes with other energy merchants. In order
to successfully compete, we must have the ability to aggregate supplies at
competitive prices from different sources and locations and must be able to
efficiently utilize transportation services from third-party pipelines and
transmission services from electric utilities. We also compete against other
energy merchants on the basis of our relative skills, financial position and
access to credit sources. Energy customers, wholesale energy suppliers and
transporters often seek financial guarantees and other assurances that their
energy contracts will be satisfied. If price information becomes increasingly
available in the energy marketing and trading business, we anticipate that our
operations will experience greater competition and downward pressure on per-unit
profit margins. In addition, our merchant asset business is constrained by our
liquidity, our access to credit and the reduction in market liquidity. Other
companies with which we compete may not have similar constraints.

OUR BUSINESS OPERATIONS AND HEDGING ACTIVITIES EXPOSE US TO THE RISK OF
NON-PERFORMANCE BY COUNTERPARTIES.

Our trading, marketing and risk management services operations are exposed
to the risk that counterparties who owe us money or physical commodities and
services, such as power, natural gas or coal, will not perform their
obligations. Should the counterparties to these arrangements fail to perform, we
might be forced to acquire alternative hedging arrangements or replace the
underlying commitment at then-current market prices. In this event, we might
incur additional losses to the extent of amounts, if any, already paid to the
counterparties.

As a result of recent events, including the credit crisis in the merchant
energy sector, the bankruptcy filings of NRG Energy Inc., PG&E National Energy
Group, Inc. (NEG) and Mirant Corp., the decreasing liquidity in our trading
markets and the related downgrading of our credit ratings and the credit ratings
of many of our trading counterparties to below investment grade, we have been
required to enter into trading and other commercial arrangements with higher
risk counterparties than those with whom we have typically contracted in the
past. These arrangements, coupled with the credit crisis in our sector, have
increased our exposure to the risk of non-performance by counterparties who owe
us money or physical commodities.

OPERATION OF POWER GENERATION FACILITIES INVOLVES SIGNIFICANT RISKS THAT COULD
NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS AND CASH FLOWS.

Our wholesale energy segment is exposed to risks relating to the breakdown
or failure of equipment or processes, fuel supply interruptions, shortages of
equipment, material and labor, and operating performance below expected levels
of output or efficiency. Significant portions of our facilities were constructed
many years ago. Older generating equipment, even if maintained in accordance
with good engineering practices, may require significant capital expenditures to
add to or upgrade equipment to keep it operating at peak efficiency, to comply
with changing environmental requirements, or to provide reliable operations.
Such changes could affect our operating costs. Any unexpected failure to produce
power, including failure caused by breakdown or forced outage, could have a
material adverse effect on our results of operations, financial condition and
cash flows.

CONSTRUCTION OF POWER GENERATION FACILITIES INVOLVES SIGNIFICANT SCHEDULE AND
COST RISKS THAT COULD NEGATIVELY AFFECT OUR RESULTS OF OPERATIONS, FINANCIAL
CONDITION AND CASH FLOWS.

Currently, we have two power generation facilities, and replacement or
incremental electric power generation units at two existing facilities, under
construction. Our successful completion of these facilities is subject to the
following:

- power prices;

- shortages and inconsistent qualities of equipment, material and labor;

- availability of financing;

- failure of key contractors and vendors to fulfill their obligations;

- work stoppages due to plant bankruptcies and contract labor disputes;

- permitting and other regulatory matters;

- unforeseen weather conditions;

- unforeseen equipment problems;

- environmental and geological conditions; and

- unanticipated capital cost increases.

Any of these factors could give rise to delays, cost overruns or the
termination of the plant expansion or construction. Many of these risks cannot
be adequately covered by insurance. While we maintain insurance, obtain
warranties from vendors and obligate contractors to meet specified performance
standards, the proceeds of such insurance, warranties or performance guarantees
may not be adequate to cover lost revenues, increased expenses or liquidated
damages payments we may owe.

In addition, construction delays and contractor performance shortfalls can
result in the loss of revenues and may, in turn, adversely affect our results of
operations. At our Seward power plant, one of our facilities under construction,
a sub-contractor of one of our two main contractors at the plant, after a
dispute with such main contractor, has filed a mechanics lien against the
property to secure payment of the amount of their fees and damages, which the
subcontractor alleges to be $36 million. These fees are disputed. The failure to
complete construction according to specifications at this plant and our other
facilities under construction can result in liabilities, reduced plant
efficiency, higher operating costs and reduced earnings.

THE LOSS OF THE TOLLING AGREEMENT FOR OUR LIBERTY ELECTRIC GENERATING STATION
AND/OR A POTENTIAL FORECLOSURE BY THE LIBERTY LENDERS COULD HAVE A MATERIAL
ADVERSE IMPACT ON OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH
FLOWS.

The output of our Liberty electric generating station is contracted under a
long-term tolling agreement between LEP and PGET. During 2002, several rating
agencies downgraded to sub-investment grade the debt of the two guarantors of
PGET, NEG and PG&E Gas Transmission Northwest Corp. (GTN). In addition, on July
8, 2003, PGET and NEG filed for reorganization under Chapter 11 of the United
States Bankruptcy Code; however, GTN did not file. The bankruptcy filing
constitutes an event of default under the Liberty credit facility which has not
been waived by the lenders. As a result, the lenders are entitled to control the
disbursement of funds by LEP and Liberty. The lenders are also entitled to
accelerate the debt and/or foreclose.

Also, on July 8, 2003, PGET filed a motion with the bankruptcy court to
reject the tolling agreement, which, if approved by the court, would deem the
agreement terminated as of July 8, 2003. Liberty does not intend to oppose this
motion. Liberty is obligated to provide PGET with a special invoice setting
forth the amount of Liberty's loss due to the early termination in accordance
with specific criteria. However, under the tolling agreement, PGET has the right
to refer the loss calculation to arbitration, which could

delay the receipt of such damages for an extended period. Liberty intends to
make prompt demand of the termination payment under its guaranty with GTN (the
guaranty, together with NEG's guaranty, is limited in amount to $140 million)
and file the necessary claims for damages with the bankruptcy court against PGET
and NEG. However, there can be no assurance that GTN would promptly pay any
award or how much, if anything, could be recovered from PGET or NEG. Any amounts
recovered from PGET, NEG and/or GTN would be handled in accordance with the
Liberty credit facility. The most likely result is that the damages would be
used to prepay LEP debt or paid into an account that is managed by the lenders
under the credit facility.

The tolling agreement provides for a fixed monthly payment to LEP. If the
tolling agreement is terminated, LEP would need to find a power purchaser or
tolling customer to replace PGET or sell the energy and/or capacity in the
merchant energy market. In addition, upon termination of the tolling agreement,
the gas transportation agreements that PGET utilizes in connection with the
tolling agreement will revert to LEP, and LEP will be required to perform the
obligations currently being performed by PGET under the gas transportation
agreements, including the payment of a monthly transportation charge. Once the
gas transportation agreements have reverted to LEP, LEP's payment obligations
thereunder will be supported by a $5 million guaranty of Orion Power Development
Company, Inc. (OPD), which is a wholly-owned subsidiary of Orion Power and the
parent company of LEP and Liberty. If LEP fails to make payment under the
transportation agreements, the transportation company may make a claim against
OPD under this guaranty. Also, if LEP fails to maintain minimum creditworthiness
as required under the gas tariff governing these transportation agreements on
file with the FERC, LEP may be required to post additional collateral. However,
OPD is not obligated to post any additional collateral.

It is unlikely, given current market conditions, that LEP would have
sufficient cash flow to pay all of its expenses or enable Liberty to make
interest and scheduled principal payments under the Liberty credit facility as
they become due, or to post the collateral which may be required to buy fuel or
in respect of the gas transportation agreements, if the tolling agreement is
terminated. The termination of the tolling agreement may cause both Liberty and
LEP to seek other alternatives, including reorganization under the bankruptcy
laws or a negotiated foreclosure transaction with the Liberty lenders. We,
including Orion Power, would not be in default under our other current debt
agreements if any of these events occur at Liberty.

If the lenders foreclose on LEP and Liberty, we believe we could incur a
pre-tax loss of an amount up to our recorded net book value with the potential
of an additional loss due to an impairment of goodwill allocated to LEP as a
result of the foreclosure. As of March 31, 2003, the combined net book value of
LEP and Liberty was $367 million, excluding the non-recourse debt obligations of
$266 million.

WE COULD BE SUBJECT TO MARKET PRICES WHEN PURCHASING POWER AND/OR TO FINES
UNDER CERTAIN OF OUR PROVIDER OF LAST RESORT AGREEMENTS.

As part of our acquisition of Orion Power in February 2002, we became the
provider of last resort for Duquesne Light. Under two agreements to be such
provider of last resort, we are obligated for a specific period to provide
energy to Duquesne Light to meet its obligations to satisfy the demands of any
customer in the Duquesne Light service area that does not elect to buy energy
from a competitive supplier as allowed by the Pennsylvania state deregulation
initiatives or that elects to return to Duquesne Light as the designated
provider of last resort. Under these contracts, we must provide all of the
energy necessary to meet the contractual requirements with no minimum and no
maximum quantity and Duquesne Light must buy all of the energy needed to satisfy
its provider of last resort obligation from us. Given the historical demand for
energy from provider of last resort customers and the historical energy
generation from our assets located in Ohio, Pennsylvania and West Virginia, we
generally expect to produce more energy than needed to meet our provider of last
resort obligations under the POLR agreements. We will attempt to sell this
excess energy into the market. The provider of last resort demand, however, will
fluctuate on a continuous, real-time basis, and will likely peak during summer
and winter, on weekdays, and during some hours of the day. This could cause the
provider of last resort demand to be greater than the amount of energy we are
able to generate at any given moment. As a result, we may need to purchase
energy from
30

the market to cover our contractual obligations. This is likely to occur at
times of higher market prices, while the price we receive will be fixed under
our provider of last resort agreements and will not fluctuate with the market.
We may also have to purchase energy from the market to cover our contractual
obligations if we have operational problems at one or more of our generating
facilities that reduce our ability to produce energy. Failure to provide
sufficient energy could give rise to penalties under both of our provider of
last resort agreements. A severe under-delivery of energy that forces Duquesne
Light to deny some customers energy could give rise to penalties of $1,000 per
MWh under the first agreement or between $100 and $1,000 per MWh under the
second agreement, depending upon the circumstances of such under-delivery.

RISKS RELATED TO THE SALE OF OUR EUROPEAN ENERGY OPERATIONS

WE SIGNED AN AGREEMENT TO SELL OUR EUROPEAN ENERGY OPERATIONS TO NUON. AS IN
ANY SALE TRANSACTION WITH REGULATORY APPROVAL AS A CONDITION PRECEDENT, THERE
IS RISK THAT THE SALE MAY BE SUBSTANTIALLY DELAYED OR MAY NOT BE CONSUMMATED.

In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon. The sale is subject to the approval of the Dutch
competition authority. We have obtained the approval of the German competition
authority. We anticipate that the consummation of the sale will occur in the
summer of 2003. However, there can be no assurance that the sale will not be
substantially delayed nor that it will be consummated. No assurance can be given
that we will obtain the approval of the Dutch authorities or that such approval
can be obtained in a timely manner.

THERE IS SIGNIFICANT OPERATIONAL, COMMERCIAL AND FINANCIAL RISK TO OUR
EUROPEAN ENERGY OPERATIONS IF THE SALE TO NUON IS NOT CONSUMMATED.

If the sale of our European energy operations is not consummated, we may be
significantly impacted by negative market perception regarding an entity with a
sub-investment grade credit rating, which has, directly and indirectly, three
credit facilities with an aggregate face value of approximately $1.3 billion.
Key commercial counterparties and vendors may limit their transactions and
exposure with us. No assurance can be given regarding our ability to
successfully or adequately mitigate these risks. In June 2003, the maturity date
of the letter of credit facility was extended to January 5, 2004 and the
maturity date of the revolving credit facility was extended to December 31,
2003.

RISKS RELATED TO OUR BUSINESSES GENERALLY

WE DO NOT ATTEMPT TO FULLY HEDGE OUR ASSETS OR POSITIONS AGAINST CHANGES IN
COMMODITY PRICES, AND OUR RISK MANAGEMENT POLICIES AND PROCEDURES MAY NOT BE
EFFECTIVE.

Commodity price risk is an inherent component of our retail and wholesale
energy operations. Our results of operations, financial condition and cash flows
depend, in large part, upon prevailing market prices for electricity and fuel in
our markets. Market prices may fluctuate substantially over relatively short
periods of time, potentially adversely impacting our results of operations,
financial condition and cash flows. Changes in market prices for electricity and
fuel may result from the following:

- weather conditions;

- seasonality;

- demand for energy commodities and general economic conditions;

- forced or unscheduled plant outages;

- disruption of electricity or gas transmission or transportation,
infrastructure or other constraints or inefficiencies;

- addition of generating capacity;

- availability of competitively priced alternative energy sources;
31

- availability and levels of storage and inventory for fuel stocks;

- natural gas, crude oil and refined products, and coal production levels;

- the creditworthiness or bankruptcy or other financial distress of market
participants;

- changes in market liquidity;

- natural disasters, wars, embargoes, acts of terrorism and other
catastrophic events; and

- federal, state and foreign governmental regulation and legislation.

To mitigate our financial exposure related to commodity price fluctuations,
we routinely enter into contracts to hedge a portion of our purchase and sale
commitments, exposure to weather fluctuations, fuel requirements and
transportation and inventories of natural gas, coal, refined products, and other
commodities and services. As part of this strategy, we routinely utilize
derivative instruments (e.g., fixed-price forward physical purchase and sales
contracts, futures, financial swaps and option contracts). However, we do not
expect to cover the entire exposure of our assets or positions to market price
and volatility changes, and the coverage will vary over time. This hedging
activity fluctuates according to strategic objectives, taking into account the
desire for cash flow or earnings certainty, the availability of liquidity
resources and our view of market prices.

Our risk management procedures and our hedging strategies are constrained
by our liquidity, our access to credit and the reduction in market liquidity,
and may not be followed or work as planned. These and other factors may
adversely impact our results of operations, financial condition and cash flows.

WE MAY EXPERIENCE INADEQUATE LIQUIDITY DUE TO FACTORS WHICH LEAD TO POSTING OF
ADDITIONAL COLLATERAL RELATED TO OUR DOMESTIC OPERATIONS.

Based on current commodity prices, we estimate that as of June 30, 2003, we
could be required to post additional collateral of up to $472 million related to
our domestic operations. This estimate could increase based on changes to
commodity prices. Factors which could lead to an increase in our actual posting
of collateral include adverse changes in our industry or negative reactions to
additional credit rating downgrades or the secured nature of our new credit
facilities. Under certain unfavorable commodity price scenarios, it is possible
that we could experience inadequate liquidity as a result of the posting of
additional collateral.

At times we have open positions in the market (required to be within
established corporate risk management guidelines), resulting from optimizing our
power generation portfolio and eliminating our remaining trading positions. If
we have open positions, changes in commodity prices could negatively impact our
results of operations, financial condition and cash flows. We have measures and
controls in place that are designed to mitigate the impact of commodity price
changes on our positions. These measures and controls are based on statistical
analyses and estimates. Consequently, no assurance can be given that these
controls and measures will be effective in the event that anomalous commodity
price changes occur.

For additional information, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Trading and Marketing and
Non-trading Operations, and "Quantitative and Qualitative Disclosures About
Market Risk" for the three years ended December 31, 2000, 2001 and 2002 and for
the three months ended March 31, 2002 and 2003, incorporated by reference herein
and note 7 to our consolidated financial statements incorporated by reference
herein.

THE ULTIMATE OUTCOME OF THE NUMEROUS LAWSUITS AND REGULATORY PROCEEDINGS
RELATING TO OUR ACTIVITIES IN THE ELECTRICITY AND GAS MARKETS TO WHICH WE ARE
A PARTY CANNOT BE PREDICTED AT THIS TIME. ANY ADVERSE DETERMINATION COULD HAVE
A MATERIAL ADVERSE EFFECT ON OUR FINANCIAL CONDITION, RESULTS OF OPERATIONS
AND CASH FLOWS.

We are party to numerous lawsuits and regulatory proceedings relating to
our trading and marketing activities, including the following:

- certain same-day commodity trading transactions in which we engaged in
1999, 2000 and 2001 involving purchases and sales with the same
counterparty for the same volume at substantially the same price, which
have been referred to as "round trip" or "wash" trades;

- a series of four structured transactions entered into during the period
May 2001 through September 2001, referred to as "structured
transactions;"

- our activities in the California wholesale market from January 2000 to
June 2001, including our operation and sale of generation from generation
facilities owned by our subsidiaries located in California; and

- our price reporting and gas trading activities at the Topock delivery
point in California.

In addition, various state and federal governmental agencies have commenced
investigations relating to these activities, including the California Attorney
General, the FERC, the CFTC and criminal investigations by the United States
Attorneys for the Southern District of New York and the Northern District of
California and, in certain circumstances, the matters described elsewhere in
this prospectus that have been the subject of the FERC and CFTC investigations.
These lawsuits, proceedings and investigations are currently the subject of
intense, highly charged media and political attention. While their ultimate
outcome cannot be predicted at this time, the possibility of civil or criminal
action against us or our current or former employees is possible. In addition,
these lawsuits, proceedings and investigations could lead to the discovery of
additional conduct or transactions not known at this time that could result in
additional litigation or regulatory action. Certain of our current and former
employees are, or may be, the subject of criminal investigations by the United
States Attorney's office in one or more jurisdictions. The ultimate disposition
of some of these matters could have a material adverse effect on our financial
condition, results of operations and cash flows. See note 14(g) to our
consolidated financial statements incorporated by reference herein and note
13(d) to our interim consolidated financial statements incorporated by reference
herein.

In June 2002, the SEC advised us that it had issued a formal order in
connection with its investigation of our financial reporting, internal controls
and related matters. The investigation focused on our round trip trades and
certain structured transactions. We cooperated with the SEC staff. On May 12,
2003, we consented, without admitting or denying the SEC's findings, to the
entry of an administrative cease-and-desist order obligating us to avoid future
violations of certain provisions of the federal securities laws, including
non-compliance with the antifraud provisions of the federal securities laws. The
SEC did not assess any monetary penalties or fines relating to the order.

OUR STRATEGIC PLANS MAY NOT BE SUCCESSFUL.

Our future results of operations are dependent on the success of our
strategic plans. Our strategic plans with respect to our wholesale energy
segment indicate a shift in emphasis from identifying and pursuing acquisition
and development candidates to completing facilities currently under construction
and integrating recently acquired generation facilities. The integration and
consolidation of our acquisitions with our existing business requires
substantial management, financial and other resources and may not be
successfully integrated. This change reflects our current focus on integrating
the Orion Power assets with our other domestic wholesale energy operations, the
completion of our construction projects and our judgments regarding the current
state of the wholesale electricity and capital markets. Our strategy could
change to respond to market conditions or other circumstances. Additionally, our
strategic plans include the evaluation of our option to acquire 81% of Texas
Genco from CenterPoint. Further, concurrently with
33

the closing of the offering of the senior secured notes, we entered into an
amendment to our new credit facilities to, among other things, increase our
flexibility regarding our potential purchase of Texas Genco. Under the credit
agreement amendment, we are permitted to exercise the option granted to us by
CenterPoint to purchase all the stock of Texas Genco or to negotiate a purchase
of all the stock of Texas Genco outside the option at a price less than or equal
to the price set under the option. The amendment also extends the deadline for
agreeing to purchase Texas Genco to September 15, 2004. Our decision whether to
purchase Texas Genco and the method used will be based on many factors including
the option price and our ability to, and the terms and conditions pursuant to
which we may, finance this acquisition.

IF WE FAIL TO OBTAIN OR MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR
APPROVAL, OUR RESULTS OF OPERATIONS MAY BE ADVERSELY AFFECTED.

Our operations are subject to complex and stringent energy, environmental
and other governmental laws and regulations. The acquisition, ownership and
operation of power generation facilities require numerous permits, approvals and
certificates from federal, state and local governmental agencies. The operation
of our generation facilities must also comply with environmental protection and
other legislation and regulations. At present, we have wholesale operations in
Arizona, California, Florida, Illinois, Maryland, Mississippi, Nevada, New
Jersey, New York, Ohio, Pennsylvania, Texas and West Virginia. Most of our
existing domestic generation facilities are exempt wholesale generators that
sell electricity exclusively into the wholesale market. These facilities are
subject to regulation by the FERC regarding rate matters and by state regulatory
commissions regarding environmental and other health and safety matters. The
FERC has authorized us to sell electricity produced from these facilities at
market prices. The FERC retains the authority to modify or withdraw our
market-based rate authority and to impose "cost of service" rates. Any reduction
by the FERC of the rates we may receive for our generation activities may
materially adversely affect our business, results of operations, financial
condition and cash flows.

CHANGES IN TECHNOLOGY MAY IMPAIR THE VALUE OF OUR POWER PLANTS AND MAY
SIGNIFICANTLY IMPACT OUR BUSINESS IN OTHER WAYS AS WELL.

Research and development activities are ongoing to improve alternative
technologies to produce electricity, including fuel cells, microturbines and
photovoltaic (solar) cells. It is possible that advances in these or other
alternative technologies will reduce the costs of electricity production from
these technologies to a level below that which we have forecasted. In addition,
increased conservation efforts and advances in technology could reduce
electricity demand and significantly reduce the value of our power generation
assets. Changes in technology could also alter the channels through which retail
electric customers buy electricity.

OUR RESULTS OF OPERATIONS, OUR ABILITY TO ACCESS CAPITAL AND INSURANCE AND OUR
FUTURE GROWTH PROSPECTS COULD BE ADVERSELY AFFECTED BY THE OCCURRENCE OR RISK
OF OCCURRENCE OF FUTURE TERRORIST ATTACKS OR RELATED ACTS OF WAR.

We are currently unable to measure the ultimate impact of the terrorist
attacks of September 11, 2001 on our industry and the United States economy as a
whole. The uncertainty associated with the military activity of the United
States and other nations and the risk of future terrorist activity may impact
our results of operations and financial condition in unpredictable ways. These
actions could result in adverse changes in the insurance markets and disruptions
of power and fuel markets. In addition, our generation facilities or the power
transmission and distribution facilities on which we rely could be directly or
indirectly harmed by future terrorist activity. The occurrence or risk of
occurrence of future terrorist attacks or related acts of war could also
adversely affect the United States economy. A lower level of economic activity
could result in a decline in energy consumption, which could adversely affect
our revenues, margins and cash flows and limit our future growth prospects. The
occurrence or risk of occurrence could also increase pressure to regulate or
otherwise limit the prices charged for electricity or

gas. Also, these risks could cause instability in the financial markets and
adversely affect our ability to access capital on terms and conditions
acceptable to us.

OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT AND OUR INSURANCE COSTS MAY
INCREASE.

We have insurance coverage, subject to various limits and deductibles,
covering our generation facilities, including property damage insurance and
general liability insurance in amounts that we consider appropriate. However, we
cannot assure you that insurance coverage will be available in the future on
commercially reasonable terms or that the insurance proceeds received for any
loss of or any damage to any of our generation facilities will be sufficient to
restore the loss or damage without negative impact on our financial condition
and results of operations. The costs of our insurance coverage have increased
significantly during recent periods and may continue to increase in the future.

RISKS RELATED TO OUR CORPORATE AND FINANCIAL STRUCTURE

WE HAVE SIGNIFICANT DEBT THAT COULD NEGATIVELY IMPACT OUR BUSINESS.

We have a significant amount of debt outstanding. As of March 31, 2003,
after giving pro forma effect to both the offering of the notes and the offering
of the senior secured notes and the use of the net proceeds from the senior
secured notes, we would have had total consolidated debt of $8.3 billion
(excluding $693 million of debt related to our European energy operations), of
which $1.4 billion would have consisted of the notes and the senior secured
notes and the balance would have consisted of other debt including all
borrowings under the credit facilities. Also, after giving pro forma effect to
the offering of the notes and the concurrent offering of the senior secured
notes assuming these offerings had occurred on January 1, 2002, and the
repayment of debt, with the amount of the net proceeds from the senior secured
notes, that was in place prior to our March 2003 refinancing, our earnings would
have been insufficient to cover our fixed charges by approximately $99 million
for the three months ended March 31, 2003, and our ratio of earnings to fixed
charges would have been 1.30 for the year ended December 31, 2002. Our high
level of debt could:

- make it difficult for us to satisfy our obligations, including debt
service requirements under our outstanding debt and the notes;

- limit our ability to obtain additional financing to operate our business;

- limit our financial flexibility in planning for and reacting to business
and industry changes;

- place us at a competitive disadvantage as compared to less leveraged
companies;

- increase our vulnerability to general adverse economic and industry
conditions, including changes in interest rates and volatility in
commodity prices; and

- require us to dedicate a substantial portion of our cash flows to
payments on our debt, thereby reducing the availability of our cash flow
for other purposes including our operations, capital expenditures and
future business opportunities.

The incurrence of additional debt could make it more likely that we will
experience some or all of the above-described risks.

DESPITE CURRENT INDEBTEDNESS LEVELS, WE AND OUR SUBSIDIARIES MAY STILL BE ABLE
TO INCUR SUBSTANTIALLY MORE DEBT. THIS COULD FURTHER EXACERBATE THE RISKS
ASSOCIATED WITH OUR SUBSTANTIAL LEVERAGE.

We and our subsidiaries may be able to incur substantial additional
indebtedness in the future. The terms of the indenture governing the notes do
not prohibit us or our subsidiaries from doing so. As of June 30, 2003, the
credit agreement governing our new credit facilities would permit additional
borrowings of up to $831 million. If new debt is added to our and our
subsidiaries' current debt levels, the related risks that we and they now face
could significantly increase. See "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Consolidated Future Uses and
Sources of Cash and

Certain Factors Impacting Future Uses and Sources of Cash" for the three years
ended December 31, 2000, 2001 and 2002 and for the three months ended March 31,
2002 and 2003, incorporated by reference herein.

IF WE DO NOT GENERATE SUFFICIENT POSITIVE CASH FLOWS, WE MAY BE UNABLE TO
SERVICE OUR DEBT.

Our ability to pay principal and interest on our debt, including the
principal and interest on the notes, depends on our future operating
performance. Future operating performance is subject to market conditions and
business factors that often are beyond our control. If our cash flows and
capital resources are insufficient to allow us to make scheduled payments on our
debt, we may have to reduce or delay capital expenditures, sell assets, seek
additional capital or restructure or refinance our debt. We cannot assure you
that the terms of our debt will allow these alternative measures or that such
measures would satisfy our scheduled debt service obligations.

Based on our current level of anticipated cost savings and operating
improvements, we believe our cash flow from operations, available cash and
available borrowings under our credit facilities will be adequate to meet our
future needs for at least the next twelve months. However, under certain
commodity pricing scenarios, we may experience strains on our liquidity. For
further discussion of our current liquidity situation and related impacts, see
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources" for the three years ended
December 31, 2000, 2001 and 2002 and for the three months ended March 31, 2002
and 2003, incorporated by reference herein.

We cannot assure you that our businesses will generate sufficient cash
flows from operations to enable us to pay the principal, premium, if any, and
interest on our debt, including these notes, or to fund our other liquidity
needs. We may not be successful in realizing the cost savings and operating
improvements that we currently anticipate. If commodity prices increase
substantially in the near term, our liquidity could be severely strained. We may
need to refinance all or a portion of our indebtedness, including these notes,
on or before maturity; however, we cannot assure you that we will be able to
refinance the indebtedness on commercially reasonable terms or at all. If we
cannot make scheduled payments on our debt, we will be in default and, as a
result:

- our debt holders could declare all outstanding principal and interest to
be due and payable;

- our holders of the credit agreement debt and the senior secured notes
could terminate their commitments and commence foreclosure proceedings
against our assets; and

- we could be forced into bankruptcy or liquidation.

THE TERMS OF OUR DEBT MAY SEVERELY LIMIT OUR ABILITY TO PLAN FOR OR RESPOND TO
CHANGES IN OUR BUSINESSES.

Our new credit facilities and the senior secured notes restrict our ability
to take specific actions in planning for and responding to changes in our
business without the consent of our lenders and noteholders, even if such
actions may be in our best interest. Our new credit facilities also require us
to maintain specified financial ratios and meet specific financial tests. Our
ability to comply with these covenants, as they currently exist or as they may
be amended, may be affected by many events beyond our control and our future
operating results may not allow us to comply with the covenants, or in the event
of a default, to remedy that default. Our failure to comply with those financial
covenants or to comply with the other restrictions in the credit agreement
governing our new credit facilities could result in a default, which could cause
that indebtedness (and by reason of cross-acceleration provisions, the notes and
other indebtedness) to become immediately due and payable. If we are unable to
repay those amounts, the holders of the credit agreement debt and the senior
secured notes could proceed against the collateral granted to them to secure
that indebtedness. If those holders accelerate the payment of our credit
agreement debt, it is unlikely that we could pay that indebtedness immediately
and continue to operate our business.

In addition, the credit agreement governing our new credit facilities and
the indenture governing the senior secured notes contain other covenants that
restrict, among other things, our ability to:

- pay dividends and other distributions with respect to our capital stock
and purchase, redeem or retire our capital stock;

- incur additional indebtedness and issue preferred stock;

- enter into asset sales unless the proceeds from those asset sales are
used to repay debt or, in certain circumstances and for a limited period
of time, are placed in an escrow account to be available to be used to
possibly acquire a direct or indirect interest in Texas Genco in the
event that we determine that such acquisition is advantageous;

- enter into transactions with affiliates;

- incur liens on assets to secure certain debt;

- engage in certain business activities; and

- engage in certain mergers or consolidations and transfers of assets.

See "Description of Notes."

OUR NON-INVESTMENT GRADE CREDIT RATINGS COULD ADVERSELY IMPACT OUR ABILITY TO
ACCESS CAPITAL ON ACCEPTABLE TERMS, OPTIMIZE OUR ASSETS AND OPERATE OUR RISK
MANAGEMENT ACTIVITIES.

Our credit rating has been downgraded to below investment grade and could
be downgraded further. The downgrading of our credit rating has limited, and
will likely continue to limit, our ability to refinance our debt obligations and
access the capital markets. A number of our commercial contracts and guarantees
associated with our asset optimization and risk management operations require us
to satisfy collateral margin requirements that vary depending on energy market
prices and contract prices. In most cases, the consequences of rating downgrades
under these contracts and guarantees require that we provide credit support to
our counterparties in the form of a pledge of cash collateral, a letter of
credit or other similar credit support. To meet future requirements, substantial
credit support could be necessary thereby reducing the availability of our cash
flows for other purposes. In certain circumstances, our liquidity could be
significantly strained, which could have a material adverse effect on our
business. In addition, certain of our contracts with commercial, industrial and
institutional retail electricity customers give the customer the right to
terminate the contract based on our receiving a below-investment-grade credit
rating from certain ratings agencies. As of June 30, 2003, we have not
experienced any contract terminations in our retail energy segment as a result
of downgrades of our credit ratings to below investment grade. As a result of
the downgrading of our credit rating, we may not be able to satisfy future
collateral margin requirements under these contracts and guarantees.

AN INCREASE IN OUR INTEREST RATES COULD ADVERSELY AFFECT OUR CASH FLOWS.

As of March 31, 2003, we had $7.2 billion of outstanding floating-rate debt
(excluding $655 million of floating-rate debt of our European energy
operations). Because of capital constraints impacting our business at the time
we borrowed some of this floating-rate debt, the interest rate margins are
substantially above our historical borrowing margins. In addition, any
floating-rate debt issued by us in the future could be at interest rate margins
substantially above our historical borrowing margins. While we may seek to use
interest rate swaps or other derivative instruments to hedge portions of our
floating-rate debt exposure, we may not be successful in obtaining hedges on
acceptable terms. Any increase in short-term interest rates would result in
higher interest costs and could adversely affect our results of operations,
financial condition and cash flows.

In addition, the capital constraints currently impacting our industry may
require additional future indebtedness to include terms and/or pricing that is
more restrictive or burdensome than those of our current indebtedness and
refinancings in March 2003. This may negatively impact our ability to operate

our business and could adversely affect our results of operations, financial
condition and cash flows. As a result of the June and July 2003 issuances of
notes and senior secured notes, our interest expense will increase
substantially. We estimate that our net interest expense will increase by
approximately $25 million during the second half of 2003 from previous
projections. In addition, as a result of the July 2003 issuance of senior
secured notes, we will expense approximately $30 million of deferred financing
costs associated with the indebtedness prepaid with the proceeds from the
offering of the senior secured notes. For additional information regarding the
$275 million of notes and $1.1 billion of senior secured notes, see "Description
of Notes" and "Description of Other Indebtedness," respectively.

RELIANT RESOURCES IS A HOLDING COMPANY WITH NO OPERATIONS OF ITS OWN. AS A
RESULT, WE DEPEND ON DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MAKE PAYMENTS ON
OUR DEBT OBLIGATIONS AND MEET OUR OTHER CASH REQUIREMENTS. APPLICABLE LAWS OR
CONTRACTUAL RESTRICTIONS COULD LIMIT THE AMOUNT OF DISTRIBUTIONS MADE TO US BY
OUR SUBSIDIARIES.

We derive substantially all our operating income from, and hold
substantially all of our assets through, our subsidiaries. As a result, we
depend on distributions of cash flows and earnings of our subsidiaries in order
to meet our payment obligations under our credit facilities and other
obligations, including the notes. These subsidiaries are separate and distinct
legal entities and have no obligation, unless specifically contracted, to pay
any amounts due on our debts or other obligations, whether by dividends,
distributions, loans or otherwise. Many of our subsidiaries have guaranteed our
obligations under our new credit facilities and the senior secured notes to the
extent legally and contractually permitted and are co-borrowers under the new
$300 million senior priority revolving credit facility. The terms of some of our
subsidiaries' indebtedness restrict their ability to pay dividends or make
payments to us in some circumstances. The terms of any new or amended subsidiary
indebtedness could further restrict payments from these subsidiaries. In
addition, provisions of applicable law, such as those limiting the legal sources
of dividends, could limit their ability to make payments or other distributions
to us.

Our right to receive any assets of any subsidiary will be effectively
subordinated to the claims of that subsidiary's creditors, including trade
creditors. In addition, even if we are a creditor of any subsidiary, our rights
as a creditor are subordinated to the indebtedness of the subsidiary under our
new credit facilities and senior secured notes. These notes will effectively be
subordinated to the prior payment of all debts (including trade payables) of our
subsidiaries. Assuming we had completed the offering of the notes on March 31,
2003, these notes would have been effectively junior to $6.5 billion (excluding
$1.8 billion related to our European energy operations) of indebtedness and
other liabilities (including trade payables) of our subsidiaries and
approximately $39 million would have been available to these subsidiaries for
future borrowings under their credit facilities (excluding $189 million
available for future borrowings under our European credit facilities).

OUR HISTORICAL FINANCIAL RESULTS AS A SUBSIDIARY OF CENTERPOINT MAY NOT BE
REPRESENTATIVE OF OUR RESULTS AS A SEPARATE COMPANY.

The historical financial information relating to periods prior to the
Distribution that we have included in this prospectus does not necessarily
reflect what our results of operations, financial condition and cash flows would
have been had we been a separate, stand-alone entity during such periods. Our
costs and expenses during such periods reflect charges from CenterPoint for
centralized corporate services and infrastructure costs. These allocations have
been determined based on assumptions that we and CenterPoint considered to be
reasonable under the circumstances. This historical financial information is not
necessarily indicative of what our results of operations, financial condition
and cash flows will be in the future. We may experience significant changes in
our cost structure, funding and operations as a result of our separation from
CenterPoint, including increased costs associated with reduced economies of
scale and increased costs associated with being a publicly traded, stand-alone
company.

RISKS RELATED TO THE NOTES AND OUR COMMON STOCK

YOUR RIGHT TO RECEIVE PAYMENTS ON THESE NOTES IS JUNIOR TO OUR EXISTING
INDEBTEDNESS AND POSSIBLY ALL OF OUR FUTURE BORROWINGS.

These notes rank behind all of our existing indebtedness (other than trade
payables) and all of our future borrowings (other than trade payables), except
any future indebtedness that expressly provides that it ranks equal with, or
subordinated in right of payment to, the notes. As a result, upon any
distribution to our creditors in a bankruptcy, liquidation or reorganization or
similar proceeding relating to us or our property, the holders of our senior
debt will be entitled to be paid in full and in cash before any payment may be
made with respect to these notes.

In addition, all payments on the notes will be blocked in the event of a
payment default on senior debt and may be blocked for up to 179 of 360
consecutive days in the event of certain non-payment defaults on senior debt.

In the event of a bankruptcy, liquidation or reorganization or similar
proceeding relating to us, holders of the notes will participate with trade
creditors and all other holders of our subordinated indebtedness in the assets
remaining after we have paid all of our senior debt. However, because the
indenture requires that amounts otherwise payable to holders of the notes in a
bankruptcy or similar proceeding be paid to holders of senior debt instead,
holders of the notes may receive less, ratably, than holders of trade payables
in any such proceeding. In any of these cases, we may not have sufficient funds
to pay all of our creditors and holders of notes may receive less, ratably, than
the holders of our senior debt.

Assuming we had completed the offering of these notes on March 31, 2003,
these notes would have been subordinated to $5.1 billion of senior debt of
Reliant Resources and approximately $651 million would have been available for
borrowing as additional senior debt under Reliant Resources' new credit
facilities after giving effect to the offering of senior secured notes and the
related prepayment under our new credit facility. We will be permitted to borrow
unlimited additional indebtedness, including senior debt, in the future under
the terms of the indenture.

OUR ABILITY TO REPURCHASE NOTES IN CASH UPON A CHANGE IN CONTROL MAY BE
LIMITED.

Our ability to repurchase notes upon the occurrence of a change in control
is subject to limitations. We may not have sufficient financial resources or the
ability to arrange financing to pay the repurchase price for all the notes
delivered by holders seeking to exercise their repurchase right. Although we may
elect, subject to satisfaction of certain conditions, to pay the repurchase
price for the notes in common stock or other applicable securities, our ability
to repurchase the notes in cash may be limited or prohibited by the terms of any
current or future borrowing arrangements existing at the time of a change in
control. Any failure by us to repurchase the notes upon a change in control
would result in an event of default under the indenture, whether or not the
repurchase is permitted by the subordination provisions of the indenture. Any
such default may, in turn, cause a default under our senior debt. Moreover, the
occurrence of a change in control could result in an event of default under the
terms of our then existing senior debt. As a result, any repurchase of the notes
may be prohibited until the senior debt is paid in full. See "Description of
Notes -- Repurchase at Option of Holders Upon a Change in Control".

Furthermore, because the sale price of our common stock will be determined
prior to the applicable repurchase date, holders of the notes bear the market
risk that our common stock will decline in value between the date the sale price
is calculated and the repurchase date.

WE CANNOT ASSURE YOU THAT AN ACTIVE TRADING MARKET WILL DEVELOP FOR THESE
NOTES, WHICH MAY ADVERSELY AFFECT THE MARKET PRICE.

The notes are a new issue of securities with no established trading market.
The initial purchasers have advised us that they currently intend to make a
market in the notes. However, the initial purchasers are not obligated to make a
market in the notes and any market making by the initial purchasers may be
discontinued at any time at the sole discretion of the initial purchasers
without notice. We cannot assure
39

you that a market for the notes will develop and continue upon completion of the
offering or that the market price of the notes will not decline. Various
factors, such as changes in prevailing interest rates or changes in perceptions
of our creditworthiness could cause the market price of the notes to fluctuate
significantly. In addition, the liquidity of the trading market in the notes and
the market price quoted for the notes may be adversely affected by changes in
the overall market for convertible securities, changes in our prospects or
financial performance or in the prospects of companies in our industry
generally. The trading price of the notes will also be significantly affected by
the market price of our common stock, which could be subject to wide
fluctuations in response to a variety of factors. The notes will not be listed
on any securities exchange or included for quotation in any automated dealer
system and will only be traded on the over-the-counter market.

OUR STOCK PRICE HAS BEEN VOLATILE HISTORICALLY AND MAY CONTINUE TO BE
VOLATILE. THE PRICE OF OUR COMMON STOCK, AND THEREFORE THE PRICE OF THE NOTES,
MAY FLUCTUATE SIGNIFICANTLY, WHICH MAY MAKE IT DIFFICULT FOR HOLDERS TO RESELL
THE NOTES OR THE SHARES OF OUR COMMON STOCK ISSUABLE UPON CONVERSION OF THE
NOTES WHEN DESIRED OR AT ATTRACTIVE PRICES.

The trading price of our common stock has been and may continue to be
subject to wide fluctuations. During 2002, the closing sale prices of our common
stock on The New York Stock Exchange ranged from $0.99 to $17.45 per share and
the closing sale price on July 21, 2003 was $5.15 per share. Our stock price may
fluctuate in response to a number of events and factors, such as quarterly
variations in operating results, actions by various regulatory agencies,
litigation, market perceptions of our financial reporting, changes in financial
estimates and recommendations by securities analysts, the operating and stock
price performance of other companies that investors may deem comparable to us,
and news reports relating to trends in our markets or general economic
conditions.

In addition, the stock market in general, and the market prices for
energy-related companies in particular, have experienced extreme volatility that
often has been unrelated to the operating performance of such companies. These
broad market and industry fluctuations may adversely affect the price of our
stock, regardless of our operating performance. Because the notes are
convertible into shares of our common stock, volatility or depressed prices for
our common stock could have a similar effect on the trading price of the notes.
Holders who receive common stock upon conversion also will be subject to the
risk of volatility and depressed prices of our common stock. In addition, the
existence of the notes may encourage short selling in our common stock by market
participants because the conversion of the notes could depress the price of our
common stock.

SECURITIES WE ISSUE TO FUND OUR OPERATIONS COULD DILUTE YOUR OWNERSHIP.

We may decide to raise additional funds through public or private debt or
equity financing to fund our operations. If we raise funds by issuing equity
securities, the percentage ownership of current stockholders will be reduced and
the new equity securities may have rights prior to those of the common stock
issuable upon conversion of the notes. We may not obtain sufficient financing on
terms that are favorable to you or us. We may delay, limit or eliminate some or
all of our proposed or existing operations if adequate funds are not available.

THE NOTES DO NOT RESTRICT OUR ABILITY TO INCUR ADDITIONAL DEBT OR TO TAKE
OTHER ACTIONS THAT COULD NEGATIVELY IMPACT HOLDERS OF THE NOTES.

We are not restricted under the terms of the notes from incurring
additional indebtedness, including secured debt. In addition, the limited
covenants applicable to the notes do not require us to achieve or maintain any
minimum financial results relating to our financial position or results of
operations. Our ability to recapitalize, incur additional debt and take a number
of other actions that are not limited by the terms of the notes could have the
effect of diminishing our ability to make payments on the notes when due.

PROVISIONS OF THE DELAWARE GENERAL CORPORATION LAW AND OUR ORGANIZATIONAL
DOCUMENTS MAY DISCOURAGE AN ACQUISITION OF US.

Our organizational documents and the Delaware General Corporation Law both
contain provisions that will impede the removal of directors and may discourage
a third party from making a proposal to acquire us. For example, our board of
directors may, without the consent of the stockholders, issue preferred stock
with greater voting rights than the common stock. The existence of these
provisions may also have a negative impact on the price of our common stock.
Furthermore, we are subject to Section 203 of the Delaware General Corporation
Law, which could have the effect of delaying or preventing a change in control.
See "Description of Capital Stock -- Delaware Antitakeover Law" for a discussion
of these anti-takeover provisions.

FUTURE SALES OF OUR COMMON STOCK IN THE PUBLIC MARKET COULD LOWER THE STOCK
PRICE.

A substantial number of shares of our common stock are subject to stock
options and the notes may be converted into shares of common stock. In addition,
under our new credit facilities, we issued certain warrants to our lenders, some
of which vested and became exercisable immediately and the balance of which will
vest and become exercisable into a substantial number of shares of our common
stock if we do not, on or before May 2005 and May 2006, repay our senior secured
term loans and/or permanently reduce the commitment under our senior secured
revolving credit facility by an aggregate of $1.0 billion by May 2005 and by an
aggregate of $2.0 billion by May 2006. With the proceeds of our issuance of the
senior secured notes on July 1, 2003, we have satisfied the May 2005 permanent
reduction amount and therefore, the 6,268,716 warrants applicable to the May
2005 date have been cancelled. For a description of these warrants, see
"Description of Other Indebtedness" and "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Consolidated Future Uses and
Sources of Cash and Certain Factors Impacting Future Uses and Sources of Cash"
for the three years ended December 31, 2000, 2001 and 2002 and for the three
months ended March 31, 2002 and 2003, incorporated by reference herein. We
cannot predict the effect, if any, that future sales of our common stock or
notes, or the availability of shares of our common stock or notes for future
sale, will have on the market price of our common stock or notes. Sales of
substantial amounts of our common stock (including shares issued upon the
exercise of stock options or warrants or the conversion of the notes), or the
perception that such sales could occur, may adversely affect prevailing market
prices for our common stock and notes.

USE OF PROCEEDS

We will not receive any of the proceeds from the sale by any selling
securityholder of the notes or shares of common stock offered under this
prospectus.

PRICE RANGE OF COMMON STOCK

Our common stock is traded on The New York Stock Exchange under the symbol
"RRI". The following table sets forth, for the periods indicated, the range of
high and low sale prices for our common stock. On July 21, 2003, the closing
price of our common stock was $5.15 per share.

COMMON
STOCK PRICE
---------------
HIGH LOW
------ ------

YEAR ENDED DECEMBER 31, 2001
Second Quarter (from May 1 through June 30)................. $37.50 $23.65
Third Quarter............................................... 28.60 14.45
Fourth Quarter.............................................. 19.85 13.20
YEAR ENDED DECEMBER 31, 2002
First Quarter............................................... $17.45 $ 9.50
Second Quarter.............................................. 17.16 7.28
Third Quarter............................................... 8.95 1.66
Fourth Quarter.............................................. 3.23 0.99
YEAR ENDING DECEMBER 31, 2003
First Quarter............................................... $ 5.70 $ 2.25
Second Quarter.............................................. 7.05 3.82
Third Quarter (through July 21)............................. 6.38 5.14

As of July 21, 2003, there were 61,213 holders of record of our common
stock.

DIVIDEND POLICY

We have not paid or declared any dividends since our formation and
currently intend to retain earnings for use in our business. Any future
dividends will be subject to determination based upon our results of operations
and financial condition, our future business prospects, any applicable
contractual restrictions, including the restriction on our ability to pay
dividends under the refinanced credit facilities, and other factors that our
board of directors considers relevant.

CAPITALIZATION

The following table sets forth our cash and cash equivalents, restricted
cash and certain other assets and our consolidated historical capitalization (1)
as of March 31, 2003 and (2) as adjusted as of March 31, 2003 to give effect to
the issuance of the notes and the use of the proceeds from the notes and the
concurrent issuance of the senior secured notes and the use of the proceeds
therefrom and the write-off of approximately $30 million of deferred financing
costs. The information appearing in this table should be read in conjunction
with our historical and unaudited financial information, together with the notes
thereto, where applicable, incorporated by reference herein.

AS OF MARCH 31, 2003
---------------------
ACTUAL AS ADJUSTED
------- -----------
(IN MILLIONS)

Cash and cash equivalents................................... $ 388 $ 388
======= =======
Restricted cash............................................. $ 177 $ 442
======= =======
Collateral for letters of credit relating to energy trading
and hedging activities.................................... $ 145 $ 145
======= =======
Margin deposits on energy trading and hedging activities.... $ 344 $ 344
======= =======
Current maturities of long-term debt and short-term
borrowings................................................ $ 448 $ 448
Reliant Resources credit facilities......................... 5,125 4,069
Notes offered............................................... -- 275
Senior secured notes........................................ -- 1,100
Other long-term debt........................................ 2,372 2,372
------- -------
Total debt.................................................. 7,945 8,264
------- -------
Stockholders' equity:
Preferred stock, par value $0.001 per share; 125,000,000
shares authorized; none outstanding.................... -- --
Common stock, par value $0.001 per share; 2,000,000,000
shares authorized; 299,804,000 issued.................. -- --
Additional paid-in capital................................ 5,877 5,877
Treasury stock at cost, 7,672,245 shares.................. (132) (132)
Retained deficit.......................................... (449) (479)
Accumulated other comprehensive loss...................... (33) (33)
------- -------
Total stockholders' equity.................................. 5,263 5,233
------- -------
Total capitalization........................................ $13,208 $13,497
======= =======

SELECTED FINANCIAL INFORMATION AND OTHER DATA

The following tables present our selected consolidated financial data for
1998 through 2002 and the three months ended March 31, 2002 and March 31, 2003.
The financial data for 1998, 1999 and 2000 are derived from the consolidated
historical financial statements of CenterPoint. The financial data for 2001 and
2002 are derived from our audited financial statements. The financial data for
the three months ended March 31, 2002 and March 31, 2003, are derived from our
unaudited interim consolidated financial statements. The data set forth below
should be read together with "Management's Discussion and Analysis of Financial
Condition and Results of Operations" for the three years ended December 31,
2000, 2001 and 2002 included in our Current Report on Form 8-K filed on June 5,
2003, incorporated by reference herein, our historical consolidated financial
statements and the notes to those statements included in our Current Report on
Form 8-K filed on June 30, 2003, incorporated by reference herein, "Management's
Discussion and Analysis of Financial Condition and Results of Operations" for
the three months ended March 31, 2002 and 2003 included in our Current Report on
Form 8-K filed on July 23, 2003, incorporated by reference herein, and our
interim consolidated financial statements and the notes to those statements
included in our Current Report on Form 8-K filed on July 23, 2003, incorporated
by reference herein. The historical financial information may not be indicative
of our future performance and the historical financial information for 1998,
1999 and 2000 does not reflect what our financial position and results of
operations would have been had we operated as a separate, stand-alone entity
during the periods presented.

INCOME STATEMENT DATA:
Revenues........................... $277 $601 $2,732 $5,507 $10,638 $1,607 $2,633
Trading margins.................... 33 88 198 378 288 51 (74)
---- ---- ------ ------ ------- ------ ------
Total......................... 310 689 2,930 5,885 10,926 1,658 2,559
---- ---- ------ ------ ------- ------ ------
Expenses:
Fuel and cost of gas sold........ 102 293 911 1,576 1,086 163 375
Purchased power.................. 13 149 926 2,498 7,421 1,031 1,708
Accrual for payment to
CenterPoint................... -- -- -- -- 128 -- 47
Operation and maintenance........ 65 128 336 464 786 150 197
General, administrative and
development................... 78 94 270 471 643 110 123
Depreciation and amortization.... 15 23 118 171 378 57 89
---- ---- ------ ------ ------- ------ ------
Total......................... 273 687 2,561 5,180 10,442 1,511 2,539
---- ---- ------ ------ ------- ------ ------
Operating income................... 37 2 369 705 484 147 20
---- ---- ------ ------ ------- ------ ------
Other income (expense):
Gains (losses) from
investments................... -- 14 (22) 23 (23) 3 1
(Loss) income of equity
investments of unconsolidated
subsidiaries.................. (1) (1) 43 7 18 4 (1)
Gain on sale of development
project....................... -- -- 18 -- -- -- --
Other, net....................... 1 1 -- 2 23 (3) (3)
Interest expense................. (2) -- (7) (16) (267) (29) (97)
Interest income.................. 1 1 16 22 28 2 14
Interest income
(expense) -- affiliated
companies, net................ 2 (6) (172) 12 5 3 --
---- ---- ------ ------ ------- ------ ------
Total other income
(expense)................... 1 9 (124) 50 (216) (20) (86)
---- ---- ------ ------ ------- ------ ------
Income (loss) from continuing
operations before income taxes... 38 11 245 755 268 127 (66)
Income tax expense (benefit)..... 17 6 102 292 121 46 (20)
---- ---- ------ ------ ------- ------ ------
Income (loss) from continuing
operations....................... 21 5 143 463 147 81 (46)
---- ---- ------ ------ ------- ------ ------
Income (loss) from operations of
discontinued European energy
operations.................... -- 15 73 79 (380) 12 (369)
Income tax (benefit) expense..... -- (4) (7) (18) 93 (3) 12
---- ---- ------ ------ ------- ------ ------
Income (loss) from discontinued
operations.................... -- 19 80 97 (473) 15 (381)
---- ---- ------ ------ ------- ------ ------
Income (loss) before cumulative
effect of accounting changes..... 21 24 223 560 (326) 96 (427)
Cumulative effect of accounting
changes, net of tax.............. -- -- -- 3 (234) (234) (25)
---- ---- ------ ------ ------- ------ ------
Net income (loss).................. $ 21 $ 24 $ 223 $ 563 $ (560) $ (138) $ (452)
==== ==== ====== ====== ======= ====== ======

BASIC EARNINGS (LOSS) PER SHARE:
Income (loss) from continuing
operations.................... $ 1.67 $ 0.51 $ 0.28 $(0.16)
Income (loss)from discontinued
operations, net of tax........ 0.35 (1.63) 0.05 (1.31)
------ ------- ------ ------
Income (loss) before cumulative
effect of accounting
changes....................... 2.02 (1.12) 0.33 (1.47)
Cumulative effect of accounting
changes, net of tax........... .01 (0.81) (0.81) (0.08)
------ ------- ------ ------
Net income (loss)................ $ 2.03 $ (1.93) $(0.48) $(1.55)
====== ======= ====== ======
DILUTED EARNINGS (LOSS) PER SHARE:
Income from continuing
operations.................... $ 1.67 $ 0.50 $ 0.28 $(0.16)
Income (loss) from discontinued
operations, net of tax........ 0.35 (1.62) 0.05 (1.31)
------ ------- ------ ------
Income (loss) before cumulative
effect of accounting
changes....................... 2.02 (1.12) 0.33 (1.47)
Cumulative effect of accounting
changes, net of tax........... .01 (0.80) (0.81) (0.08)
------ ------- ------ ------
Net income (loss)................ $ 2.03 $ (1.92) $(0.48) $(1.55)
====== ======= ====== ======

THREE MONTHS ENDED
YEAR ENDED DECEMBER 31, MARCH 31,
---------------------------------------------------- -------------------
1998 1999 2000 2001 2002 2002
(1) (1) (1)(5) (1)(2)(5) (1)(3) (5) 2003
------- -------- -------- --------- -------- -------- --------
(IN MILLIONS, EXCEPT OPERATING DATA)

STATEMENT OF CASH FLOW DATA:
Cash flows from operating
activities................. $ (2) $ 38 $ 335 $ (152) $ 519 $ 396 $ (227)
Cash flows from investing
activities................. (365) (1,406) (3,013) (838) (3,486) (3,127) (190)
Cash flows from financing
activities................. 379 1,408 2,721 1,000 3,981 2,861 (314)
OTHER OPERATING DATA:
Trading and marketing
activity(6):
Natural gas (Bcf)(7)....... 1,115 1,481 2,273 3,265 3,449 951 360
Power sales (thousand
MWh)(7)................. 61,195 128,266 125,971 222,907 306,425 69,941 23,854
Power generation activity:
Wholesale power sales
(thousand MWh)(7)....... 2,973 10,204 39,300 62,825 128,812 21,503 27,097
Retail power sales (GWh)..... -- -- -- 473 59,004 12,783 13,896
Net power generation capacity
(MW)....................... 3,800 4,469 9,231 11,109 19,888 16,753 19,888

DECEMBER 31,
----------------------------------------------
1998 1999 2000 2001 2002 MARCH 31,
(1) (1) (1)(5) (1)(5) (1) 2003
------ ------- ------- ------- ------- ---------
(IN MILLIONS)

BALANCE SHEET DATA:
Property, plant and equipment, net.... $ 270 $ 643 $ 2,439 $ 3,108 $ 7,294 $ 8,738
Total assets.......................... 1,409 5,624 13,475 11,726 17,637 18,838
Short-term borrowings................. -- -- -- 92 669 306
Long-term debt to third parties,
including current maturities........ -- 69 260 297 6,159 7,639
Accounts and notes (payable)
receivable -- affiliated companies,
net................................. (17) (1,333) (1,969) 445 -- --
Stockholders' equity.................. 652 741 2,345 5,984 5,653 5,263

---------------

(1) Our results of operations include the results of the following acquisitions,
all of which were accounted for using the purchase method of accounting,
from their respective acquisition dates: the five generating facilities in
California substantially acquired in April 1998, a generating facility in
Florida acquired in October 1999, the REMA acquisition that occurred in May
2000 and the Orion Power acquisition that occurred in February 2002. See
note 5 to our consolidated financial statements incorporated by reference
herein for further information about the acquisitions occurring in 2000 and
2002. In October 1999, we acquired REPGB, which is part of our European
energy operations. In February 2003, we signed an agreement to sell our
European energy operations to Nuon, a Netherlands-based electricity
distributor. In the first quarter of 2003, we began to report the results of
our European energy operations as discontinued operations in accordance with
SFAS No. 144 and accordingly, reclassified prior period amounts. For further
discussion of the sale, see note 23 to our consolidated financial statements
incorporated by reference herein.

(2) Effective January 1, 2001, we adopted SFAS No. 133 which established
accounting and reporting standards for derivative instruments. See note 7 to
our consolidated financial statements incorporated by reference herein for
further information regarding the impact of the adoption of SFAS No. 133.

(3) During the third quarter of 2002, we completed the transitional impairment
test for the adoption of SFAS No. 142 on our consolidated financial
statements, including the review of goodwill for impairment as of January 1,
2002. Based on this impairment test, we recorded an impairment of our
European energy segment's goodwill of $234 million, net of tax, as a
cumulative effect of accounting change. See note 6 to our consolidated
financial statements incorporated by reference herein for further
discussion.

(4) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis in the statements of
consolidated operations. Comparative financial statements for prior periods
have been reclassified to conform to this presentation. See note 2(t) to our
consolidated financial statements incorporated by reference herein for
further discussion.

(5) As described in note 1 to our consolidated financial statements incorporated
by reference herein, our consolidated financial statements for 2000 and 2001
and for the three months ended March 31, 2002 have been restated from
amounts previously reported. The restatement had no impact on previously
reported consolidated cash flows.

(6) Excludes financial transactions.

(7) Includes physical contracts not delivered.

MANAGEMENT'S DISCUSSION AND ANALYSIS
OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

For our most recent annual consolidated financial statements and notes, see
our Current Report on Form 8-K filed on June 30, 2003 and incorporated by
reference herein. For our most recent annual "Management's Discussion and
Analysis of Financial Condition and Results of Operations", see our Current
Report on Form 8-K filed on June 5, 2003 and incorporated by reference herein.
For our most recent interim consolidated financial statements and notes and
interim "Management's Discussion and Analysis of Financial Condition and Results
of Operations", see our Current Report on Form 8-K filed on July 23, 2003 and
incorporated by reference herein.

OUR BUSINESS

GENERAL

Our business operations consist of the following 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;

- Other operations -- includes our venture capital investment portfolio and
unallocated corporate costs.

Our European energy operations, formerly a financial reporting segment but
now classified as discontinued operations, operate power generation facilities
in the Netherlands and conduct wholesale energy trading and origination
activities in Europe. In February 2003, we entered into a definitive agreement
to sell this operation to Nuon.

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 electric 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 initial public offering of approximately 20% of our common stock in May 2001
and received net proceeds from our initial public offering of $1.7 billion. We
used $147 million of the net proceeds of our initial public offering 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.

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 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 Mid-Continent regional portfolio.

DISPOSITION OF EUROPEAN ENERGY OPERATIONS

In February 2003, we signed a share purchase agreement to sell our European
energy operations to Nuon, a Netherlands-based electricity distributor. Upon
consummation of the sale, we expect to receive cash proceeds from the sale of
approximately $1.2 billion (approximately Euro 1.1 billion as of March 31,
2003). We intend to use the cash proceeds from the sale first to repay the Euro
600 million bank term loan borrowed by RECE to finance a portion of the original
acquisition costs of our European energy operations. As additional consideration
for the sale, we will also receive 90% of the dividends and other distributions
in excess of approximately $120 million (approximately Euro 110 million as of
March 31, 2003) 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 $126 million
(approximately Euro 115 million as of March 31, 2003). If the amount of net cash
is
49

less on such date, the purchase price will be reduced accordingly. The sale is
subject to the approval of the Dutch competition authority. We anticipate that
the consummation of sale will occur in the summer of 2003.

DISPOSITION OF DESERT BASIN PLANT

On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant, located in Casa Grande, Arizona, to SRP for
$289 million. The transaction is expected to close by the end of 2003. We will
recognize a loss on the sale of our Desert Basin plant operations in the third
quarter of 2003 and in connection with the anticipated sale, we will report the
assets and liabilities to be sold as discontinued operations effective July
2003. For further discussion regarding the anticipated sale of our Desert Basin
plant operations and its impact on our results of operations, see "Risk
Factors -- Risks Related to Our Wholesale Energy Operations".

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 approximately 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 approximately 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
approximately one MW or greater of peak demand). We own certain ERCOT generation
facilities, which consist of ten power generation units completed or under
various stages of construction at seven facilities with an aggregate net
generation capacity of 805 MW located in Texas. The generating capacity of these
facilities consists of 100% base-load capacity.

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 have entered into contracts to provide retail
electric services to large commercial, industrial and institutional customers in
New Jersey beginning August 1, 2003, and 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". On May 21, 2003, the Maryland
Public Service Commission granted one of our wholly-owned subsidiaries a license
to provide electric service to large commercial, industrial and institutional
clients in that state.

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
50

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 who request it 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 up to twice a year. 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. As part of a request to change the
fuel factor for changes in purchased energy prices, we would have to show that
the fuel factor must be adjusted 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. In June 2003, we filed our
second and final request for 2003 with the PUCT to increase the price to beat
fuel factor based on a 23.1% increase in the price of natural gas. Our requested
increase was based on an average forward 12-month natural gas price of
$6.1000/MMbtu during the twenty-day trading period beginning May 14, 2003 and
ending June 11, 2003. The requested increase represents an increase of 9.2% in
the total bill of a residential customer using, on average, 12,000 kilowatt
hours per year. There can be no assurances such request will be approved. 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.

may be required to make a significant payment to CenterPoint in 2004. As of
March 31, 2003, our estimate for the payment related to residential customers is
between $160 million and $190 million, with a most probable estimate of $175
million. Currently, we believe that the 40% test for small commercial customers
will be met and we will not make a payment related to those customers. If the
40% test is not met related to our small commercial customers and a payment is
required, we estimate this payment would be approximately $30 million.

LARGE COMMERCIAL, INDUSTRIAL AND INSTITUTIONAL SERVICES -- SOLUTIONS BUSINESS

We provide electricity and energy services to large commercial, industrial
and institutional customers (i.e., customers with an aggregate peak demand of
greater than approximately one MW) in Texas with whom we have signed contracts.
As of April 30, 2003, the average contract term for these contracts was 16
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
approximately 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 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
14,000 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 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 or (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.
Concurrently with the closing of the senior secured notes offering, we entered
into an amendment to our new credit facilities to, among other things, increase
our flexibility to purchase CenterPoint's interest in Texas Genco. The amendment
allows us to negotiate a purchase of CenterPoint's interest in Texas Genco
outside the option at a price less than or equal to the price set under the
option and also extends the deadline for agreeing to purchase CenterPoint's
interest in Texas Genco to September 15, 2004.

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.

COMPETITION

For information regarding competitive factors affecting our retail energy
segment, see "Risk Factors -- Risks Related to Our Retail Energy Operations".

WHOLESALE ENERGY

Our wholesale energy segment provides energy and energy services with a
focus on the competitive segment of the United States wholesale energy markets.
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 market electric
energy, capacity and ancillary services and procure natural gas, coal, fuel oil,
natural gas transportation capacity and other energy-related commodities. We
also seek to 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 marketing and hedging
activities related to our electric generating facilities, pipeline
transportation capacity positions, pipeline storage positions and fuel
positions.

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. Moreover, during the second quarter of 2003, market liquidity was
negatively impacted by the filings for reorganization under Chapter 11 of the
United States Bankruptcy Code of three companies in the wholesale power
industry, NRG Energy Inc., NEG and Mirant Corp.

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 120 operating electric power
generation facilities with an aggregate net generating capacity of 19,083 MW
located in five regions of the United States (excluding our ERCOT generation
facilities). The generating capacity of these facilities consists of
approximately 32% of base-load, 36% of intermediate and 32% of peaking capacity.
We have two electric power generation facilities and replacement or incremental
electric power generation units at two 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:

TOTAL NET
NUMBER OF GENERATING
GENERATION CAPACITY
REGION FACILITIES(1) (MW)(2) DISPATCH TYPE(3) FUEL TYPE
------ ------------- ---------- ------------------------ ------------------

MID-ATLANTIC
Operating(4)................ 22 4,795 Base, Intermediate, Peak Gas/Coal/Oil/Hydro
Under -- 1,120 Base, Intermediate Gas/Coal
Construction(5)(6)(7).....
--- ------
Combined.................... 22 5,915
NEW YORK
Operating(8)................ 77 2,952 Base, Intermediate, Peak Gas/Oil/Hydro
MID-CONTINENT
Operating................... 9 4,484 Base, Intermediate, Peak Gas/Oil/Coal
Under Construction(5)....... 1 800 Intermediate, Peak Gas
--- ------
Combined.................... 10 5,284
SOUTHEAST
Operating(9)(10)............ 5 2,210 Base, Intermediate, Peak Gas/Oil
WEST
Operating(11)(12)(13)....... 7 4,642 Base, Intermediate, Peak Gas/Oil
Under Construction(5)....... 1 541 Base, Intermediate Gas
--- ------
Combined.................... 8 5,183
TOTAL
Operating................... 120 19,083
Under Construction.......... 2 2,461
--- ------
Combined.................... 122 21,544
=== ======

---------------

(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.

(8) Excludes two hydro plants with a net generating capacity of 5 MW, which are
not currently operational.

(9) 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) 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.

(12) 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%.

(13) Includes our 588-megawatt Desert Basin plant, located in Casa Grande,
Arizona. On July 9, 2003, we entered into a definitive agreement to sell
our Desert Basin plant to SRP.

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 4,795
MW located in Pennsylvania, New Jersey and Maryland. The generating capacity of
these facilities consists of approximately 45% of base-load, 28% of intermediate
and 27% of peaking capacity.

We are constructing a 795 MW gas-fired intermediate generation unit at an
existing facility located in Pennsylvania. We expect this unit will begin
commercial operation in the fourth 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. 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.

The following table describes the electric power generation facilities we
owned, leased or had under construction in the Mid-Atlantic region of the United
States as of March 31, 2003:

SUMMER/WINTER
NET GENERATING
GENERATION FACILITIES(1) LOCATION CAPACITY(MW) FUEL TYPE DISPATCH TYPE(2)
------------------------ ------------ -------------- ------------ ----------------

Operating
Blossburg.............. Pennsylvania 23 Gas Peak
Conemaugh.............. Pennsylvania 282 Coal/Oil Base/Peak
Deep Creek............. Maryland 19 Hydro Base
Gilbert................ New Jersey 615 Dual Inter/Peak
Glen Gardner........... New Jersey 184 Dual Peak
Hamilton............... Pennsylvania 23 Oil Peak
Hunterstown............ Pennsylvania 71 Dual Peak
Keystone............... Pennsylvania 284 Coal/Oil Base/Peak
Liberty................ Pennsylvania 568 Gas Base
Mountain............... Pennsylvania 47 Dual Peak
Orrtanna............... Pennsylvania 23 Oil Peak
Piney.................. Pennsylvania 28 Hydro Base
Portland............... Pennsylvania 584 Coal/Gas/Oil Base/Inter/Peak
Sayreville............. New Jersey 496 Dual Inter/Peak
Seward................. Pennsylvania 197 Coal Base/Inter
Shawnee................ Pennsylvania 23 Oil Peak
Shawville(3)........... Pennsylvania 614 Coal/Oil Base/Peak
Titus.................. Pennsylvania 281 Coal/Dual Inter/Peak
Tolna Station.......... Pennsylvania 47 Oil Peak
Warren................. Pennsylvania 68 Dual Peak
Wayne.................. Pennsylvania 66 Oil Peak
Werner................. New Jersey 252 Oil Peak
-----
Total Operating.......... 4,795
-----
Under Construction
Hunterstown(4)......... Pennsylvania 795 Gas Inter
Seward(4).............. Pennsylvania 325 Coal Base
-----
Total Under
Construction........... 1,120
-----
TOTAL COMBINED........... 5,915
=====

---------------

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.
All of these facilities are operational.

(2) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking facilities,
respectively.

(3) We lease a 100% interest in the Shawville Station, a 16.67% interest in the
Keystone Station and a 16.45% interest in the Conemaugh Station under
facility interest lease agreements with original terms of 26.25 years, 33.75
years and 33.75 years, respectively.

(4) We expect the Hunterstown plant will begin commercial operation in the
fourth quarter of 2003 and the Seward plant will begin commercial operation
in the third quarter of 2004.

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.

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.

The following table describes the electric power generation facilities we
owned, leased or had under construction in the New York region of the United
States as of March 31, 2003:

SUMMER/WINTER
NET GENERATING
GENERATION FACILITIES(1) LOCATION CAPACITY (MW) FUEL TYPE DISPATCH TYPE(2)
------------------------ -------- -------------- --------- ----------------

Operating
Astoria....................... New York 1,277 Gas/Dual Inter/Peak
Carr Street................... New York 101 Gas Inter
Gowanus....................... New York 597 Dual/Oil Peak
Narrows....................... New York 305 Dual Peak
Hydroelectric assets.......... New York 672 Hydro Base
-----
Total Operating................. 2,952
=====

---------------

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.
All of these facilities are operational.

(2) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking facilities,
respectively.

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 of $105 per KW per year, and sales capacity from
substantially all our existing in-city generating units are subject to this 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.

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.

MID-CONTINENT REGION

Facilities. We own 9 operating electric power generation facilities with
an aggregate net generating capacity of 4,484 MW located in Illinois, Ohio,
Pennsylvania and West Virginia. The generating capacity of these facilities
consists of approximately 51% of base-load, 7% of intermediate and 42% of
peaking capacity.

We are constructing an 800 MW gas-fired intermediate and peaking facility
in Mississippi. We expect this facility will begin commercial operations in the
third quarter of 2003.

The following table describes the electric power generation facilities we
owned or had under construction in the Mid-Continent region of the United States
as of March 31, 2003:

SUMMER/WINTER
NET GENERATING
GENERATION FACILITIES(1) LOCATION CAPACITY (MW) FUEL TYPE DISPATCH TYPE(2)
------------------------ ------------- -------------- --------- ----------------

Operating
Aurora...................... Illinois 912 Gas Peak
Avon Lake................... Ohio 721 Coal/Oil Base/Peak
Brunot Island............... Pennsylvania 367 Gas/Oil Inter/Peak
Ceredo...................... West Virginia 475 Gas Peak
Cheswick.................... Pennsylvania 566 Coal Base
Elrama...................... Pennsylvania 487 Coal Base
New Castle.................. Pennsylvania 339 Coal/Gas Base/Peak
Niles....................... Ohio 246 Coal/Gas Base/Peak
Shelby County............... Illinois 371 Gas Peak
-----
Total Operating............... 4,484
Under Construction
Choctaw..................... Mississippi 800 Gas Inter/Peak
-----
TOTAL COMBINED................ 5,284
=====

---------------

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.

(2) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking facilities,
respectively.

Market Framework. We generally sell the electric energy, capacity and
ancillary services generated and/or provided by our Mid-Continent 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 an
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.

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 Mid-Continent
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
Mid-Continent 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
Light in the greater Pittsburgh area under one contract through December 2004
and another which does not have a fixed termination date. During periods when
the capacity of the generating facilities in our Mid-Continent region exceeds
the power demands of the Duquesne Light, we may sell the excess power into the
market.

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.

The following table describes the electric power generation facilities we
owned in the Southeast region of the United States as of March 31, 2003:

NET GENERATING
GENERATION FACILITIES(1) LOCATION CAPACITY (MW) FUEL TYPE DISPATCH TYPE(2)
------------------------ -------- -------------- --------- ----------------

Operating
Sabine(3).......................... Texas 54 Gas Base
Indian River....................... Florida 587 Dual Inter
Osceola............................ Florida 465 Dual Peak
Leased facilities(4)............... Florida 1,104 Dual Peak
-----
Total Operating...................... 2,210
=====

---------------

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.

(2) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking facilities,
respectively.

(3) We own a 50% interest in this facility. An independent third party owns the
other 50%.

(4) 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. One of these facilities
is currently owned by Mirant Corp., which filed for reorganization under
Chapter 11 of the United States Bankruptcy Code on July 14, 2003.

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 and
intermediate generation facility in southern Nevada. We expect this facility
will begin commercial operation in the fourth quarter of 2003.

The following table describes the electric power generation facilities we
owned or had under construction in the West region of the United States as of
March 31, 2003:

SUMMER/WINTER
NET GENERATING
GENERATION FACILITIES(1) LOCATION CAPACITY (MW) PRIMARY FUEL DISPATCH TYPE(2)
------------------------ ---------- -------------- ------------ ----------------

Operating
Coolwater..................... California 658 Gas/Dual Inter
Desert Basin(3)............... Arizona 588 Gas Base
El Dorado(4).................. Nevada 235 Gas Base
Ormond Beach.................. California 1,525 Gas Inter
Etiwanda...................... California 1,022 Gas Inter/Peak
Mandalay...................... California 560 Gas Inter/Peak
Ellwood....................... California 54 Gas Peak
-----
Total Operating................. 4,642
Under Construction
Big Horn(5)................... Nevada 541 Gas Base/Inter
-----
TOTAL COMBINED.................. 5,183
=====

---------------

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.

(2) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking facilities,
respectively.

(3) On July 9, 2003, we entered into a definitive agreement to sell our Desert
Basin plant to SRP. For further discussion regarding the sale of our Desert
Basin operations and its impact on our results of operations, see "Risk
Factors -- Risks Related to Our Wholesale Energy Operations".

(4) We own a 50% interest in the El Dorado facility. Sempra Energy owns the
other 50%.

(5) We expect this facility will begin commercial operation in the fourth
quarter of 2003.

Market Framework. Our West regional market includes the states of Arizona,
California, Oregon, Nevada, New Mexico, Utah and Washington. Generally we sell
the 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. On July
9, 2003, we entered into a definitive agreement to sell the 588 MW plant to SRP.
The transaction is expected to close by the end of 2003. 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 have
evaluated the available capacity in California and determined that we will make
the investment in the necessary environmental upgrades. We estimate that the
cost of the necessary upgrades for both units will be approximately $9 million,
of which $2 million has already been spent. Unit 5 at Etiwanda is subject to a
similar standard which goes into effect on January 1, 2004. See
"-- Environmental Matters".

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.

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.

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.

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(e), 14(i) and 14(j) to our consolidated
financial statements incorporated by reference herein. For information regarding
our hedging strategy relating to such long-term commitments, see "Risk
Factors -- Risks Related to Our Wholesale Energy Operations".

COMMERCIAL OPERATIONS -- MARKETING, TRADING, POWER ORIGINATION AND RISK
MANAGEMENT

Strategy. Our domestic commercial business seeks to optimize our physical
asset positions consisting of our power generation asset portfolio, pipeline
transportation capacity positions, pipeline storage positions and fuel positions
and provides risk management services for our asset positions. We perform these
functions through procurement, 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
64

result, we have reduced our trading workforce from 264 to 160 as of December 31,
2002, which 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 marketing and hedging activities related to our electric generating
facilities, pipeline transportation capacity positions, 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.

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 rights 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 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
enabled our commercial groups to take selective 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 transportation capacity positions, 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 and Non-Trading Operations -- Trading and
Marketing Operations" and "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Quantitative and Qualitative Disclosures
About Market Risk" for the three years ended December 31, 2000, 2001 and 2002
and for the three months ended March 31, 2002 and 2003, incorporated by
reference herein.

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 those facilities 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 market-based rates. In its orders authorizing
market-based rates, the FERC also has granted certain of 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. As discussed above under "Risk
Factors -- Risks Related to Our Wholesale Energy Options," the FERC recently
issued a Show Cause order proposing to revoke the market-based rate authority of
Reliant Energy Services. 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
66

market design that will lower delivered energy costs, maintain reliability,
mitigate market power and increase customer choice options. SMD 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. However, there is substantial controversy surrounding the
development of SMD, and it is unclear whether SMD would be implemented and what
form it would take.

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 subsidiaries have received determinations of exempt wholesale
generator status from the FERC or are companies that own or operate qualifying
facilities. 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 "Risk Factors -- Risks Related to Our Wholesale Energy Operations".

EUROPEAN ENERGY

In February 2003, we agreed to sell our European energy operations to Nuon,
a Netherlands-based electricity distributor. The sale is subject to the approval
of the Dutch competition authority. We anticipate the consummation of the sale
in the summer of 2003.

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 March 31, 2003, the net book value
of these investments was $41 million.

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 clean up or decommission disposal or fuel storage areas and
other locations as necessary. We anticipate spending approximately $173 million
from 2003 through 2007 for such environmental compliance and remediation. These
figures exclude our Netherlands operations which are the subject of a pending
sale to Nuon. For a discussion of the pending sales, see "Management's
Discussion and Analysis of Financial Conditions and Results of
Operations -- Overview" for the three years ended December 31, 2000, 2001 and
2002 and for the three months ended March 31, 2002 and 2003, incorporated by
reference herein.

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.
68

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
addition to the EPA's requests for information, the New Jersey Department of
Environmental Protection (NJDEP) recently requested a copy of all correspondence
relating to the EPA requests for information. To date, NJDEP has taken no
further action in connection with this request for one of the six stations.

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 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. On
May 30, 2003, we notified the South Coast Air Quality Management District that
we would install a selective catalytic reduction system by the end of March
2004, rather than surrender the permits for these units. 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. Although
we have initiated the process to obtain permits necessary to install such
technology, whether we will proceed with such installation will depend upon the
economic market for this unit which has not yet been determined. If we elect to
proceed with such installation, it will be necessary to seek an extension of the
deadline for completing such installation.

We have also been addressing issues with our Cheswick, Pennsylvania
facility's compliance with the visible emission (opacity) standards contained in
its air permit. Although we have substantially reduced the frequency of the
opacity exceedances since we acquired the facility as part of the Orion Power
acquisitions, we recently received a letter, dated April 28, 2003, from the
Group Against Smog and Pollution (GASP) notifying us of their intent to initiate
an action under the citizens' suit provisions of the state and federal clean air
laws to compel compliance and seek civil penalties. We do not anticipate that
the cost of achieving compliance will involve material expenditures, but the
potential penalties sought in such an action for past violations could exceed
$100,000. The threatened action has not yet been commenced. Accordingly, we do
not know whether the action will, in fact, be commenced or whether the penalties
sought will be material.
69

FERC

Last year the FERC granted ten new licenses for 23 of our hydroelectric
facilities in New York. (For additional information related to the FERC, see
"Risk Factors -- Risks Related to Our Wholesale Energy Operations"). The FERC
imposed conditions in such licenses which will require us to spend approximately
$21 million in capital expenditures in order to comply with such conditions.
Applications for new FERC licenses remain pending for seven of our hydroelectric
facilities in New York. Conditions which may be imposed in such additional new
licenses may also result in capital expenditures.

In the course of the FERC licensing proceedings various agencies have
requested increased flow rates downstream of the dams in order to enhance fish
habitats and for other purposes. The FERC has imposed conditions in the new
licenses to increase such flow rates and we expect that the FERC will also
impose similar conditions in the licenses for which applications remain pending.
Increased flow rates may affect revenues for these facilities due to the loss of
use of water for power generation. However, all of the minimum flow requirements
and other environmental conditions in the respective licenses are the result of
settlement agreements negotiated by us and our predecessors and settlement
agreements are being pursued for the remaining pending license applications.
Therefore, we do not expect such lost revenues to be material to the economic
viability of such facilities.

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 rulemaking
dealing with Section 316(b) and generally would affect existing facilities that
use significant quantities of cooling water. Under the amended court deadline,
the 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. We expect our
remaining obligation with respect to such remediation to be less than $1
million. In August 2000, we signed a modified consent order agreement that
committed us to complete the remediation no later than November 2004.

We are responsible for the costs of closing a number of active ash and
related waste disposal sites associated with certain of our facilities, located
in Pennsylvania. A number of such sites have already been closed (for which we
are responsible for long-term maintenance costs), some will be closed within the
next five years, and the remainder are anticipated to be closed thereafter. We
have estimated that the total cost of our share to close these active sites
(including future maintenance costs at closed sites) to be approximately $43
million. The portion of this figure estimated to be incurred in the years 2003
through 2007 is included in the environmental compliance and remediation figure
for that period provided above. For risks associated with environmental
compliance, see "Environmental Matters -- General".

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 ensuring that in connection with the transfer of such a facility
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 transfer of four New Jersey properties we purchased from Sithe
Energies, Inc. We estimate that the remaining 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 by the prior owners. The remaining portion of the liability we
assumed for historical releases at all of these New York plants is approximately
$7 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.

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 and similar state laws, owners and operators of facilities
from or at 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.

LEGAL PROCEEDINGS

For a discussion regarding certain legal proceedings affecting us, see note
14(g) to our consolidated financial statements incorporated by reference herein
and note 13(d) to our interim consolidated financial statements incorporated by
reference herein.

EMPLOYEES

As of December 31, 2002, we had 6,002 full-time employees. Of these
employees, 1,930 are covered by collective bargaining agreements. The collective
bargaining agreements expire on various dates until May 14, 2007. The following
table sets forth the number of our employees by business segment as of December
31, 2002:

SEGMENT NUMBER
------- ------

Retail energy............................................... 1,633
Wholesale energy............................................ 3,143
European energy............................................. 680
Other operations............................................ 546
-----
Total..................................................... 6,002
=====

PROPERTIES

Our corporate offices currently occupy approximately 500,000 square feet of
leased office space in Houston, Texas, which lease expires in January 2004.
During 2003, we expect to relocate our corporate offices. Upon relocation, our
corporate offices will occupy approximately 520,000 square feet of leased office
space in Houston, Texas. Our new lease expires in 2018, subject to two five-year
renewal options.

In addition to our corporate office space, we lease or own various real
property and facilities relating to our generation assets and development
activities. Our principal generation facilities are generally described under
"-- Wholesale Energy". We believe we have satisfactory title to our facilities
in accordance with standards generally accepted in the electric power industry,
subject to exceptions, which, in our opinion, would not have a material adverse
effect on the use or value of the facilities.

MANAGEMENT

DIRECTORS AND EXECUTIVE OFFICERS

Our directors and executive officers, including their ages as of July 21,
2003, are as follows:

NAME AGE PRESENT POSITION
---- --- ----------------

Joel V. Staff.......................... 59 Chairman and Chief Executive Officer
Stephen W. Naeve....................... 56 Vice Chairman
Robert W. Harvey....................... 47 Executive Vice President and Group
President -- Wholesale Business
Mark M. Jacobs......................... 41 Executive Vice President and Chief
Financial Officer
Jerry Langdon.......................... 51 Executive Vice President and Chief
Administrative Officer
Michael L. Jines....................... 45 Senior Vice President, General Counsel
and Corporate Secretary
Thomas C. Livengood.................... 48 Vice President and Controller
Laree E. Perez......................... 49 Director
William L. Transier.................... 49 Director
E. William Barnett..................... 70 Director
Donald J. Breeding..................... 68 Director

JOEL V. STAFF has served as our Chairman and Chief Executive Officer since
the resignation of R. Steve Letbetter, our former Chairman and Chief Executive
Officer, in April 2003. Until May 2002, he was with National-Oilwell, Inc.,
where he served as chairman, president and chief executive officer from July
1993 until May 2001. Previously, Mr. Staff spent 17 years with Baker Hughes,
Inc. where he held various financial and general management positions, including
senior vice president of the parent company and president of both the drilling
and production groups. Mr. Staff serves on the board of directors of
National-Oilwell, Inc. where he is a member of its executive committee and Ensco
International, Incorporated, where he is a member of its audit committee. He is
chairman of the board of directors of T-3 Energy Services, Inc., where he also
serves as chairman of T-3 Energy Services' compensation and nominating committee
and as a member of its audit committee.

STEPHEN W. NAEVE is our Vice Chairman. Prior to becoming our Vice Chairman
in May 2003, he served as our President and Chief Operating Officer. He has
served as Vice Chairman of CenterPoint from June 1999 until the Distribution and
as Chief Financial Officer of CenterPoint from 1997 until the Distribution. From
1997 to 1999, Mr. Naeve held the position of Executive Vice President and Chief
Financial Officer of CenterPoint. Since 1988, he served in various officer
capacities with CenterPoint, including Vice President -- Strategic Planning and
Administration between 1993 and 1996. Mr. Naeve resigned as Vice Chairman of
CenterPoint at the time of the Distribution.

ROBERT W. HARVEY is our Executive Vice President and Group
President -- Wholesale Business. Prior to being appointed to such position in
May 2003, he served as our Executive Vice President and Group
President -- Retail Business. Mr. Harvey served as Vice Chairman of CenterPoint
from June 1999 until the Distribution. From 1982 to 1999, Mr. Harvey was
employed with the Houston office of McKinsey & Co., Inc. He was a director
(senior partner) and was the leader of the firm's North American electric power
and natural gas practice. Mr. Harvey resigned as Vice Chairman of CenterPoint at
the time of the Distribution.

MARK M. JACOBS is our Executive Vice President and Chief Financial Officer.
Mr. Jacobs served as Executive Vice President and Chief Financial Officer of
CenterPoint from July 2002 until the Distribution. From 1989 to 2002, Mr. Jacobs
was employed by Goldman, Sachs & Co. He was a Managing Director in

the firm's Natural Resources Group. Mr. Jacobs resigned as Executive Vice
President and Chief Financial Officer of CenterPoint at the time of the
Distribution.

JERRY LANGDON has served as our Executive Vice President and Chief
Administrative Officer since May 2003. Mr. Langdon served as president of EPGT
Texas Pipeline, L.P. from June 2001 until May 2003. He served as the Managing
Partner and Chief Operating Officer of CARLANG Partners, L.P. from September
1999 until November 2001 and the President of Republic Gas Corporation from June
1993 until June 2001. In October 1988, Mr. Langdon was appointed by President
Reagan to be a Commissioner to the Federal Energy Regulatory Commission, where
he served until 1993. He has served as a director on the Gas Industry Standards
Board (now the North American Energy Standards Board) since 1999 and is Chairman
of the National Petroleum Council Coordinating Subcommittee. Mr. Langdon has
served as an advisory director of Highland Energy Company since 1998, an
advisory director of DLJ Global Energy Partners from 1999 until 2000 and a
director of Costilla Energy Inc., Quanta Services, Inc. and Midcoast Energy,
Inc. at various times from June 1996 to February 2002.

MICHAEL L. JINES is our senior vice president and acting general counsel.
Until mid-2003, he was our deputy general counsel and senior vice president and
general counsel of our Wholesale Group. Prior to the Distribution, Mr. Jines
served as deputy general counsel of CenterPoint and senior vice president and
general counsel of Reliant Resources' Wholesale Group. He joined CenterPoint in
1982.

THOMAS C. LIVENGOOD is our Vice President and Controller. Prior to joining
us in August 2002, he served as Executive Vice President and Chief Financial
Officer of Carriage Services, Inc., a publicly traded consumer services company,
since 1996. From 1991 to 1996, he served as Vice President and Chief Financial
Officer of Tenneco Energy Company, a division of Tenneco, Inc.

LAREE E. PEREZ has been a Director of Reliant Resources since April 2002.
Ms. Perez is an independent financial consultant in Albuquerque, New Mexico with
the Medallion Company. From February 1996 until September 2002, she was Vice
President of Loomis, Sayles & Company, L.P. Ms. Perez was co-founder, president
and chief executive officer of Medallion Investment Company, Inc. from November
1991 until it was acquired by Loomis Sayles in 1996.

WILLIAM L. TRANSIER has been a Director of Reliant Resources since December
2002. Mr. Transier has served as executive vice president and chief financial
officer of Ocean Energy, Inc. since March 1999. From September 1998 to March
1999, he served as executive vice president and chief financial officer of
Seagull Energy Corporation. From May 1996 to September 1998, he served as senior
vice president and chief financial officer of Seagull Energy Corporation. Mr.
Transier is also a director of Cal Dive International, Inc. and chairman of its
audit committee.

E. WILLIAM BARNETT has been a Director of Reliant Resources since October
2002. Mr. Barnett is a retired partner and currently senior counsel with Baker
Botts LLP. He began practicing law with Baker Botts in 1958 and served as
managing partner from 1984 through the end of 1997. He serves on the board of
directors of numerous educational, health care and community organizations
including chairman of the board of trustees of Rice University and life trustee
of The University of Texas Law School Foundation.

DONALD J. BREEDING has been a Director of Reliant Resources since October
2002. Mr. Breeding has been president and chief executive officer of Airline
Management, LLC, engaged in aviation and airline consulting, since 1997. From
1992 to 1997, he was president and chief executive officer of Continental
Micronesia, a majority-owned subsidiary of Continental Airlines. From 1988 to
1992, he was senior vice president of operations for Continental Airlines with
responsibility for all flying operations activities of the company and
responsibility for Continental Express. Mr. Breeding serves as a member of the
board of directors of Pinnacle Airlines, Inc. and Miami Air International.

EXECUTIVE COMPENSATION

These tables show the compensation of the chief executive officer and the
four other most highly compensated executive officers in 2000, 2001 and 2002.
Reported compensation for 2000 was paid by CenterPoint.

SUMMARY COMPENSATION TABLE
FOR YEARS ENDED DECEMBER 31, 2000, 2001 AND 2002

LONG-TERM COMPENSATION
------------------------------------
ANNUAL COMPENSATION SECURITIES
----------------------------------------- RESTRICTED UNDERLYING
OTHER ANNUAL STOCK OPTION LTIP
NAME AND PRINCIPAL POSITION YEAR SALARY(1) BONUS(1) COMPENSATION(2) AWARD(3) AWARDS(4) PAYOUTS(5)
--------------------------- ---- ---------- ---------- --------------- ---------- ---------- ----------

R. Steve Letbetter(7)..... 2002 $1,000,000 -- $44,919 -- 700,000 $379,079
Former Chairman and 2001 983,750 $1,739,270 2,514 $1,690,000 850,000 812,479
Chief Executive Officer 2000 913,750 2,101,620 393 -- 400,000 213,166
Stephen W. Naeve.......... 2002 596,875 -- 141 -- 340,000 228,309
President and Chief 2001 568,750 773,500 88 901,345 420,000 334,560
Operating Officer 2000 537,500 752,500 81 -- 175,000 102,489
Robert W. Harvey(8)....... 2002 575,000 -- 2,701 -- 340,000 237,314
Executive Vice President 2001 568,750 773,500 2,720 901,345 420,000 --
& President -- Retail 2000 537,500 752,500 613 -- 175,000 --
Business
Hugh Rice Kelly(9)........ 2002 446,250 -- 3,427 -- 130,000 139,803
Former Senior Vice 2001 431,250 322,575 3,311 -- 160,000 382,360
President, General 2000 412,500 408,375 1,135 -- 80,000 134,970
Counsel and Corporate
Secretary
Mark M. Jacobs(10)........ 2002 202,865 -- -- 959,629 318,667 --
Executive Vice President
and Chief Financial
Officer

ALL OTHER
NAME AND PRINCIPAL POSITION COMPENSATION(6)
--------------------------- ---------------

R. Steve Letbetter(7)..... $208,690
Former Chairman and 315,542
Chief Executive Officer 121,472
Stephen W. Naeve.......... 107,241
President and Chief 120,259
Operating Officer 81,290
Robert W. Harvey(8)....... 154,321
Executive Vice President 166,573
& President -- Retail 123,014
Business
Hugh Rice Kelly(9)........ 104,186
Former Senior Vice 108,861
President, General 84,291
Counsel and Corporate
Secretary
Mark M. Jacobs(10)........ 11,870
Executive Vice President
and Chief Financial
Officer

---------------

(1) The amounts shown include salary and bonus earned as well as earned but
deferred compensation.

(2) The amounts shown include tax gross-ups paid to compensate for tax
consequences of imputed income under the executive life insurance plan and
the discount for any shares of our stock purchased under our employee stock
purchase plan. Mr. Letbetter's amount also includes preferential interest
paid on the deferred compensation that he elected to receive in 2002, in
excess of 120% of the applicable federal long-term rate.

(3) On July 29, 2002, Mr. Jacobs was granted an award of 205,488 shares of our
restricted stock, which vest in equal installments on the first, second and
third anniversaries of the date of grant. The amount shown is based on the
closing price of the underlying shares on that date. On May 4, 2001, the
following awards of our restricted stock were granted: Mr. Letbetter,
50,000 shares; Mr. Naeve, 26,667 shares and Mr. Harvey, 26,667 shares. The
amounts shown are based on the closing prices of those shares on May 4,
2001. The aggregate value of restricted stock awards held as of December
31, 2002, based on closing sales prices of the underlying shares on that
date, was $160,000 for Mr. Letbetter, $85,334 for Mr. Naeve, $85,334 for
Mr. Harvey and $657,562 for Mr. Jacobs. In the event dividends are paid on
the underlying common stock, dividend equivalents accrue on the restricted
stock.

(4) Securities underlying options are shares of our common stock, except for
grants in 2000, which are shares of common stock of CenterPoint.

(5) Amounts shown represent the dollar value of CenterPoint common stock paid
out in that year based on the achievement of performance goals for the
cycle ending in the prior year plus dividend equivalent accruals during the
performance period.

(6) Amounts for 2002 include (i) matching and profit sharing contributions to
the savings plan and the savings restoration component of our deferral plan
as follows: Mr. Letbetter, $193,449; Mr. Naeve, $97,627; Mr. Harvey,
$96,095; Mr. Kelly, $55,518; and Mr. Jacobs, $11,870; (ii) the term portion
of the premiums paid under split-dollar life insurance policies purchased
in connection with our executive life insurance plan, as follows: Mr.
Letbetter, $817; Mr. Naeve, $219; Mr. Harvey, $1,104; and Mr. Kelly,
$2,232; (iii) accrued interest on deferred compensation that exceeds 120%
of the applicable federal long-term rate, as follows: Mr. Letbetter,
$14,424; Mr. Naeve, $9,395; Mr. Harvey, $2,215; and Mr. Kelly, $46,436.
Additionally, the amount shown for Mr. Harvey for 2002 includes $54,907 in
loan forgiveness discussed in footnote 8 below.

(7) Mr. Letbetter resigned as our chairman and chief executive officer in April
2003.

(8) In connection with Mr. Harvey's initial employment, we loaned him $250,000.
The loan bears interest at a rate of 8% and principal and interest are to
be forgiven in annual installments through May 2004 so long as Mr. Harvey
remains employed by us or one of our subsidiaries as of each relevant
anniversary of his employment date. The amount of loan forgiveness for 2002
was $54,907, which amount is included in the "All Other Compensation"
column.

(9) Mr. Kelly retired as our senior vice president, general counsel and
corporate secretary in May 2003.

(10) Mr. Jacobs was not employed by us prior to July 2002.

OPTION GRANTS IN LAST FISCAL YEAR

NUMBER OF
SECURITIES % OF 2002 EXERCISE OR GRANT DATE
UNDERLYING OPTIONS EMPLOYEE BASE PURCHASE EXPIRATION PRESENT
GRANTED(1) OPTION GRANTS PRICE PER SHARE DATE VALUE(2)
------------------ ------------- --------------- ---------- ----------

R. Steve Letbetter(3)....... 700,000 9.80% $10.90 02/29/2012 $3,563,000
Stephen W. Naeve............ 340,000 4.76% 10.90 02/29/2012 1,730,600
Robert W. Harvey............ 340,000 4.76% 10.90 02/29/2012 1,730,600
Hugh Rice Kelly(4).......... 130,000 1.82% 10.90 02/29/2012 661,700
Mark M. Jacobs.............. 318,667 4.46% 4.79 07/28/2012 713,814

---------------

(1) Option grants vest in one-third increments per year generally from the date
of grant (so long as the officer remains an employee of Reliant Resources).
All options would immediately vest upon a change in control as defined in
our long-term incentive plan. A "change in control" generally is deemed to
have occurred if (i) any person or group becomes the direct or indirect
beneficial owner of 30% or more of our outstanding voting securities, unless
the acquisition is directly from us and approved by our board of directors;
(ii) our initial directors and individuals approved by a majority of the
initial directors (or their approved successors) cease to constitute a
majority of our board of directors; (iii) a merger, consolidation or
acquisition involving us is carried out, unless more than 70% of the
surviving company's outstanding voting securities is owned by our former
stockholders in substantially the same proportion as before the transaction,
any consideration paid by us (including the amount of any long-term debt
assumed by the surviving company) does not exceed 50% of the fair market
value of our outstanding voting securities immediately prior to the
transaction, no person or group becomes the beneficial owner of 30% of more
of the surviving company's voting securities as a result of the transaction,
and a majority of the directors of the surviving company were our directors
immediately prior to the transaction; or (iv) we transfer 70% or more of our
assets to another corporation that is not wholly-owned by us, unless after
the transfer more than 70% of the largest acquiring company's outstanding
voting securities is owned by our former stockholders and a majority of the
directors of the largest acquiring company were our directors immediately
prior to the transaction.

(2) Grant date value is based on the Black-Scholes option pricing model assuming
a five-year term, volatility of 46.99%, no annual dividend and a risk-free
interest rate of 4.43%. Actual gains, if any, will be dependent on future
performance of the common stock.

(3) Mr. Letbetter resigned as our chairman and chief executive officer in April
2003.

(4) Mr. Kelly retired as our senior vice president, general counsel and
corporate secretary in May 2003.

AGGREGATED OPTION EXERCISES IN LAST FISCAL YEAR
AND FISCAL YEAR-END OPTION VALUES

NUMBER OF SECURITIES
UNDERLYING VALUE OF UNEXERCISED
UNEXERCISED OPTIONS IN-THE MONEY OPTIONS
SHARES AT DECEMBER 31, 2002 AT DECEMBER 31, 2002($)(1)
ACQUIRED ON VALUE --------------------------- ---------------------------
NAME EXERCISE REALIZED EXERCISABLE UNEXERCISABLE EXERCISABLE UNEXERCISABLE
---- ----------- -------- ----------- ------------- ----------- -------------

R. Steve Letbetter(2)..... -- $ -- 823,354 1,371,814 $ -- $ --
Stephen W. Naeve.......... -- -- 377,482 666,002 -- --
Robert W. Harvey.......... -- -- 326,635 666,002 -- --
Hugh Rice Kelly(3)........ -- -- 209,720 257,696 -- --
Mark M. Jacobs............ -- -- -- 318,667 -- --

---------------

(1) Based on the average of the high and low sales prices of our common stock on
the New York Stock Exchange for December 31, 2002.

(2) Mr. Letbetter resigned as our chairman and chief executive officer in April
2003.

(3) Mr. Kelly retired as our senior vice president, general counsel and
corporate secretary in May 2003.
76

LONG-TERM INCENTIVE PLAN -- AWARDS IN LAST FISCAL YEAR(1)

ESTIMATED FUTURE PAYOUTS UNDER
NON-STOCK PRICE-BASED PLANS(2)
---------------------------------------------
BELOW
PERFORMANCE THRESHOLD THRESHOLD TARGET MAXIMUM
NUMBER OF PERIOD UNTIL NUMBER OF NUMBER OF NUMBER OF NUMBER OF
NAME SHARES PAYOUT SHARES SHARES SHARES SHARES
---- --------- ------------ --------- --------- --------- ---------

R. Steve Letbetter(3)........ 125,000 2002-2004 0 62,500 125,000 187,500
Stephen W. Naeve............. 60,000 2002-2004 0 30,000 60,000 90,000
Robert W. Harvey............. 60,000 2002-2004 0 30,000 60,000 90,000
Hugh Rice Kelly(3)........... 23,800 2002-2004 0 11,900 23,800 35,700
Mark M. Jacobs............... 25,488 2002-2004 0 12,744 25,488 38,232

---------------

(1) The payout of these awards can vary depending on Reliant Resources' total
stockholder return ("TSR") measured against its peer group competitors. A
performance modifier provides the incentive to maximize TSR relative to the
competitor peer group by modifying the payout value so that awards may range
from 0% to 150% of the target number of shares awarded. If a change in
control occurs prior to the end of the performance period, the participant's
right to receive shares will be settled with a cash payment to the
participant equal to the product of (i) the fair market value per share of
common stock on the date immediately preceding the date on which the change
of control occurs and (ii) 150% of the target number of shares.

(2) The table does not reflect dividend equivalent accruals, if any, during the
performance period.

(3) Mr. Letbetter resigned as our chairman and chief executive officer in April
2003, and Mr. Kelly retired as senior vice president, general counsel and
corporate secretary in May 2003. The plan allows for a partial award of the
target number of shares based on the relationship between the days the
participant was active during the cycle to the total number of days in the
three-year performance cycle.

STOCK OWNERSHIP

The following table sets forth information regarding beneficial ownership
of our common stock by each current director and nominee, our named executive
officers, and our directors, nominee and named executive officers as a group,
all as of March 27, 2003:

AMOUNT AND NATURE OF
NAME AND ADDRESS OF BENEFICIAL OWNER(1) BENEFICIAL OWNERSHIP(2) PERCENT OF CLASS
--------------------------------------- ----------------------- ----------------

E. William Barnett.............................. 7,615(3) *
Donald J. Breeding.............................. 7,879(3) *
Robert W. Harvey................................ 994,080(4)(5) *
Mark M. Jacobs.................................. 443,522(5) *
Hugh Rice Kelly................................. 775,696(4)(6) *
R. Steve Letbetter.............................. 3,768,306(4)(5)(7) 1.3%
Stephen W. Naeve................................ 1,255,342(4)(5) *
Laree E. Perez.................................. 9,865(3) *
Joel V. Staff................................... 9,678(3) *
William L. Transier............................. 7,500(3) *
All of the above officers and directors and
other executive officers as a group (11
persons)...................................... 7,298,666(4)(5) 2.4%

---------------

* Indicates that such director's or officer's ownership does not exceed 1% of
our outstanding common stock.

(1) The address of each beneficial owner is c/o Reliant Resources, Inc., 1111
Louisiana Street, Houston, Texas 77002.

(2) Includes shares owned directly or through the Reliant Resources, Inc.
Savings Plan.

(3) Includes 7,500 shares of restricted stock awarded in March 2003 under the
terms of our director compensation plan over which directors have no voting
or investment power until such shares vest upon the earlier or retirement or
at such time as he/she does not stand for reelection to the board of
directors.

(4) Includes shares covered by Reliant Resources' stock options and other rights
to acquire stock that are exercisable within 60 days, as follows: Mr.
Harvey, 625,970 shares; Mr. Kelly, 578,629 shares; Mr. Letbetter, 2,884,922
shares; Mr. Naeve, 675,365 shares; and the group, 4,764,886 shares.

(5) Includes shares held under the terms of compensation plans over which
executive officers have no voting or investment power until vesting in
accordance with the terms of the plans as follows: Mr. Harvey, 358,667
shares; Mr. Jacobs, 442,976 shares; Mr. Letbetter, 601,890 shares; Mr.
Naeve, 396,667 shares; and the group, 1,800,200 shares.

(6) Upon Mr. Kelly's retirement, 221,501 options became fully vested in
accordance with the terms of his severance agreement.

(7) Upon Mr. Letbetter's resignation, 1,250,001 options became fully vested in
accordance with the terms of his severance agreement.

CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

In the normal course of operations, we have entered into transactions and
agreements with related parties, including CenterPoint. For a discussion of
historical related-party transactions, see note 3 to our consolidated financial
statements incorporated by reference herein. Below are details of significant
current related party transactions, arrangements and agreements.

AGREEMENTS WITH CENTERPOINT

Master Separation Agreement. Shortly before our IPO, we entered into a
master separation agreement with CenterPoint. The agreement provided for the
separation of our assets and businesses from those of CenterPoint. It also
contains agreements governing the relationship between CenterPoint and us after
our IPO, and in some cases after the Distribution, and specifies the related
ancillary agreements that we have signed with CenterPoint, some of which are
described in further detail below.

The agreement provides for cross-indemnities intended to place sole
financial responsibility on us and our subsidiaries for all liabilities (except
for certain possible tax liabilities) associated with the current and historical
businesses and operations we conduct after giving effect to the separation,
regardless of the time those liabilities arise, and to place sole financial
responsibility for liabilities associated with CenterPoint's other businesses
with CenterPoint and its other subsidiaries. Each party has also agreed to
assume and be responsible for some specified liabilities associated with
activities and operations of the other party and its subsidiaries to the extent
performed for or on behalf of the other party's current or historical business.

The agreement also requires us to indemnify CenterPoint for any untrue
statement of a material fact, or omission of a material fact necessary to make
any statement not misleading, in the registration statement or prospectus that
we filed with the SEC in connection with our IPO.

Texas Genco Option. In connection with the separation of our businesses
from those of CenterPoint, CenterPoint granted us an option to purchase all of
the shares of capital stock owned by CenterPoint in January 2004 of Texas Genco,
which holds the Texas generating assets of CenterPoint's electric utility
division. For additional information regarding the Texas Genco option and
various agreements between Center Point and us related to the Texas Genco
option, see note 4(b) to our consolidated financial statements incorporated by
reference herein.

Service Agreements. We have entered into agreements with CenterPoint under
which CenterPoint will provide us, on an interim basis, various corporate
support services, information technology services and other previously shared
services such as corporate security, facilities management, accounts receivable,
accounts payable, remittance processing and payroll, office support services and
purchasing and logistics. The charges we will pay CenterPoint for these services
are generally intended to allow CenterPoint to recover its fully allocated costs
of providing the services, plus out-of-pocket costs and expenses. In addition,
pursuant to lease agreements, CenterPoint will lease us office space in its
headquarters building and various other locations in Houston, Texas for various
terms. For additional information regarding these agreements, see note 4(a) to
our consolidated financial statements incorporated by reference herein.

Payment to CenterPoint. To the extent that our price to beat for electric
service to residential and small commercial customers in CenterPoint's Houston
service territory during 2002 and 2003 exceeds the market price of electricity,
we may be required to make a significant payment to CenterPoint in 2004. As of
March 31, 2003, 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(d) to
our consolidated financial statements incorporated by reference herein.

Guarantee of Certain Benefit Payments. We have guaranteed, in the event
CenterPoint becomes insolvent, certain non-qualified benefits of CenterPoint's
and its subsidiaries' existing retirees at the Distribution totaling
approximately $58 million.

Transportation Agreement. Prior to the IPO, Reliant Energy Services (our
wholly-owned trading subsidiary) entered into an agreement whereby a subsidiary
of CenterPoint agreed to reimburse Reliant

Energy Services for any transportation payments made under a transportation
agreement with ANR Pipeline Company and for the refund of $41 million due to ANR
Pipeline Company, an unaffiliated company. For additional information regarding
this transportation agreement, see note 14(e) to our consolidated financial
statements incorporated by reference herein.

Generating Capacity Auction Line of Credit. On October 1, 2002, our retail
energy segment, through a subsidiary, entered into a master power purchasing
contract with Texas Genco covering, among other things, our purchase of capacity
and/or energy from Texas Genco's generating facilities. In connection with the
March 2003 refinancing, this contract has been amended to grant Texas Genco a
security interest in the accounts receivable and related assets of certain
retail energy segment subsidiaries, the priority of which is subject to certain
permitted prior financing arrangements, and the junior liens granted to the
lenders under the March 2003 refinancing. In addition, many of the covenant
restrictions contained in the contract were removed in the amendment. In
connection with the offering of senior secured notes on July 1, 2003, the junior
liens granted to the lenders were transferred to the collateral trustee under
the collateral trust agreement and now secure the lenders, the holders of the
senior secured notes and future holders of debt secured under the collateral
trust agreement. The intercreditor arrangements with Texas Genco also were
updated to reflect the transfer and the collateral trust agreement structure.

Various Other Agreements. In connection with the separation of our
businesses from those of CenterPoint, we have entered into other agreements
providing for, among other things, mutual indemnities and releases with respect
to our respective businesses and operations, matters relating to corporate
governance, matters relating to responsibility for employee compensation and
benefits, and the allocation of tax liabilities. In addition, we and CenterPoint
have entered into various agreements relating to ongoing commercial arrangements
including, among other things, the leasing of optical fiber and related
maintenance activities, gas purchasing and agency matters, and subcontracting
energy services under existing contracts. For additional information regarding
these agreements, see notes 3 and 4 to our consolidated financial statements
incorporated by reference herein.

EMPLOYMENT CONTRACTS AND SEVERANCE/CHANGE OF CONTROL AGREEMENTS

Our officers, with the exception of Mr. Jacobs and Mr. Harvey, entered into
severance agreements with us in January 2003. These agreements provide, in
general, for the payment of certain severance benefits in the event of an
involuntary termination of employment by us without cause or by the executive
during the three year period following a change in control of Reliant Resources,
Inc., as defined in our long-term incentive plan, for good reason (collectively,
a "covered termination"). Under the agreements, named officers who experience a
covered termination are entitled to three times the sum of his or her annual
salary and target bonus. Other officers that experience a covered termination
are entitled to a lump-sum severance payment ranging from one times to two times
the sum of his or her annual salary and target annual bonus depending on his or
her classification and compensation. In addition, each officer is entitled to a
pro rata portion of their current year bonus paid out at target, medical and
life insurance for 18 months, or in the case of a change in control, three
years, at the rate for active employees, outplacement services based upon his or
her classification and compensation, legal fees paid by us, and continued access
to financial planning services for the greater of the remainder of the calendar
year or 60 days. An additional payment will be made to an executive to
compensate for any excess parachute excise tax which may be imposed in
connection with severance payments made in connection with a change in control.
The agreements include a non-compete agreement between the executives and us,
which is not applicable following a covered termination that occurs following a
change in control. An executive's other benefits and awards on termination of
employment will be treated in accordance with the terms of the applicable plan
document. The term of the severance agreements is three years, with a one year
automatic renewal thereafter. Generally, for purposes of the severance
agreements, good reason is defined as a reduction in remuneration, or relocation
of more than 50 miles, and for certain officers, good reason also includes a
substantial reduction in authority and responsibility.

Harvey Severance Agreement. Mr. Harvey entered into a severance agreement
with us in May, 2003. Mr. Harvey's severance agreement has substantially the
same terms and conditions as the severance
80

agreements entered into with our other officers, except that (i) upon a covered
termination Mr. Harvey will also become fully vested in equity awards from us
made prior to January 1, 2004 (ii) the Harvey agreement contains an expanded
definition of good reason that (a) is applicable in the first three years of the
term of the agreement and (b) provides that if an event constituting good reason
occurs during such period, Mr. Harvey will receive his severance benefits even
absent the occurrence of a change in control.

Jacobs Severance Agreement. We entered into an employment agreement with
Mr. Jacobs in July 2002, which was subsequently amended, which sets forth his
compensation and duties and provides the applicable consequences upon any
termination of his employment. Mr. Jacobs will also be entitled to a
supplemental bonus at the end of the current term of his agreement if, at such
time, the aggregate value of his initial option and restricted stock awards does
not equal or exceed $1,850,000. Under the agreement, Mr. Jacobs is generally
provided with the same severance terms and benefits as the terms and benefits
described above with respect to the other named executive officer's severance
agreements (other than Mr. Harvey).

Letbetter Severance Agreement. In connection with his resignation in April
2003, Mr. Letbetter entered into an amendment to his severance agreement,
pursuant to which he will receive severance payments equaling $6.9 million and a
pro rata bonus with respect to our 2003 fiscal year of $747,946. In addition,
Mr. Letbetter's medical insurance continues at active employee rates until age
65, his financial planning service is available up to a maximum cost of $25,000
and he is eligible for outplacement assistance up to a maximum cost of $100,000.
Mr. Letbetter may also elect to purchase from us the split-dollar life insurance
policy at the greater of the cash surrender value of the policy or the total
premiums paid by us with respect to the policy. In addition, under the amended
severance agreement Mr. Letbetter has entered into a consulting agreement with
us for a minimum of 12 months under which he will be paid monthly installments
of $83,333, with any services provided above the normal annual hour commitment
paid at $500 per hour, and in April 2004, he will vest in 551,890 shares of
restricted stock previously awarded to him, provided he does not breach the
non-compete provision in his amended severance agreement during that period. His
benefit under our 1985 deferred compensation plan will be paid to him in 15
annual installments of $49,152. Mr. Letbetter will be provided office space,
parking and support for a three year period, continued home security monitoring
until age 65, a transfer of the club membership previously provided to him and
continued coverage under our directors' and officers' insurance. In addition,
Mr. Letbetter's unvested options became immediately exercisable upon his
resignation.

Kelly Severance Agreement. Mr. Kelly's retirement will be treated as a
covered termination under his severance agreement, pursuant to which he will
receive a severance payment equal to three times his salary and target bonus,
approximately $2.3 million, and a pro rata bonus with respect to our 2003 fiscal
year of $96,164, outplacement services, financial planning, extended medical and
life insurance coverage, which are the same benefits provided to similarly
situated executives.

ADDITIONAL RELATED TRANSACTIONS

In connection with Mr. Harvey's initial employment, he was loaned $250,000
which loan was assumed by us. This loan bears interest at a rate of 8% and
principal and interest are to be forgiven in annual installments through May
2004 so long as Mr. Harvey remains employed by us or one of our subsidiaries as
of each relevant anniversary of his employment date. The amount of loan
forgiveness for 2002 was $54,907.

The law firm of Baker Botts LLP provides legal services to the company. Mr.
Barnett is employed as senior counsel at Baker Botts LLP. Fees paid by Reliant
Resources to Baker Botts LLP did not exceed five percent of such law firm's
gross revenues for its last fiscal year.

The law firm of Skadden, Arps, Slate, Meagher & Flom LLP provides legal
services to the company. The brother of Mr. Naeve is a partner at Skadden, Arps,
Slate, Meagher & Flom LLP. Fees paid by Reliant Resources to Skadden, Arps,
Slate, Meagher & Flom LLP did not exceed five percent of such law firm's gross
revenues for its last fiscal year.

DESCRIPTION OF OTHER INDEBTEDNESS

During March 2003, we refinanced our (a) $1.6 billion senior revolving
credit facilities, (b) $2.9 billion 364-day Orion acquisition term loan, and (c)
$1.425 billion construction agency financing commitment, and we obtained a new
$300 million senior priority revolving credit facility. The syndicated
refinancing combined the existing credit facilities into a $2.1 billion senior
secured revolving credit facility, a $921 million senior secured term loan, and
a $2.91 billion senior secured term loan. The refinanced credit facilities
mature in March 2007. The $300 million senior priority revolving credit facility
matures on the earlier of our possible acquisition of Texas Genco or December
15, 2004 and is secured with a first lien on substantially all of our
contractually and legally available assets. The other facilities totaling $5.93
billion are secured with a second lien on such assets. With the exception of
subsidiaries prohibited by the terms of their financing documents from doing so,
our subsidiaries guarantee both the refinanced credit facilities and the senior
priority revolving credit facility.

In connection with the refinancing, we were required to make a prepayment
of $350 million under the senior revolving credit facility. This prepayment was
made from cash on hand and is available to be reborrowed under the senior
secured revolving credit facility. We must use the proceeds of any loans under
the senior priority revolving credit facility solely to secure or prepay our
ongoing commercial and trading obligations and not for other general corporate
or working capital purposes. We must use the proceeds of any loans under the
senior secured revolving credit facility solely for working capital and other
general corporate purposes. We are not permitted to use the proceeds from loans
under any of these facilities to acquire Texas Genco.

The loans under the refinanced credit facilities bear interest at LIBOR,
plus 4.0% or a base rate plus 3.0% and the loans under the senior priority
revolving credit facility bear interest at LIBOR plus 5.5% or a base rate plus
4.5%. If the refinanced credit facilities are not permanently reduced by $500
million, $1.0 billion and $2.0 billion (cumulatively) by May 2004, 2005 and
2006, respectively, we must pay a fee ranging from 0.50% to 1.0% of the amount
of the refinanced credit facilities still outstanding on each such date. With
the proceeds of our issuance of the senior secured notes on July 1, 2003, we
have satisfied the May 2004 and May 2005 permanent reduction amounts and
therefore, will not be required to pay the above-described fees on either such
date. We must prepay the refinanced facilities with proceeds from certain asset
sales and issuances of securities and with certain cash flows in excess of a
threshold amount. Additionally, we are required to make principal payments or
commitment reductions on the refinanced facilities of $500 million by no later
than May 2006 (such amount to be reduced by certain prepayments). With the
proceeds of our issuance of the senior secured notes on July 1, 2003, we have
made prepayments on the refinanced facilities sufficient to satisfy the May 2006
principal payment requirement. Our March 2003 credit facilities restrict our
ability to take specific actions, subject to numerous exceptions that are
designed to allow for the execution of our business plans in the ordinary
course, including the completion of all four of the power plants currently under
construction, the preservation and optimization of all of our existing
investments in the retail energy and wholesale energy businesses, the ability to
provide credit support for our commercial obligations and the possible
acquisition of a majority interest in Texas Genco, and the financings related
thereto. Such restrictions include our ability to:

- encumber our assets;

- enter into business combinations or divest our assets;

- incur additional debt or engage in sale and leaseback transactions;

- pay dividends or prepay other debt;

- make investments or acquisitions;

- enter into transactions with affiliates;

- make capital expenditures;

- materially change our business;

- amend our debt and other material agreements;

- repurchase our capital stock;

- allow distributions from our subsidiaries to persons other than us or
another subsidiary; and

- engage in certain types of trading activities.

Financial covenants include maintaining a debt to earnings before interest,
taxes, depreciation, amortization and rent (EBITDAR) ratio of a certain maximum
amount and a EBITDAR to interest ratio of a certain minimum amount. We must be
in compliance with each of the covenants before we can borrow or issue letters
of credit under the revolving credit facilities. These covenants, however, are
not anticipated to materially restrict our ability to borrow funds or obtain
letters of credit. Additionally, our failure to comply with these covenants
could result in an event of default that, if not cured or waived, could result
in our being required to repay these borrowings before their scheduled due
dates.

In connection with our March 2003 refinancing, we issued to the lenders
20,373,326 warrants to acquire shares of our common stock. Of the total issued,
7,835,894 warrants vested in March 2003, 6,268,716 will vest if our refinanced
credit facilities have not been reduced by an aggregate of $1.0 billion by May
2005 and the remaining 6,268,716 will vest if our refinanced credit facilities
have not been reduced by an aggregate of $2.0 billion by May 2006. With the
proceeds of our issuance of the senior secured notes on July 1, 2003, we have
satisfied the May 2005 permanent reduction amount and therefore the applicable
6,268,716 warrants described above have been cancelled. The exercise prices of
the warrants are based on average market prices of our common stock during
specified periods in proximity to the refinancing date. The exercise price of
the warrants that vested in March 2003 will be the average daily closing price
for the period of 60 calendar days beginning 90 days after March 31, 2003. The
warrants that vested in March 2003 are exercisable until August 2008, and the
remaining warrants are exercisable for a period of five years from the date they
become vested.

Senior Secured Notes. On July 1, 2003, we issued $550 million 9.25% senior
secured notes due July 15, 2010 and $550 million 9.50% senior secured notes due
July 15, 2013 in a private placement and received proceeds, after deducting the
initial purchasers' discount and estimated out-of-pocket expenses, of $1.1
billion. We used the net proceeds of the issuance to prepay $1.1 billion of
senior secured term loan under our refinanced credit facilities. With certain
limited exceptions, the senior secured notes are secured by the same collateral
which secures our refinanced credit facilities. The collateral is held by a
collateral trustee under a collateral trust agreement for the ratable benefit of
all holders of the credit agreement debt, senior secured note holders and future
senior secured note holders. The senior secured notes are also guaranteed by all
of our subsidiaries that guarantee our refinanced credit facilities, except for
certain subsidiaries of Orion Power and certain other subsidiaries. Interest is
payable semi-annually on January 15 and July 15. The first interest payments
will be made on January 15, 2004. We are not required to make any mandatory
redemption or sinking fund payments with respect to the senior secured notes.
The senior secured notes indentures contain covenants which bind us and our
subsidiaries that include, among others, restrictions on (a) the payment of
dividends, (b) the incurrence of indebtedness and the issuance of preferred
stock, (c) asset sales, (d) liens, (e) transactions with affiliates, and (f)
sale and leaseback transactions. These covenants are not expected to materially
restrict our ability to conduct our business.

Orion Power Senior Notes. Orion Power has outstanding $400 million
aggregate principal amount of 12% senior notes due 2010. The senior notes are
senior unsecured obligations of Orion Power. Orion Power is not required to make
any mandatory redemption or sinking fund payments with respect to the senior
notes. The senior notes are not guaranteed by any of Orion Power's subsidiaries
and are non-recourse to Reliant Resources. In connection with the Orion Power
acquisition, we recorded the senior notes at an estimated fair value of $479
million. The $79 million premium is being amortized against interest expense
over the life of the senior notes. The fair value of the senior notes was based
on our incremental borrowing rates for similar types of borrowing arrangements
as of the acquisition date. The senior notes indenture contains covenants that
include, among others, restrictions on the payment of dividends by Orion Power.

Orion Power's Debt. During October 2002, the Orion Power revolving credit
facility was prepaid and terminated and, as part of the same transaction, we
refinanced the Orion MidWest and Orion NY credit facilities, which refinancing
included an extension of the maturities by three years to October 2005. In
connection with these refinancings, we applied excess cash of $145 million to
prepay and terminate the Orion Power revolving credit facility and to reduce the
term loans and revolving working capital facilities at Orion MidWest and Orion
NY. As of the refinancing date, the amended and restated Orion MidWest credit
facility included a term loan of approximately $974 million and a $75 million
revolving working capital facility. As of the refinancing date, the amended and
restated Orion NY credit facility included a term loan of approximately $353
million and a $30 million revolving working capital facility. The loans under
each facility bear interest at LIBOR plus a margin or at a base rate plus a
margin. The LIBOR margin is 2.50% during the first twelve months, 2.75% during
the next six months, 3.25% for the next six months and 3.75% thereafter. The
base rate margin is 1.50% during the first twelve months, 1.75% for the next six
months, 2.25% for the next six months and 2.75% thereafter. The amended and
restated Orion NY credit facility is secured by a first lien on a substantial
portion of the assets of Orion NY and its subsidiaries (excluding certain
plants). Orion MidWest and its subsidiary are guarantors of the Orion NY
obligations under the amended and restated Orion NY credit agreement.
Substantially all of the assets of Orion MidWest and its subsidiary are pledged,
via a second lien, as collateral for this guarantee. The amended and restated
Orion MidWest credit facility is, in turn, secured by a first lien on
substantially all of the assets of Orion MidWest and its subsidiary. Orion NY
and its subsidiaries are guarantors of the Orion MidWest obligations under the
amended and restated Orion MidWest credit agreement. A substantial portion of
the assets of Orion NY and its subsidiaries (excluding certain plants) are
pledged, via a second lien, as collateral for this guarantee. Both the Orion
MidWest and Orion NY credit facilities contain affirmative and negative
covenants, including negative pledges, that must be met by each borrower under
its respective facility to borrow funds or obtain letters of credit, and which
require Orion MidWest and Orion NY to maintain a combined debt service coverage
ratio of 1.5 to 1.0. These covenants are not anticipated to materially restrict
either borrower's ability to borrow funds or obtain letters of credit under its
respective credit facility. The facilities also provide for any available cash
at one borrower to be made available to the other borrower to meet shortfalls in
the other borrower's ability to make certain payments, including operating
costs. This is effected through distributions of such available cash to Orion
Capital, a direct subsidiary of Orion Power formed in connection with the
refinancing. Orion Capital, as indirect owner of each of Orion MidWest and Orion
NY, can then contribute such cash to the other borrower. Although cash
sufficient to make the November and December 2002 payments on Orion Power's 12%
senior notes and 4.5% convertible senior notes was provided in connection with
the refinancing, the ability of the borrowers to make subsequent dividends to
Orion Power for such interest payments or otherwise is subject to certain
requirements (described below) that may restrict such dividends.

As of December 31, 2002 and March 31, 2003, Orion MidWest had $969 million
and $964 million, respectively, of term loans and $51 million and $40 million,
respectively, of revolving working capital facility loans outstanding. A total
of $14 million and $15 million in letters of credit were also outstanding under
the Orion MidWest credit facility as of December 31, 2002 and March 31, 2003,
respectively. As of December 31, 2002 and March 31, 2003, Orion NY had $351
million and $348 million, respectively, of term loans outstanding. There were no
loans or letters of credit outstanding under the Orion NY working capital
facility as of December 31, 2002. There were no borrowings outstanding and $15
million of letters of credit outstanding under this facility as of March 31,
2003. As of December 31, 2002, restricted cash under the Orion MidWest and the
Orion NY credit facilities was $72 million and $73 million, respectively, and
$27 million at Orion Capital. As of March 31, 2003, restricted cash under the
Orion MidWest and the Orion NY credit facilities was $65 million and $61
million, respectively, and $14 million at Orion Capital. A certain portion of
such restricted cash may be dividended to Orion Power if Orion MidWest and Orion
NY have made certain prepayments and a number of distribution tests have been
met, including satisfaction of certain debt service coverage ratios and the
absence of events of default. These tests may restrict a dividend of such
restricted cash to Orion Power. Any restricted cash which is not dividended will
be applied on a quarterly basis to prepay on a pro rata basis outstanding loans
at Orion MidWest and Orion NY. No distributions may be made under any
circumstances after October 28, 2004. Orion

MidWest's and Orion NY's obligations under the respective facilities are
non-recourse to Reliant Resources.

Liberty Credit Agreement. For a discussion of certain significant risks
relating to Liberty, see "Risk Factors -- Risks Related to our Wholesale Energy
Operations -- The loss of the tolling agreement for our Liberty electric
generating station and/or a potential foreclosure by the Liberty lenders could
have a material adverse impact on our results of operations, financial condition
and cash flows." In July 2000, LEP and Liberty, indirect wholly-owned
subsidiaries of Orion Power, entered into a syndicated facility that provides
for (a) a construction/term loan in an amount of up to $105 million; (b) an
institutional term loan in an amount of up to $165 million; (c) a revolving
working capital facility for an amount of up to $5 million; and (d) a debt
service reserve letter of credit facility of $17 million. The outstanding
borrowings related to the Liberty credit agreement are non-recourse to Reliant
Resources.

In May 2002, the construction loans were converted to term loans. As of the
conversion date, the term loans had an outstanding principal balance of $270
million, with $105 million having maturities through 2012 and the balance having
maturities through 2026. On the conversion date, Orion Power made the required
cash equity contribution of $30 million into Liberty, which was used to repay a
like amount of equity bridge loans advanced by the lenders. A related $41
million letter of credit furnished by Orion Power as credit support was returned
for cancellation. In addition, on the conversion date, a $17 million letter of
credit was issued in satisfaction of Liberty's obligation to provide a debt
service reserve. The facility also provides for a $5 million working capital
line of credit. The debt service reserve letter of credit facility and the
working capital facility expire in May 2007. Liberty is currently not permitted
to borrow under the working capital facility.

As of March 31, 2003, amounts outstanding under the Liberty credit
agreement bear interest at a floating rate, which may be either LIBOR plus 1.25%
or a base rate plus 0.25%, except for the institutional term loan which bears
interest at a fixed rate of 9.02%. For the floating rate term loan, the LIBOR
margin is 1.25% during the first 36 months from the conversion date, 1.375%
during the next 36 months and 1.625% thereafter. The base rate margin is 0.25%
during the first 36 months from the conversion date, 0.375% during the next 36
months and 0.625% thereafter. The LIBOR margin for the revolving working capital
facility is 1.25% during the first 36 months from the conversion date and 1.375%
thereafter. The base rate margin is 0.25% during the first 36 months from the
conversion date and 0.375% thereafter. As of December 31, 2002, Liberty had $103
million and $165 million of the floating rate and fixed rate portions of the
facility outstanding, respectively. As of March 31, 2003, Liberty had $101
million and $165 million of the floating rate and fixed rate portions of the
facility outstanding, respectively. A $17 million letter of credit was also
outstanding under the Liberty credit agreement as of December 31, 2002 and March
31, 2003.

The lenders under the Liberty credit agreement have a security interest in
substantially all of the assets of Liberty. The Liberty credit agreement
contains affirmative and negative covenants, including a negative pledge, that
must be met to borrow funds or obtain letters of credit. Liberty is currently
unable to access the working capital facility. Additionally, the Liberty credit
agreement restricts Liberty's ability to, among other things, make dividend
distributions unless Liberty satisfies various conditions. As of December 31,
2002 and March 31, 2003, restricted cash under the Liberty credit agreement
totaled $27 million and $31 million, respectively. For a discussion of the
existing default under the Liberty credit facility and the lenders' rights to
accelerate the debt and/or foreclose, see "Risk Factors -- Risks Related to our
Wholesale Energy Operations -- The loss of the tolling agreement for our Liberty
electric generating station and/or a potential foreclosure by the Liberty
lenders could have a material adverse impact on our results of operations,
financial condition and cash flows."

We, including Orion Power, are not in default under our other current debt
agreements due to the credit agreement default by Liberty. For a discussion of
certain significant risks relating to Liberty, including the risk that in the
future we could incur a pre-tax loss of an amount up to our recorded net book
value, see "Risk Factors -- Risks Related to our Wholesale Energy
Operations -- The loss of the tolling agreement for our Liberty electric
generating station and/or a potential foreclosure by the Liberty

lenders could have a material adverse impact on our results of operations,
financial condition and cash flows."

PEDFA Bonds for Seward Plant. One of our wholly-owned subsidiaries is in
the process of constructing a 521 MW waste-coal fired, steam electric generation
plant located in Indiana County, Pennsylvania. This facility, the Seward
project, is directly owned by a special purpose entity, which was not
consolidated as of December 31, 2002; however, due to our adoption of FIN No.
46, effective on January 1, 2003, we consolidated this special purpose entity.
In addition, on March 31, 2003, the entity that owns the plant became one of our
indirect wholly-owned subsidiaries. Three series of secured tax-exempt revenue
bonds relating to the Seward project have been issued by PEDFA, for a total of
$300 million outstanding as of January 1, 2003 and March 31, 2003. The bonds
were issued in December 2001 and April 2002. The bonds mature in December 2036.
The bonds bear interest at a floating rate determined each week by the
applicable remarketing agents. As of March 31, 2003, the bonds bore interest of
1.25%. Letters of credit totaling $305 million have been issued under our $2.1
billion senior secured revolver to support the bonds. The bonds are non-recourse
to Reliant Resources.

REMA Letter of Credit Facilities. REMA's lease obligations are currently
supported by three letters of credit issued under three separate unsecured
letter of credit facilities. See note 14(a) to our consolidated financial
statements incorporated by reference herein for a discussion of REMA's lease
obligations. The letter of credit facilities expire in August 2003. The amount
of each letter of credit is equal to an amount representing the greater of (a)
the next six months' scheduled rental payments under the related lease, or (b)
50% of the scheduled rental payments due in the next twelve months under the
related lease. Under the letter of credit facilities, REMA pays a letter of
credit fee based on its assigned credit rating. As of March 31, 2003, the fee
equaled 2.75% of the total amount of the outstanding letters of credit. As of
December 31, 2002 and March 31, 2003, there were $38 million and $50 million,
respectively, in letters of credit outstanding under the facilities. While these
letter of credit facilities are non-recourse to Reliant Resources, REMA's
subsidiaries guarantee REMA's obligations under these facilities. REMA does not
expect to renew or replace the existing letter of credit facilities. REMA
anticipates that the beneficiary will draw on the letters of credit and that the
proceeds of the letter of credit would support REMA's lease obligations. The
drawing would not constitute a default of any of REMA's obligations and would
constitute the making of a loan by the letter of credit issuer to REMA. The
principal amount of the loan is expected to be $42 million and would be payable
in six equal semi-annual installments beginning on the next lease payment date,
January 2, 2004. The loan would accrue interest at the rate of LIBOR plus 3%.

Reliant Energy Channelview L.P. In 1999, Channelview, a special purpose
project subsidiary of REPG, entered into a $475 million syndicated credit
facility to finance the construction and start-up operations of an electric
power generation plant located in Channelview, Texas. The maximum availability
under this facility was (a) $92 million in equity bridge loans for the purpose
of paying or reimbursing project costs, (b) $369 million in loans to finance the
construction of the project and (c) $14 million in revolving loans for general
working capital purposes.

In November 2002, the construction loans were converted to term loans. On
the conversion date, subsidiaries of REPG contributed cash equity and
subordinated debt of $92 million into Channelview, which was used to repay in
full the equity bridge loans advanced by the lenders. As of December 31, 2002,
Channelview had $369 million and $5 million of term loans and revolving working
capital facility loans outstanding, respectively. As of March 31, 2003,
Channelview had $367 million and $10 million of term loans and revolving working
capital facility loans outstanding, respectively. The outstanding borrowings
related to the Channelview credit agreement are non-recourse to Reliant
Resources. The term loans have final maturities ranging from 2017 to 2024. The
revolving working capital facility matures in 2007.

As of March 31, 2003, with the exception of two tranches which total $91
million, the term loans and revolving working capital facility loans bear a
floating rate interest at the borrower's option of either (a) a base rate of
prime plus a margin of 0.25% or (b) LIBOR plus a margin of 1.25%. For $256
million of the term loans and the working capital facility loans, the LIBOR
margin is 1.25% during the first 60 months

from the conversion date, 1.45% during the next 48 months, 1.75% during the
following 48 months and 2.125% thereafter. The base rate margin is 0.25% during
the first 60 months from the conversion date, 0.45% during the next 48 months,
0.75% during the following 48 months and 1.125% thereafter. For $30 million of
the term loans, the LIBOR margin is 1.25% during the first 60 months from the
conversion date, 1.45% during the next 48 months, 1.875% during the following 48
months and 2.25% thereafter. The base rate margin is 0.25% during the first 60
months from the conversion date, 0.45% during the next 48 months, 0.875% during
the following 48 months and 1.25% thereafter. One tranche of $16 million bears a
floating rate interest at the borrower's option of either (a) a base rate plus a
margin of 2.407% or (b) LIBOR plus a margin of 3.407% throughout its term. A
second tranche of $75 million bears interest at a fixed rate of 9.547%
throughout its term.

Obligations under the term loans and revolving working capital facility are
secured by substantially all of the assets of the borrower. The Channelview
credit agreement contains affirmative and negative covenants, including a
negative pledge, that must be met to borrow funds. These covenants are not
anticipated to materially restrict Channelview's ability to borrow funds under
the credit facility. The Channelview credit agreement allows Channelview to pay
dividends or make restricted payments only if specified conditions are
satisfied, including maintaining specified debt service coverage ratios and debt
service reserve account balances. As of December 31, 2002 and March 31, 2003,
restricted cash under the credit agreement totaled $13 million.

DESCRIPTION OF NOTES

RRI issued the notes under an indenture, dated as of June 24, 2003, between
itself and Wilmington Trust Company, as trustee, in a private transaction that
was not subject to the registration requirements of the Securities Act. The
terms of the notes include those stated in the indenture and those made part of
the indenture by reference to the Trust Indenture Act of 1939, as amended.

The following description is a summary of the material provisions of the
indenture and the registration rights agreement. It does not restate those
agreements in their entirety. We urge you to read the indenture and the
registration rights agreement because they, and not this description, define
your rights as holders of the notes. Copies of the indenture and the
registration rights agreement have been filed as exhibits to the registration
statement of which this prospectus is a part.

The registered holder of a note will be treated as the owner of it for all
purposes. Only registered holders will have rights under the indenture. In this
description, when we refer to "RRI," "we," "our" or "us," we are referring to
Reliant Resources, Inc. and not any of its current and future subsidiaries,
unless the context otherwise requires.

BRIEF DESCRIPTION OF THE NOTES

The notes are limited to $275,000,000 in aggregate principal amount. The
notes will mature on August 15, 2010, and will be payable at a price of 100% of
the principal amount of the notes. The notes will bear interest at the interest
rate of 5.00% per year from June 24, 2003. We will pay interest semi-annually on
February 15 and August 15 of each year, commencing on August 15, 2003.

The notes are general unsecured obligations of RRI and are subordinated to
all of our current and future senior debt, and are pari passu in right of
payment with any future senior subordinated indebtedness of RRI. The notes are
also effectively subordinated in right of payment to all indebtedness and other
liabilities, including trade payables, of our subsidiaries. Neither we nor our
subsidiaries are restricted from incurring additional indebtedness or providing
guarantees of indebtedness under the indenture. The indenture does not impose
any financial or similar covenants on us or our subsidiaries. All future
indebtedness of RRI will be treated as senior to these notes unless that future
indebtedness states that it is not senior to these notes.

You may convert the notes into shares of our common stock initially at the
conversion rate of 104.8108 shares of common stock per each $1,000 principal
amount of notes, subject to adjustment in certain circumstances, at any time
before the close of business on the maturity date, unless the notes have been
previously redeemed or repurchased. Holders of notes called for redemption or
submitted for repurchase upon a change in control will be entitled to convert
the notes up to and including the close of business on the business day
immediately preceding the date fixed for redemption or repurchase, as the case
may be. The conversion rate may be adjusted as described below under
"-- Conversion Rights."

We may redeem the notes at our option at any time on or after August 20,
2008 in whole or in part, if the last reported sale price of our common stock is
at least 125% of the then effective conversion price for at least 20 trading
days within a period of 30 consecutive trading days ending on the trading day
before the date of the redemption notice at the redemption prices set forth
below under "-- Optional Redemption by RRI," plus accrued and unpaid interest
to, but excluding, the redemption date. We will therefore be required to make at
least ten interest payments on the notes before being able to redeem the notes.
If we experience a change in control, you will have the right to require us to
repurchase your notes as described below under "-- Repurchase at Option of
Holders Upon a Change in Control."

FORM, DENOMINATION, TRANSFER, EXCHANGE AND BOOK-ENTRY PROCEDURES

The notes were issued:

- only in fully registered form;

- without interest coupons; and

- in denominations of $1,000 and multiples of $1,000.

The notes are evidenced by one or more global notes, which was deposited
with the trustee as custodian for DTC and registered in the name of Cede & Co.,
as nominee of DTC. The global note issued during the offering of the notes and
any notes issued in exchange for the global note are subject to restrictions on
transfer and bear a legend regarding such restrictions. The notes that are
resold under this prospectus will be represented by a new unrestricted global
note. Upon issuance of this global note, DTC will credit the accounts of persons
holding through it with the respective principal amounts of the notes
represented by the new unrestricted global note. Except as set forth below,
record ownership of the global note may be transferred, in whole or in part,
only to another nominee of DTC or to a successor of DTC or its nominee.

The global note will not be registered in the name of any person, or
exchanged for notes that are registered in the name of any person, other than
DTC or its nominee unless one of the following occurs:

- DTC notifies us that it is unwilling, unable or no longer qualified to
continue acting as the depositary for the global note; or

- an event of default with respect to the notes represented by the global
note has occurred and is continuing; or

- we decide to discontinue use of the system of book-entry transfer through
DTC or any successor depositary.

In those circumstances, DTC will determine in whose names any securities
issued in exchange for the global note will be registered.

DTC or its nominee is considered the sole owner and holder of the global
note for all purposes, and as a result:

- you cannot have notes registered in your name if they are represented by
the global note;

- except as described above, you cannot receive physical certificated notes
in exchange for your beneficial interest in the global note;

- you will not be considered to be the owner or holder of the global note
or any note it represents for any purpose; and

- all payments on the global note will be made to DTC or its nominee.

The laws of some jurisdictions require that certain kinds of purchasers,
such as insurance companies, can only own securities in definitive certificated
form. These laws may limit your ability to transfer your beneficial interests in
the global note to these types of purchasers.

Only institutions, such as a securities broker or dealer, that have
accounts with DTC or its nominee (called participants) and persons that may hold
beneficial interests through participants can own a beneficial interest in the
global note. The only place where the ownership of beneficial interests in the
global note will appear and the only way the transfer of those interests can be
made will be on the records kept by DTC (for each participants' interests) and
the records kept by those participants (for interests of persons held by
participants on their behalf).

Secondary trading in bonds and notes of corporate issuers is generally
settled in clearinghouse (that is, next-day) funds. In contrast, beneficial
interests in global notes usually trade in DTC's same-day funds

settlement system, and settle in immediately available funds. We make no
representations as to the effect that settlement in immediately available funds
will have on trading activity in those beneficial interests.

We will make cash payments of interest, principal, redemption price or
repurchase price of the global note, as well as any payment of special interest,
to the trustee for payment on to Cede & Co., the nominee for DTC, as the
registered owner of the global note. We will make these payments by wire
transfer of immediately available funds on each payment date.

We have been informed that DTC's practice is to credit participants'
accounts on the payment date with payments in amounts proportionate to their
respective beneficial interests in the notes represented by the global note as
shown on DTC's records, unless DTC has reason to believe that it will not
receive payment on that payment date. Payments by participants to owners of
beneficial interests in notes represented by the global note held through
participants will be the responsibility of those participants, as is now the
case with securities held for the accounts of customers registered in street
name.

We will send any redemption or repurchase notices to Cede. We understand
that if less than all the notes are being redeemed, DTC's practice is to
determine by lot the amount of the holdings of each participant to be redeemed.

We also understand that neither DTC nor Cede will consent or vote with
respect to the notes. We have been advised that under its usual procedures, DTC
will mail an omnibus proxy to us as soon as possible after the record date. The
omnibus proxy assigns Cede's consenting or voting rights to those participants
to whose accounts the notes are credited on the record date identified in a
listing attached to the omnibus proxy.

Because DTC can only act on behalf of participants, who in turn act on
behalf of indirect participants, the ability of a person having a beneficial
interest in the principal amount represented by the global note to pledge such
interest to persons or entities that do not participate in the DTC book-entry
system, or otherwise take actions in respect of that interest, may be affected
by the lack of a physical certificate evidencing its interest.

DTC has advised us that it will take any action permitted to be taken by a
holder of notes (including the presentation of notes for exchange) only at the
direction of one or more participants to whose account with DTC interests in the
global note are credited, and only in respect of such portion of the principal
amount of the notes represented by the global note as to which such participant
or participants has or have given such direction.

DTC has also advised us as follows:

- DTC is a limited purpose trust company organized under the laws of the
State of New York, a member of the Federal Reserve System, a clearing
corporation within the meaning of the Uniform Commercial Code, as
amended, and a clearing agency registered pursuant to the provisions of
Section 17A of the Exchange Act;

- DTC was created to hold securities for its participants and facilitate
the clearance and settlement of securities transactions between
participants through electronic book-entry changes in accounts of its
participants;

- Participants include securities brokers and dealers, banks, trust
companies and clearing corporations and may include certain other
organizations;

- Certain participants, or their representatives, together with other
entities, own DTC; and

- Indirect access to the DTC system is available to other entities such as
banks, brokers, dealers and trust companies that clear through or
maintain a custodial relationship with a participant, either directly or
indirectly.

The policies and procedures of DTC, which may change periodically, will
apply to payments, transfers, exchanges and other matters relating to beneficial
interests in the global note. We and the trustee

have no responsibility or liability for any aspect of DTC's or any participants'
records relating to beneficial interests in the global note, including for
payments made on the global note. Further, we and the trustee are not
responsible for maintaining, supervising or reviewing any of those records.

CONVERSION RIGHTS

You have the option to convert any portion of the principal amount of any
note that is an integral multiple of $1,000 into shares of our common stock at
any time on or prior to the close of business on the maturity date, unless the
notes have been previously redeemed or repurchased. The initial conversion rate
is equal to 104.8108 shares per $1,000 in principal amount of notes, as shown on
the cover page of this prospectus. The conversion rate is equivalent to a
conversion price of approximately $9.54 per share. The conversion rate is
subject to adjustment as described below. Your right to convert a note called
for redemption or delivered for repurchase will terminate at the close of
business on the business day immediately preceding the redemption date or
repurchase date for that note, unless we default in making the payment due upon
redemption or repurchase.

You may convert all or part of any note by delivering the note at the
office or agency of the trustee in the Borough of Manhattan, The City of New
York, accompanied by a duly signed and completed conversion notice, a copy of
which may be obtained from the trustee. The conversion date will be the date on
which the note and the duly signed and completed conversion notice are so
delivered. Beneficial owners of an interest in a global security may exercise
their right of conversion pursuant to DTC's conversion program. This notice of
conversion can be obtained at the office of the conversion agent. The conversion
date will be the date on which the note and the duly signed and completed notice
of conversion are delivered.

As promptly as practicable on or after the conversion date, we will issue
and deliver to the trustee a certificate or certificates for the number of full
shares of our common stock issuable upon conversion, together with a cash
payment in lieu of any fraction of a share. The certificate or certificates will
then be sent by the trustee to the conversion agent for delivery to the holders.
The shares of our common stock issuable upon conversion of the notes will be
fully paid and nonassessable and will be of the same class as the shares of our
common stock that are currently outstanding.

If you surrender a note for conversion on a date that is not an interest
payment date, you will not be entitled to receive any interest for the period
from the immediately preceding interest payment date to the conversion date,
except as described below in this paragraph. However, if you are a holder of a
note on a regular record date, including a note surrendered for conversion after
the regular record date, you will receive the interest payable on such note on
the next succeeding interest payment date. Accordingly, to correct for the
resulting overpayment of interest, any note surrendered for conversion during
the period from the close of business on a regular record date to the opening of
business on the next succeeding interest payment date must be accompanied by
payment of an amount equal to the interest payable on such interest payment date
on the principal amount of notes being surrendered for conversion. However, you
will not be required to make that payment if you are converting a note, or a
portion of a note, that we have called for redemption, or that you are entitled
to require us to repurchase from you upon a change in control, if your
conversion right would terminate because of the redemption or repurchase between
the regular record date and the close of business on the next succeeding
interest payment date.

No other payment or adjustment for interest, or for any dividends in
respect of our common stock, will be made upon conversion. Holders of our common
stock issued upon conversion will not be entitled to receive any dividends
payable to holders of our common stock as of any record time or date before the
close of business on the conversion date. We will not issue fractional shares
upon conversion. Instead, we will pay cash for such fractional shares based on
the market price of our common stock at the close of business on the conversion
date.

You will not be required to pay any taxes or duties relating to the issue
or delivery of our common stock on conversion but you will be required to pay
any tax or duty relating to any transfer involved in the issue or delivery of
our common stock in a name other than that of the holder of the note.
Certificates
91

representing shares of common stock will not be issued or delivered unless all
taxes and duties, if any, payable by you have been paid.

The conversion rate is subject to adjustment for, among other things:

- dividends and other distributions payable in our common stock on shares
of our common stock;

- the issuance to all holders of our common stock of rights, options or
warrants entitling them to subscribe for or purchase our common stock at
less than the then current market price of such common stock as of the
record date for shareholders entitled to receive such rights, options or
warrants, provided that the conversion rate will be readjusted to the
extent any of these rights, options or warrants are not exercised prior
to their expiration;

- subdivisions, combinations and reclassifications of our common stock;

- distributions to all holders of our common stock of evidences of our
indebtedness, shares of capital stock, cash or assets, including
securities, but excluding:

- those dividends, distributions, rights, options and warrants referred to
above;

- dividends or distributions paid exclusively in cash; and

- distributions upon mergers or consolidations referred to below;

- distributions consisting exclusively of cash (excluding any cash
distributed upon a merger or consolidation referred to below) to all
holders of common stock in an aggregate amount that, combined together
with:

- other such all-cash distributions made within the preceding 12 months in
respect of which no adjustment has been made; and

- any cash and the fair market value of other consideration payable in
respect of any tender offer by us or any of our subsidiaries for our
common stock concluded within the preceding 12 months in respect of
which no adjustment has been made,

exceeds 1.0% of our market capitalization (for this purpose being the
product of the current market price per share of common stock on the
record date for such distribution multiplied by the number of shares of
common stock outstanding) on such date; and

- the successful completion of a tender offer made by us or any of our
subsidiaries for our common stock which involves an aggregate
consideration that, together with:

- any cash and the fair market value of other consideration payable in a
tender offer by us or any of our subsidiaries for common stock expiring
within the 12 months preceding the expiration of such tender offer in
respect of which no adjustment has been made; and

- the aggregate amount of any such all-cash distributions referred to
above to all holders of our common stock within the 12 months preceding
the expiration of such tender offer in respect of which no adjustments
have been made,

exceeds 1.0% of our market capitalization (for this purpose being the
product of the current market price per share of common stock as of the
last time tenders could have been made pursuant to such tender offer
multiplied by the number of shares of common stock outstanding) on the
expiration of such tender offer.

We will not make any adjustment for any transaction if the holders of the
notes actually participate in such transaction on an equal and ratable basis.

To the extent that we have a rights plan in effect upon conversion of the
notes into common stock, the holder will receive, in addition to the common
stock, the rights under the rights plan whether or not the rights have separated
from the common stock at the time of conversion, subject to limited exceptions,
and no adjustments to the conversion rate will be made, except in limited
circumstances.
92

We reserve the right to effect such increases in the conversion rate in
addition to those required by the foregoing provisions as we consider to be
advisable in order to avoid or diminish any income tax to the holder of common
stock resulting from stock distribution. We will not be required to make any
adjustment to the conversion rate until the cumulative adjustments amount to
1.0% or more of the conversion rate (except in the case of a cash dividend). We
will compute all adjustments to the conversion rate and will give notice by mail
to holders of the registered notes of any such adjustments.

If we merge or consolidate with another person or sell or transfer all or
substantially all of our assets, each note then outstanding will, without the
consent of the holder of any note, become convertible only into the kind and
amount of securities, cash and other property receivable upon such
consolidation, merger, sale or transfer by a holder of the number of shares of
common stock into which the note was convertible immediately prior to the
merger, consolidation or sale. This calculation will be made based on the
assumption that the holder of common stock failed to exercise any rights of
election that the holder may have to select a particular type of consideration.
The adjustment will not be made for a merger that does not result in any
reclassification, conversion, exchange or cancellation of our common stock.

We may temporarily increase the conversion rate for any period of at least
20 days if our board of directors determines that the increase would be in our
best interest. The board of directors' determination in this regard will be
conclusive. We will give holders of notes at least 15 days' notice of such an
increase in the conversion rate. Any such increase, however, will not be taken
into account for purposes of determining whether the closing price of our common
stock exceeds the conversion price by 110% in connection with an event that
otherwise would be a change in control as defined below.

MERGERS AND SALES OF ASSETS BY RRI

We may not, directly or indirectly, consolidate with or merge into any
other person or convey, transfer, sell or lease our properties and assets
substantially as an entirety to any person, other than to one or more of our
subsidiaries, unless:

- the person formed by such consolidation or into or with which we are
merged or the person to which our properties and assets are so conveyed,
transferred, sold or leased, shall be a corporation organized and
existing under the laws of the United States, any State within the United
States or the District of Columbia and, if we are not the surviving
person, the surviving person assumes the payment of the principal of,
premium, if any, and interest on the notes (including special interest,
if any) and the performance of our other covenants under the indenture
pursuant to an agreement reasonably satisfactory to the trustee; provided
that if the person formed by or surviving any such consolidation or
merger with us is not a corporation, a corporate co-issuer shall also be
an obligor with respect to the convertible notes, and

- immediately after giving effect to the transaction, no event of default,
and no event that, after notice or lapse of time or both, would become an
event of default, shall have occurred and be continuing.

In addition, we may not, directly or indirectly, lease all or substantially
all of our properties or assets, in one or more related transactions to any
person, other than to one or more of our subsidiaries.

SUBORDINATION

The indebtedness evidenced by the notes is subordinated to the extent
provided in the indenture to the prior payment in full of all our senior debt
(as defined below). In the event of our insolvency, bankruptcy, receivership,
liquidation, reorganization, debt restructuring or similar proceeding or
liquidation, dissolution or winding up or any assignment for the benefit of
creditors or marshalling of assets and liabilities, payments on the notes will
be subordinated in right of payment to the prior payment in full in cash of all
senior debt. As a result of these subordination provisions, in the event of our
liquidation, insolvency or any similar event described above, holders of senior
debt may receive more, ratably, and holders of the notes may receive less,
ratably, than our other creditors. In the event of any acceleration of

the notes because of an event of default, holders of any senior debt would be
entitled to payment in full in cash of all senior debt before the holders of
notes are entitled to receive any payment or distribution. We are required to
promptly notify holders of senior debt if payment of the notes is accelerated
because of an event of default.

We may also not make payment of principal, interest or other amounts on the
notes or redeem or repurchase the notes if any of the following occurs:

- a default in the payment of the principal, interest or other amounts on
designated senior debt (as defined below) occurs;

- any other default on designated senior debt occurs and the maturity of
such designated senior debt is accelerated; or

- any other default (other than the ones specified above) occurs and is
continuing with respect to designated senior debt that permits holders or
their representatives of designated senior debt to accelerate its
maturity, and the trustee receives a payment blockage notice from us or
some other person permitted to give the payment blockage notice under the
indenture.

The foregoing prohibitions regarding payments on the notes shall end:

- in case of a prohibition based on a payment default or a nonpayment
default where the maturity of such designated senior debt is accelerated,
when all amounts in respect of such designated senior debt have been paid
in full in cash or the default is cured, waived or ceases to exist and
any acceleration has been rescinded; and

- in case of a prohibition based on a nonpayment default (other than the
ones specified above), 179 days after the receipt of the payment blockage
notice, unless (1) earlier terminated by the written notice of the person
who gave the payment blockage notice, (2) all amounts on the designated
senior debt have been paid in full in cash or (3) the default giving rise
to the payment blockage notice is cured, waived or ceases to exist,
unless the designated senior debt has been accelerated.

No new payment blockage period based on a nonpayment default may start
unless 360 days have elapsed since the effectiveness of the prior payment
blockage notice. No nonpayment default that existed or was continuing on the
date of delivery of any payment blockage notice to the trustee may be the basis
for a subsequent payment blockage notice, unless such default has been cured or
waived for a period of at least 90 days. The subordination provisions will not
prevent the occurrence of any event of default under the indenture. If the
trustee or any holder receives any payment that should not have been made to it
in contravention of subordination provisions before all senior debt is paid in
full in cash, then such payment will be held in trust for the holders of senior
debt.

"designated senior debt" means any and all indebtedness outstanding under
our credit agreement and our obligations under any particular senior debt having
an aggregate principal amount in excess of $50,000,000 in which the instrument
creating or evidencing the same or the assumption or guarantee thereof, or
related agreements to which we are a party, expressly provides that such senior
debt shall be "designated senior debt" for purposes of the indenture. The
instrument, agreement or other document evidencing such designated senior debt
may place limitations and conditions on the right of such senior debt to
exercise the rights of designated senior debt.

"senior debt" means, as to any person:

- all indebtedness for money borrowed, for reimbursement of drawings under
letters of credit and all hedging obligations unless the instrument under
which such indebtedness is incurred expressly provides that it is on a
parity with or subordinated in right of payment to the notes;

- any and all indebtedness and obligations outstanding under our credit
agreement; and

- any deferrals, renewals, refinancings, replacements or extensions of any
of the above.

Notwithstanding anything to the contrary in the preceding, senior debt will
not include:

- any liability for federal, state, local or other taxes owed or owing by
RRI;

- any intercompany Indebtedness of RRI to any of its affiliates; or

- any trade payables.

The notes are structurally subordinated to all indebtedness and other
liabilities, including trade payables, of our subsidiaries. Our right to receive
any assets of our subsidiaries upon their liquidation or reorganization, and
your consequent right to participate in those assets, will be effectively
subordinated to the claims of the subsidiary's creditors, including trade
creditors, except to the extent that we are recognized as a creditor of such
subsidiary. Even in the event that we are recognized as a creditor of one our
subsidiaries, our claims would still be subordinate to any security interest in
the assets of the subsidiary and any indebtedness of such subsidiary senior to
that held by us.

As of March 31, 2003, we had approximately $5.1 billion of indebtedness and
other liabilities that would have constituted senior debt.

Neither we nor our subsidiaries are limited or prohibited from incurring
senior debt or any other indebtedness or liabilities under the indenture. We
expect from time to time to incur additional indebtedness and other liabilities,
including senior debt. We also expect that our subsidiaries may from time to
time incur additional indebtedness and other liabilities.

OPTIONAL REDEMPTION BY RRI

On or after August 20, 2008, we may redeem the notes, in whole or in part,
if the last reported sale price of our common stock is at least 125% of the then
effective conversion price for at least 20 trading days within a period of 30
consecutive trading days ending on the trading day before the date of the
redemption notice at the redemption prices set forth below. If we elect to
redeem all or part of the notes, we will give at least 30, but no more than 60,
days' prior notice to you.

The redemption price, expressed as a percentage of principal amount, is as
follows for the following periods:

REDEMPTION
PERIOD PRICE
------ ----------

Beginning on August 20, 2008 and ending on August 14,
2009...................................................... 101.429%
Beginning on August 15, 2009 and ending on August 14,
2010...................................................... 100.714%

and thereafter at 100% of the principal amount. In each case, we will pay
accrued and unpaid interest (including special interest) to, but excluding, the
redemption date.

If we do not redeem all of the notes, the trustee will select the notes to
be redeemed in principal amounts of $1,000 or whole multiples of $1,000 by lot
or on a pro rata basis. If any notes are to be redeemed in part only, we will
issue a new note or notes in principal amount equal to the unredeemed principal
portion thereof. If a portion of your notes is selected for partial redemption
and you convert a portion of your notes, the converted portion will be deemed to
be taken from the portion selected for redemption.

No sinking fund is provided for the notes, which means that the indenture
does not require us to redeem or retire the notes periodically.

PAYMENT AND CONVERSION

We will make all payments of principal and interest (including special
interest) on the notes by dollar check. If you hold registered notes with a face
value greater than $2,000,000, at your request we will make payments of
principal or interest to you by wire transfer to an account maintained by you at
a bank in The City of New York. Payment of any interest on the notes will be
made to the person in whose name the

note, or any predecessor note, is registered at the close of business on
February 1 or August 1, whether or not a business day, immediately preceding the
relevant interest payment date (a "regular record date"). If you hold registered
notes with a face value in excess of $2,000,000 and you would like to receive
payments by wire transfer, you will be required to provide the trustee with wire
transfer instructions at least 15 days prior to the relevant payment date.

Payments on any global note registered in the name of DTC or its nominee
will be payable by the trustee to DTC or its nominee in its capacity as the
registered holder under the indenture. Under the terms of the indenture, we and
the trustee will treat the persons in whose names the notes, including any
global note, are registered as the owners for the purpose of receiving payments
and for all other purposes. Consequently, neither we, the trustee nor any of our
agents or the trustee's agents has or will have any responsibility or liability
for:

- any aspect of DTC's records or any participant's or indirect
participant's records relating to or payments made on account of
beneficial ownership interests in the global note, or for maintaining,
supervising or reviewing any of DTC's records or any participant's or
indirect participant's records relating to the beneficial ownership
interests in the global note; or

- any other matter relating to the actions and practices of DTC or any of
its participants or indirect participants.

We will not be required to make any payment on the notes due on any day
which is not a business day until the next succeeding business day. The payment
made on the next succeeding business day will be treated as though it were paid
on the original due date and no interest will accrue on the payment for the
additional period of time.

Notes may be surrendered for conversion at the office or agency of the
trustee in the Borough of Manhattan, New York. Notes surrendered for conversion
must be accompanied by appropriate notices and any payments in respect of
interest or taxes, as applicable, as described above under "-- Conversion
Rights."

We have initially appointed the trustee as registrar, paying agent and
conversion agent. We may terminate the appointment of the registrar or any
paying agent or conversion agent and appoint an additional registrar or
additional or other paying agents and conversion agents. However, until the
notes have been delivered to the trustee for cancellation, or moneys sufficient
to pay the principal of, premium, if any, and interest on the notes have been
made available for payment and either paid or returned to us as provided in the
indenture, the trustee will maintain an office or agency in the Borough of
Manhattan, New York for surrender of notes for conversion. Notice of any
termination or appointment and of any change in the office through which the
registrar or any paying agent or conversion agent will act will be given in
accordance with "-- Notices" below.

All moneys deposited with the trustee or any paying agent, or then held by
us, in trust for the payment of principal of, premium, if any, or interest
(including special interest) on any notes which remain unclaimed at the end of
two years after the payment has become due and payable will be repaid to us, and
you will then look only to us for payment.

REPURCHASE AT OPTION OF HOLDERS UPON A CHANGE IN CONTROL

If a change in control (as defined below) occurs, you will have the right,
at your option, to require us to repurchase all of your notes not previously
called for redemption, or any portion of the principal amount thereof, that is
$1,000 or an integral multiple of $1,000. We will repurchase the notes upon a
change in control at a price equal to 100% of the principal amount of the notes
to be repurchased, together with accrued and unpaid interest to, but excluding,
the repurchase date.

At our option, instead of paying the repurchase price in cash, we may pay
the repurchase price, in whole or in part, in our common stock (or in the case
of a merger, consolidation or similar transaction in which we are not the
surviving corporation, common stock, common equity interests, ordinary shares or

American Depository Shares of the surviving corporation or its direct or
indirect parent corporation) valued at 95% of the average of the closing prices
of our common stock for the five trading days immediately preceding the second
trading day prior to the repurchase date. We may only pay the repurchase price
in our common stock or applicable securities if we satisfy conditions provided
in the indenture.

Within 30 days after the occurrence of a change in control, we are
obligated to give to you notice of the occurrence of the change in control, of
the type of consideration to be paid and of the repurchase right arising as a
result of the change in control. We must also deliver a copy of this notice to
the trustee. To exercise the repurchase right, you must deliver on or before the
second business day immediately preceding the 20th day after the date of our
notice a written notice to the trustee of your exercise of your repurchase
right, together with the notes with respect to which the right is being
exercised. You may withdraw this notice by delivering to the trustee a notice of
withdrawal prior to the close of business on the second business day immediately
preceding the repurchase date. We are required to repurchase the notes
surrendered for repurchase on a repurchase date that is 20 days after our
notice.

Because the value of any shares of our common stock that we may use to
satisfy our repurchase obligation will be determined prior to the repurchase
date, holders of the notes bear the market risk that our common stock will
decline in value between the date the repurchase price is calculated and the
repurchase date.

A change in control means the occurrence of any of the following:

(1) the direct or indirect sale, transfer, conveyance or other
disposition (other than by way of merger or consolidation), in one or a
series of related transactions, of all or substantially all of the
properties or assets of RRI and its subsidiaries taken as a whole to any
"person" (as that term is used in Section 13(d) of the Exchange Act, but
excluding any employee benefit plan of RRI or any of its subsidiaries, and
any person or entity acting in its capacity as trustee, agent or other
fiduciary or administrator of any such plan);

(2) the adoption of a plan relating to the liquidation or dissolution
of RRI other than (i) the consolidation with, merger into or transfer of
all or part of the properties and assets of any of our subsidiaries to us
or any of our other subsidiaries and (ii) the merger of us with an
affiliate solely for the purpose of our re-incorporating or our re-forming
in another jurisdiction;

(3) the consummation of any transaction (including, without
limitation, any merger or consolidation) the result of which is that any
"person" (as defined above) becomes the beneficial owner, directly or
indirectly, of more than 50% of the voting stock of RRI, measured by voting
power rather than number of shares;

(4) the first day on which a majority of the members of the board of
directors of RRI are not continuing directors;

(5) RRI consolidates with, or merges with or into, any person, or any
person consolidates with, or merges with or into, RRI, in any such event
pursuant to a transaction in which any of the outstanding voting stock of
RRI or such other person is converted into or exchanged for cash,
securities or other property, other than any such transaction where the
voting stock of RRI outstanding immediately prior to such transaction is
converted into or exchanged for voting stock (other than disqualified
stock) of the surviving or transferee person constituting a majority of the
outstanding shares of such voting stock of such surviving or transferee
person (immediately after giving effect to such issuance); or

(6) a termination of listing, which means that the common stock is
neither listed for trading on a United States national securities exchange
nor quoted on the Nasdaq National Market.

However, a change in control shall not be deemed to have occurred if
either:

- the closing price per share of our common stock for any five trading days
within the period of 10 consecutive trading days ending immediately after
the later of the change in control or the public announcement of the
change in control (in the case of a change in control under clause (3)
above) or the period of 10 consecutive trading days ending immediately
before the change in control (in the case of a change in control under
clause (5) above) shall equal or exceed 110% of the conversion price of
the notes in effect on each such trading day; or

- all of the consideration, excluding cash payments for fractional shares
and cash payments made pursuant to dissenters' appraisal rights, in a
merger or consolidation otherwise constituting a change in control
described in clause (3) and/or clause (5) above consists of shares of
common stock, depositary receipts or other certificates representing
common equity interests traded on a national securities exchange or
quoted on the Nasdaq National Market, or will be so traded or quoted
immediately following such change in control, and as a result of such
transaction or transactions the notes become convertible solely into such
common stock, depositary receipts or other certificates representing
common equity interests.

For purposes of these provisions:

- whether a person is a "beneficial owner" shall be determined in
accordance with Rule 13d-3 promulgated by the Securities and Exchange
Commission under the Exchange Act;

- "voting stock" of any person as of any date means the capital stock of
such person that is at the time entitled to vote in the election of the
board of directors of such person;

- "capital stock" means: (1) in the case of a corporation, corporate stock;
(2) in the case of an association or business entity, any and all shares,
interests, participations, rights or other equivalents (however
designated) of corporate stock; (3) in the case of a partnership or
limited liability company, partnership interests (whether general or
limited) or membership interests; and (4) any other interest or
participation that confers on a person the right to receive a share of
the profits and losses of, or distributions of assets of, the issuing
person, but excluding from all of the foregoing any debt securities
convertible into capital stock, whether or not such debt securities
include any right of participation with capital stock;

- "disqualified stock" means any capital stock that, by its terms (or by
the terms of any security into which it is convertible, or for which it
is exchangeable, in each case, at the option of the holder of the capital
stock), or upon the happening of any event, matures or is mandatorily
redeemable, pursuant to a sinking fund obligation or otherwise, or
redeemable at the option of the holder of the capital stock, in whole or
in part, on or prior to the date that is 91 days after the date on which
the notes mature. Notwithstanding the preceding sentence, any capital
stock that would constitute disqualified stock solely because the holders
of the capital stock have the right to require RRI to repurchase such
capital stock upon the occurrence of a change of control or an asset sale
will not constitute disqualified stock. The amount of disqualified stock
deemed to be outstanding at any time for purposes of the indenture shall
be equal to the maximum amount that RRI and its subsidiaries may become
obligated to pay upon the maturity of, or pursuant to any mandatory
redemption provisions of, such disqualified stock, exclusive of accrued
dividends.

- "board of directors" means: (1) with respect to a corporation, the board
of directors of the corporation or any committee thereof duly authorized
to act on behalf of such board; (2) with respect to a partnership, the
board of directors of the general partner of the partnership; (3) with
respect to a limited liability company, the managing member or members or
any controlling committee of managing members or board of directors
thereof; and (4) with respect to any other person, the board or committee
of such person serving a similar function;

- "continuing director" means, as of any date of determination, any member
of the board of directors of RRI who: (1) was a member of such board of
directors on the date of the indenture; or (2) was

nominated for election or elected to such board of directors with the
approval of a majority of the continuing directors who were members of
such board at the time of such nomination or election;

- the "conversion price" is equal to $1,000 divided by the conversion rate;
and

- "person" includes any syndicate or group which would be deemed to be a
"person" under Section 13(d)(3) of the Exchange Act.

The rules and regulations under the Exchange Act require the dissemination
of prescribed information to security holders in the event of an issuer tender
offer. These rules may apply in the event that the repurchase option becomes
available to you. We will comply with these rules to the extent applicable at
that time.

We may, to the extent permitted by applicable law, at any time purchase
notes in the open market or by tender at any price or by private agreement. Any
note so purchased by us may, to the extent permitted by applicable law and,
subject to certain conditions, be reissued or resold or may, at our option, be
surrendered to the trustee for cancellation. Any notes surrendered for
cancellation may not be reissued or resold and will be canceled promptly.

Our ability to repurchase notes upon the occurrence of a change in control
is subject to limitations. We may not have sufficient financial resources or the
ability to arrange financing to pay the repurchase price in cash for all the
notes delivered by holders seeking to exercise their repurchase right. Although
our ability to repurchase the notes in cash may be limited or prohibited by the
terms of any future borrowing arrangements existing at the time of a change in
control, we may elect, subject to satisfaction of certain conditions, to pay the
repurchase price for the notes in common stock or applicable securities. Any
failure by us to repurchase the notes upon a change in control would result in
an event of default under the indenture, whether or not the repurchase is
permitted by the subordination provisions of the indenture. Any such default
may, in turn, cause a default under our senior debt. Moreover, the occurrence of
a change in control could result in an event of default under the terms of our
then existing indebtedness. As a result, any repurchase of the notes may be
prohibited until the senior debt is paid in full.

The change in control repurchase provision of the notes may, in certain
circumstances, make more difficult or discourage a takeover of our company. The
change in control repurchase feature, however, is not the result of our
knowledge or any specific effort to accumulate shares of our common stock, to
obtain control of us by means of a merger, tender offer solicitation or
otherwise by management to adopt a series of anti-takeover provisions. Instead,
the change in control purchase feature is a standard term contained in
convertible securities similar to the notes.

The definition of change in control includes a phrase relating to the
transfer or sale of all or substantially all of our assets. There is no precise,
established definition of the phrase "substantially all" under applicable law.
Accordingly, your ability to require us to repurchase your notes as a result of
a transfer or sale of less than all of our assets may be uncertain.

The foregoing provisions would not necessarily afford you protection in the
event of highly leveraged or other transactions involving us that may adversely
affect you.

EVENTS OF DEFAULT

The following are events of default under the indenture:

- we fail to pay principal of or premium, if any, on any note when due,
whether or not prohibited by the subordination provisions of the
indenture;

- we fail to pay any interest, including any special interest, on any note
when due, which failure continues for 30 days, whether or not prohibited
by the subordination provisions of the indenture;

- we fail to comply with the notice and repurchase provisions described
under "-- Repurchase at Option of Holders Upon a Change of Control,"
whether or not the notice or repurchase is

prohibited by the subordination provisions of the indenture, which
failure continues for 30 days following notice as provided in the
indenture;

- we fail to perform any agreement or other covenant in the notes or the
indenture, which failure continues for 90 days following notice as
provided in the indenture;

- we fail to pay any indebtedness under any bond, debenture, note or other
evidence of indebtedness for money borrowed by us or any of our
subsidiaries, other than (1) Reliant Energy Retail Holdings, LLC or any
subsidiary thereof in connection with a securitization transaction in
which the indebtedness incurred by such entities is non-recourse to
Reliant Resources and its other subsidiaries (2) Reliant Energy Capital
(Europe) Inc. and its subsidiaries, (3) Reliant Energy Channelview, L.P.
and its subsidiaries so long as, taken together, they would not
constitute a significant subsidiary and (4) Liberty Electric PA, LLC,
Liberty Electric Power, LLC and their respective subsidiaries so long as,
taken together, they would not constitute a significant subsidiary (or
the payment of which is guaranteed by us), in a principal aggregate
amount then outstanding in excess of $100,000,000 at final maturity
(either at its stated maturity or upon acceleration thereof), and such
indebtedness is not discharged, or such acceleration is not rescinded or
annulled, within the grace period provided in such bond, debenture, note,
or other evidence of indebtedness;

- failure by us or any of our subsidiaries, other than (1) Reliant Energy
Retail Holdings, LLC or any subsidiary thereof that has engaged in a
securitization transaction (2) Reliant Energy Capital (Europe) Inc. and
its subsidiaries, (3) Reliant Energy Channelview, L.P. and its
subsidiaries so long as, taken together, they would not constitute a
significant subsidiary and (4) Liberty Electric PA, LLC, Liberty Electric
Power, LLC and their respective subsidiaries so long as, taken together,
they would not constitute a significant subsidiary, to pay final and
non-appealable judgments aggregating in excess of $100,000,000, which are
not covered by indemnities or third-party insurance, which judgments are
not paid, discharged, vacated or stayed for a period of 60 days; and

- certain events of bankruptcy, insolvency or reorganization involving us
or any of our significant subsidiaries (other than Reliant Energy Capital
(Europe) Inc. and its subsidiaries).

Subject to the provisions of the indenture relating to the duties of the
trustee in case an event of default shall occur and be continuing, the trustee
will be under no obligation to exercise any of its rights or powers under the
indenture at the request or direction of any holder, unless the holder shall
have offered and provided indemnity satisfactory to the trustee. Subject to
providing indemnification of the trustee, the holders of a majority in aggregate
principal amount of the outstanding notes will have the right to direct the
time, method and place of conducting any proceeding for any remedy available to
the trustee or exercising any trust or power conferred on the trustee. The
trustee may withhold from holders of the notes notice of any continuing event of
default if it determines that withholding notice is in their interest, except an
event of default relating to the payment of principal, premium, if any, or
interest or special interest.

In general, the trustee is required to give notice of a default with
respect to the notes to the holders of those notes. However, the trustee may
withhold notice of any such default (except a default in payment of principal of
or interest on any note) if the trustee determines it is in the best interests
of the holders of the notes to do so.

If an event of default other than an event of default arising from events
of insolvency, bankruptcy or reorganization occurs and is continuing, either the
trustee or the holders of at least 25% in aggregate principal amount of the
outstanding notes may accelerate the maturity of all notes. However, after such
acceleration, but before a judgment or decree based on acceleration, the holders
of a majority in aggregate principal amount of outstanding notes may, under
certain circumstances, rescind and annul the acceleration if all events of
default, other than the non-payment of principal of the notes that have become
due solely by such declaration of acceleration, have been cured or waived as
provided in the indenture. If an event of default arising from events of
insolvency, bankruptcy or reorganization relating to us occurs and is
continuing, then the principal of, and accrued interest on, all of the notes
will automatically become immediately due and payable without any declaration or
other act on the part of the holders of the notes

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or the trustee. For information as to waiver of defaults, see "-- Meetings,
Modification and Waiver" below.

You will not have any right to institute any proceeding with respect to the
indenture, or for any remedy under the indenture, unless:

- you give the trustee written notice of a continuing event of default;

- the holders of at least 25% in aggregate principal amount of the
outstanding notes have made written request and offered indemnity
satisfactory to the trustee to institute proceedings;

- the trustee shall have failed to institute such proceeding within 60 days
of the written request; and

- the trustee has not received from the holders of a majority in aggregate
principal amount of the outstanding notes a direction inconsistent with
the written request within such 60 day period.

However, these limitations do not apply to a suit instituted by you for the
enforcement of payment of the principal of, premium, if any, or interest,
including special interest, on your note on or after the respective due dates
expressed in your note or your right to convert your note in accordance with the
indenture.

We will be required to furnish to the trustee annually a statement as to
our performance of certain of our obligations under the indenture and as to any
default in such performance. Upon becoming aware of any event of default, RRI is
required to deliver to the trustee a statement specifying such event of default.

MEETINGS, MODIFICATION AND WAIVER

The indenture contains provisions for convening meetings of the holders of
notes to consider matters affecting their interests.

The indenture may be amended or modified without the necessity of obtaining
the consent of the holders of the notes in order to, among other things:

- provide for our successor pursuant to a consolidation, merger or sale of
assets;

- add to our covenants for the benefit of the holders of all or any of the
notes or to surrender any right or power conferred upon us by the
indenture;

- provide for a successor trustee with respect to the notes;

- cure any ambiguity or correct or supplement any provision in the
indenture which may be defective or inconsistent with any other
provision, or to make any other provisions with respect to matters or
questions arising under the indenture which, in each case, will not
adversely affect the interests of the holders of the notes;

- add any additional events of default with respect to all or any of the
notes;

- secure the notes; or

- increase the conversion rate or reduce the conversion price, provided
that the increase or reduction, as the case may be, is in accordance with
the terms of the indenture or will not adversely affect the interests of
the holders of the notes.

Other modifications and amendments of the indenture may be made, compliance
by us with certain restrictive provisions of the indenture may be waived, and
any past defaults by us under the indenture (except: (1) a default in the
payment of principal, premium, if any, or interest, (2) failure to convert a
note into common stock or (3) failure to comply with any of the provisions of
the indenture that would require the consent of the holder of each outstanding
note affected) may be waived with the written consent of the holders of not less
than a majority in aggregate principal amount of the notes at the time
outstanding.

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The quorum at any meeting called to adopt a resolution will be persons
holding or representing a majority in aggregate principal amount of the notes at
the time outstanding and, at any reconvened meeting adjourned for lack of a
quorum, 25% of such aggregate principal amount.

However, a modification or amendment requires the consent of the holder of
each outstanding note affected if it would:

- change the stated maturity of the principal or interest of a note;

- reduce the principal amount of, or any premium or interest on, any note;

- reduce the amount payable upon a redemption or mandatory repurchase;

- modify the provisions with respect to the repurchase rights of holders of
notes in a manner adverse to the holders;

- modify our rights to redeem the notes in a manner adverse to the holders;

- change the place or currency of payment on a note;

- impair the right to institute suit for the enforcement of any payment on
any note;

- modify our obligation to maintain an office or agency in New York City;

- modify the subordination provisions in a manner that is adverse to the
holders of the notes;

- adversely affect the right to convert the notes other than a modification
or amendment permitted by the terms of the indenture;

- modify our obligation to deliver information required under Rule 144A to
permit resales of the notes and common stock issued upon conversion of
the notes if we cease to be subject to the reporting requirements under
the Exchange Act;

- reduce the above-stated percentage of the principal amount of the holders
whose consent is needed to modify or amend the indenture;

- reduce the percentage of the principal amount of the holders whose
consent is needed to waive compliance with certain provisions of the
indenture or to waive certain defaults;

- reduce the percentage of the principal amount of the holders required for
the adoption of a resolution or the quorum required at any meeting of
holders of notes at which a resolution is adopted; or

- modify the provisions with respect to meetings, modification and waiver.

We will generally be entitled to set any day as a record date for the
purpose of determining the holders of outstanding notes that are entitled to
take any action under the indenture. In limited circumstances, the trustee will
be entitled to set a record date for action by holders. If a record date is set
for any action to be taken by holders, such action may be taken only by persons
who are holders of outstanding notes on the record date and must be taken within
180 days following the record date or such other period as we may specify (or as
the trustee may specify, if it set the record date). This period may be
shortened or lengthened (but not beyond 180 days) from time to time.

REGISTRATION RIGHTS

We entered into a registration rights agreement with the initial purchasers
of the notes. If you sell the notes or shares of common stock issued upon
conversion of the notes under this registration statement, you generally will be
required to be named as a selling securityholder in this prospectus, deliver
this prospectus to purchasers and be bound by applicable provisions of the
registration rights agreement, including some indemnification provisions.

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In the registration rights agreement, we agreed to use our reasonable best
efforts to keep the registration statement effective until the earlier of (1)
the sale pursuant to this shelf registration statement of all securities
registered hereunder; (2) the expiration of the period referred to in Rule
144(k) of the Securities Act with respect to all the notes and the shares of
common stock issuable upon conversion of the notes held by persons that are not
our affiliates; or (3) June 24, 2005.

We may suspend the use of this prospectus under certain circumstances
relating to pending corporate developments, public filings with the SEC and
similar events for a period not to exceed 45 days in any 90-day period and not
to exceed an aggregate of 90 days in any 365-day period. We also agreed to pay
special interest to holders of the notes and shares of common stock issued upon
conversion of the notes if this registration statement is not timely filed or
made effective or if the prospectus is unavailable for periods in excess of
those permitted above. You should refer to the registrations rights agreement
for a description of this special interest.

NOTICES

Notice to holders of the registered notes will be given by mail to the
addresses as they appear in the security register. Notices will be deemed to
have been given on the date of such mailing.

Notice of a redemption of notes will be given not less than 30 nor more
than 60 days prior to the redemption date and will specify the redemption date.
A notice of redemption of the notes will be irrevocable.

REPLACEMENT OF NOTES

We will replace any note that becomes mutilated, destroyed, stolen or lost
at the expense of the holder upon delivery to the trustee of the mutilated notes
or evidence of the loss, theft or destruction satisfactory to us and the
trustee. In the case of a lost, stolen or destroyed note, indemnity satisfactory
to the trustee and us may be required at the expense of the holder of the note
before a replacement note will be issued.

PAYMENT OF STAMP AND OTHER TAXES

We will pay all stamp and other duties, if any, that may be imposed by the
United States or any political subdivision thereof or taxing authority thereof
or therein with respect to the issuance of the notes or of shares of stock upon
conversion of the notes. We will not be required to make any payment with
respect to any other tax, assessment or governmental charge imposed by any
government or any political subdivision thereof or taxing authority thereof or
therein.

SATISFACTION AND DISCHARGE

We may satisfy and discharge our obligations under the indenture while the
notes remain outstanding, subject to certain conditions, if:

- all outstanding notes will become due and payable at their scheduled
maturity within one year; or

- all outstanding notes are scheduled for redemption within one year,

and in either case, we have deposited with the trustee an amount in cash or cash
equivalents sufficient to pay and discharge all outstanding notes on the date of
their scheduled maturity or the scheduled date of redemption.

GOVERNING LAW

The indenture, the notes and the registration rights agreement are governed
by and construed in accordance with the laws of the State of New York, United
States of America.

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THE TRUSTEE

If an event of default occurs and is continuing, the trustee will be
required to use the degree of care of a prudent person in the conduct of his own
affairs in the exercise of its powers. Subject to such provisions, the trustee
will be under no obligation to exercise any of its rights or powers under the
indenture at the request of any of the holders of notes, unless they shall have
furnished to the trustee reasonable security or indemnity satisfactory to it.

The indenture contains certain limitations on the rights of the trustee, if
it or any of its affiliates is then our creditor, to obtain payment of claims in
certain cases or to realize on certain property received on any claims as
security or otherwise. The trustee and its affiliates will be permitted to
engage in other transactions with us. However, if the trustee or any affiliate
continues to have any conflicting interest and a default occurs with respect to
the notes, the trustee must eliminate such conflict or resign.

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DESCRIPTION OF CAPITAL STOCK

GENERAL

The following descriptions are summaries of material terms of our common
stock, preferred stock, restated certificate of incorporation and amended and
restated bylaws. This summary is qualified by reference to our restated
certificate of incorporation and amended and restated bylaws, copies of which
have been filed as exhibits to the registration statement of which this
prospectus is a part, and by the provisions of applicable law.

Our authorized capital stock consists of 2,000,000,000 shares of common
stock, par value $0.001 per share, and 125,000,000 shares of preferred stock,
par value $0.001 per share. Of the 125,000,000 shares of preferred stock,
2,000,000 shares have been designated Series A preferred stock. As of July 21,
2003, there were 294,286,986 shares of common stock outstanding, 5,517,014
shares of common stock held in treasury and there were no outstanding shares of
preferred stock.

COMMON STOCK

Each share of common stock entitles the holder to one vote on all matters
submitted to a vote of stockholders, including the election of directors. There
are no cumulative voting rights. Accordingly, holders of a majority of the total
votes entitled to vote in an election of directors will be able to elect all of
the directors standing for election. Subject to preferences that may be
applicable to any outstanding preferred stock, the holders of our common stock
are entitled to dividends when, as and if declared by our board of directors out
of funds legally available for that purpose. If we are liquidated, dissolved or
wound up, the holders of our common stock will be entitled to a pro rata share
in any distribution to stockholders, but only after satisfaction of all of our
liabilities and of the prior rights of any outstanding series of our preferred
stock. The common stock has no preemptive or conversion rights or other
subscription rights. There are no redemption or sinking fund provisions
applicable to the common stock. All outstanding shares of our common stock are
fully paid and nonassessable.

PREFERRED STOCK

Our board of directors has the authority, without stockholder approval, to
issue shares of preferred stock from time to time in one or more series, and to
fix the number of shares and terms of each such series. The board may determine
the designation and other terms of each series, including:

- dividend rates,

- redemption rights,

- liquidation rights,

- sinking fund provisions,

- conversion rights,

- voting rights, and

- any other designations, powers, preferences, rights, qualifications,
limitations, or restrictions.

The issuance of preferred stock, while providing desired flexibility in
connection with possible acquisitions and other corporate purposes, could
adversely affect the voting power of holders of our common stock. It could also
affect the likelihood that holders of our common stock will receive dividend
payments and payments upon liquidation.

The issuance of shares of preferred stock, or the issuance of rights to
purchase shares of preferred stock, could be used to discourage an attempt to
obtain control of our company. For example, if, in the exercise of its fiduciary
obligations, our board were to determine that a takeover proposal was not in our
best interest, the board could authorize the issuance of a series of preferred
stock containing class voting

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rights that would enable the holder or holders of the series to prevent or make
the change of control transaction more difficult. Alternatively, a change of
control transaction deemed by the board to be in our best interest could be
facilitated by issuing a series of preferred stock having sufficient voting
rights to provide a required percentage vote of the stockholders.

Holders of our common stock may purchase shares of our Series A preferred
stock if the rights associated with their common stock are exercisable and the
holders exercise the rights. Please read the "-- Stockholder Rights Plan"
section below.

SERIES A PREFERRED STOCK

Our Series A preferred stock ranks junior to all other series of our
preferred stock, and senior to our common stock with respect to dividend and
liquidation rights. If we liquidate, dissolve or wind up, we may not make any
distributions to holders of our common stock unless we first pay holders of our
Series A preferred stock an amount equal to:

- $1,000 per share, plus

- accrued and unpaid dividends and distributions on our Series A preferred
stock, whether or not declared, to the date of such payment.

If the dividends or distributions payable on our Series A preferred stock are in
arrears, we may not:

- declare or pay dividends on,

- make any other distributions on,

- redeem,

- purchase, or

- otherwise acquire for consideration, any shares of our common stock or
our Series A preferred stock, until we have paid all such unpaid
dividends or distributions, except in accordance with a purchase offer to
all holders of our Series A preferred stock upon terms that our board of
directors determines will be fair and equitable.

We may redeem shares of our Series A preferred stock at any time at a
redemption price determined in accordance with the provisions of our certificate
of incorporation.

Holders of shares of our Series A preferred stock are entitled to vote
together with holders of our common stock as one class on all matters submitted
to a vote of our stockholders. Each share of our Series A preferred stock
entitles its holder to a number of votes equal to the "adjustment number"
specified in our restated certificate of incorporation. The adjustment number is
initially equal to 1,000 and is subject to adjustment in the event we:

- declare any dividend on our common stock payable in shares of common
stock,

- subdivide our outstanding shares of common stock, or

- combine our outstanding shares of common stock into a smaller number of
shares.

ANTI-TAKEOVER EFFECTS OF DELAWARE LAWS AND OUR CHARTER AND BYLAW PROVISIONS

Some provisions of Delaware law and our restated certificate of
incorporation and bylaws could make the following more difficult:

- acquisition of us by means of a tender offer,

- acquisition of control of us by means of a proxy contest or otherwise, or

- removal of our incumbent officers and directors.

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These provisions, as well as our stockholder rights plan and our ability to
issue preferred stock, are designed to discourage coercive takeover practices
and inadequate takeover bids. These provisions are also designed to encourage
persons seeking to acquire control of us to first negotiate with our board of
directors. We believe that the benefits of increased protection give us the
potential ability to negotiate with the proponent of an unfriendly or
unsolicited proposal to acquire or restructure us, and that the benefits of this
increased protection outweigh the disadvantages of discouraging those proposals,
because negotiation of those proposals could result in an improvement of their
terms.

CHARTER AND BYLAW PROVISIONS

ELECTION AND REMOVAL OF DIRECTORS

Our board of directors may be comprised of between one and fifteen
directors, the exact number to be fixed from time to time by resolution of our
board of directors. Currently, our board of directors has five members. Our
board of directors is divided into three classes. The directors in each class
will serve for a three-year term, with only one class being elected each year by
our stockholders. This system of electing and removing directors may discourage
a third party from making a tender offer or otherwise attempting to obtain
control of us, because it generally makes it more difficult for stockholders to
replace a majority of our directors. In addition, no director may be removed
except for cause, and directors may be removed for cause by a majority of the
shares then entitled to vote at an election of directors. Any vacancy occurring
on the board of directors and any newly created directorship may only be filled
by a majority of the remaining directors in office.

STOCKHOLDER MEETINGS

Our bylaws provide that special meetings of our stockholders may be called
only by the chairman of our board of directors, our president and chief
executive officer, or a majority of the board of directors and may not be called
by the holders of common stock. In addition, our restated certificate of
incorporation and our bylaws specifically deny any power of the stockholders to
call a special meeting.

ELIMINATION OF STOCKHOLDER ACTION BY WRITTEN CONSENT

Our restated certificate of incorporation and our bylaws provide that
holders of our common stock will not be able to act by written consent without a
meeting.

AMENDMENT OF CERTIFICATE OF INCORPORATION

The provisions described above under "-- Election and Removal of
Directors", "-- Stockholder Meetings" and "-- Elimination of Stockholder Action
by Written Consent" may be amended only by the affirmative vote of holders of at
least 66 2/3% of the voting power of outstanding shares of our capital stock
entitled to vote in the election of directors, voting together as a single
class.

AMENDMENT OF BYLAWS

Our board of directors has the power to alter, amend or repeal our bylaws
or adopt new bylaws by the affirmative vote of at least 80% of all directors
then in office at any regular or special meeting of the board of directors
called for that purpose. This right is subject to repeal or change by the
affirmative vote of holders of at least 80% of the voting power of all
outstanding shares of our capital stock entitled to vote in the election of
directors, voting together as a single class.

OTHER LIMITATIONS ON STOCKHOLDER ACTIONS

Our bylaws also impose some procedural requirements on stockholders who
wish to:

- make nominations in the election of directors,

- propose that a director be removed,

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- propose any repeal or change in our bylaws, or

- propose any other business to be brought before an annual or special
meeting of stockholders.

With respect to special meetings of stockholders, our bylaws provide that
only such business shall be conducted as shall have been stated in the notice of
the meeting or shall otherwise have been brought before the meeting by or at the
direction of the chairman of the meeting or the board of directors.

Under these procedural requirements, in order to bring a proposal or
nomination before an annual meeting of stockholders, or in order to bring a
nomination before a meeting of stockholders, a stockholder must deliver timely
notice to our corporate secretary along with the following:

- a description of the business or nomination to be brought before the
meeting and the reasons for conducting such business at the meeting,

- the stockholder's name and address,

- the number of shares beneficially owned by the stockholder and evidence
of such ownership,

- the names and addresses of all persons with whom the stockholder is
acting in concert and a description of all arrangements and
understandings with such persons, and

- the number of shares such persons beneficially own.

To be timely, a stockholder must deliver notice:

- of a nomination or other business in connection with an annual meeting of
stockholders, not less than 90 nor more than 180 days prior to the date
on which the immediately preceding year's annual meeting of stockholders
was held, or

- of a nomination in connection with a special meeting of stockholders, not
less than 40 nor more than 60 days prior to the date of the special
meeting.

In order to submit a nomination for our board of directors, a stockholder
must also submit information with respect to the nominee that we would be
required to include in a proxy statement, as well as some other information. If
a stockholder fails to follow the required procedures, the stockholder's nominee
or proposal will be ineligible and will not be voted on by our stockholders.

LIMITATION ON LIABILITY OF DIRECTORS

Our restated certificate of incorporation provides that no director shall
be personally liable to us or our stockholders for monetary damages for breach
of fiduciary duty as a director, except as required by law, as in effect from
time to time. Currently, Delaware law requires that liability be imposed for the
following:

- any breach of the director's duty of loyalty to our company or our
stockholders,

- any act or omission not in good faith or which involved intentional
misconduct or a knowing violation of law,

- unlawful payments of dividends or unlawful stock repurchases or
redemptions, and

- any transaction from which the director derived an improper personal
benefit.

Our bylaws provide that, to the fullest extent permitted by law, we will
indemnify any officer or director of our company against all damages, claims and
liabilities arising out of the fact that the person is or was our director or
officer, or served any other enterprise at our request as a director, officer,
employee, agent or fiduciary. We will reimburse the expenses, including
attorneys' fees, incurred by a person indemnified by this provision when we
receive an undertaking to repay such amounts if it is ultimately determined that
the person is not entitled to be indemnified by us. Amending this provision will
not reduce our indemnification obligations relating to actions taken before an
amendment.

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STOCKHOLDER RIGHTS PLAN

Each share of common stock includes one right to purchase from us a unit
consisting of one-thousandth of a share of our Series A preferred stock at a
purchase price of $150.00 per unit, subject to adjustment. The rights are issued
pursuant to a rights agreement between us and JP Morgan Chase Bank, as successor
to The Chase Manhattan Bank, as rights agent. We have summarized selected
portions of the rights agreement and the rights below. For a complete
description of the rights, we encourage you to read the summary below and the
rights agreement, which we have filed as an exhibit to the registration
statement of which this prospectus is a part.

DETACHMENT OF RIGHTS; EXERCISABILITY

The rights are evidenced by the certificates representing our currently
outstanding common stock and all common stock certificates we issue prior to the
"distribution date". That date will occur, except in some cases, on the earlier
of:

- ten days following a public announcement that a person or group of
affiliated or associated persons, who we refer to collectively as an
"acquiring person", has acquired, or obtained the right to acquire,
beneficial ownership of 15% or more of the outstanding shares of our
common stock, or

- ten business days following the start of a tender offer or exchange offer
that would result in a person becoming an acquiring person.

Our board of directors may defer the distribution date in some
circumstances. Also, some inadvertent acquisitions of our common stock will not
result in a person becoming an acquiring person if the person promptly divests
itself of sufficient common stock.

Until the distribution date:

- common stock certificates will evidence the rights,

- the rights will be transferable only with those certificates,

- new common stock certificates will contain a notation incorporating the
rights agreement by reference, and

- the surrender for transfer of any common stock certificate will also
constitute the transfer of the rights associated with the common stock
represented by the certificate.

The rights are not exercisable until the distribution date and will expire
at the close of business on January 15, 2011, unless we redeem or exchange them
at an earlier date as described below or we extend the expiration date prior to
January 15, 2011.

As soon as practicable after the distribution date, the rights agent will
mail certificates representing the rights to holders of record of common stock
as of the close of business on the distribution date. From that date on, only
separate rights certificates will represent the rights. We will issue rights
with all shares of common stock issued prior to the distribution date. We will
also issue rights with shares of common stock issued after the distribution date
in connection with some employee benefit plans or upon conversion of some
securities. Except as otherwise determined by our board of directors, we will
not issue rights with any other shares of common stock issued after the
distribution date.

FLIP-IN EVENT

A "flip-in event" will occur under the rights agreement when a person
becomes an acquiring person otherwise than pursuant to a "permitted offer". The
rights agreement defines "permitted offer" as a tender or exchange offer for all
outstanding shares of our common stock at a price and on terms that a majority
of the independent directors on our board of directors determines to be fair to
and otherwise in our best interests and the best interests of our stockholders.

109

If a flip-in event occurs, each right, other than any right that has become
null and void as described below, will become exercisable to receive the number
of shares of common stock, or in some specified circumstances, cash, property or
other securities, which has a "current market price" equal to two times the
exercise price of the right. Please refer to the rights agreement for the
definition of "current market price".

FLIP-OVER EVENT

A "flip-over event" will occur under the rights agreement when, at any time
from and after the time a person becomes an acquiring person:

- we are acquired by any person or we acquire any person in a merger or
other business combination transaction, other than specified mergers that
follow a permitted offer, or

- 50% or more of our assets, cash flow or earning power is sold, leased or
transferred.

If a flip-over event occurs, each holder of a right, except rights that are
voided as described below, will thereafter have the right to receive, on
exercise of the right, a number of shares of common stock of the acquiring
company that has a current market price equal to two times the exercise price of
the right.

When a flip-in event or a flip-over event occurs, all rights that then are,
or under the circumstances the rights agreement specifies previously were,
beneficially owned by an acquiring person or specified related parties will
become null and void in the circumstances the rights agreement specifies.

SERIES A PREFERRED STOCK

After the distribution date, each right will entitle the holder to purchase
a fractional share of our Series A preferred stock, which will be essentially
the economic equivalent of one share of common stock. Please refer to the
"-- Preferred Stock -- Series A Preferred Stock" section above for additional
information about our Series A preferred stock.

ANTIDILUTION

The number of rights associated with a share of outstanding common stock,
the number of fractional shares of Series A preferred stock issuable upon
exercise of a right and the exercise price of the right are subject to
adjustment in the event of a stock dividend on, or a subdivision, combination or
reclassification of, our common stock occurring prior to the distribution date.
The exercise price of the rights and the number of fractional shares of Series A
preferred stock or other securities or property issuable on exercise of the
rights are subject to adjustment from time to time to prevent dilution in the
event of some specified transactions affecting the Series A preferred stock.

With some exceptions, we will not be required to adjust the exercise price
of the rights until cumulative adjustments amount to at least 1% of the exercise
price. The rights agreement also will not require us to issue fractional shares
of Series A preferred stock that are not integral multiples of the specified
fractional share and, in lieu thereof, we will make a cash payment based on the
market price of the Series A preferred stock on the last trading date prior to
the date of exercise. Pursuant to the rights agreement, we reserve the right to
require prior to the occurrence of any flip-in event or flip-over event that, on
any exercise of rights, a number of rights be exercised so that we will issue
only whole shares of Series A preferred stock.

REDEMPTION OF RIGHTS

At any time until the time a person becomes an acquiring person, we may
redeem the rights in whole, but not in part, at a price of $.005 per right,
payable, at our option, in cash, shares of common stock or such other
consideration as our board of directors may determine. Upon such redemption, the
rights will terminate and the only right of the holders of rights will be to
receive the $.005 redemption price.

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EXCHANGE OF RIGHTS

At any time after the occurrence of a flip-in event and prior to a person
becoming the beneficial owner of 50% or more of our outstanding common stock or
the occurrence of a flip-over event, we may exchange the rights, other than
rights owned by an acquiring person or an affiliate or an associate of an
acquiring person, which will have become void, in whole or in part, at an
exchange ratio of one share of common stock, and/or other equity securities
deemed to have the same value as one share of common stock, per right, subject
to adjustment.

SUBSTITUTION

If we have an insufficient number of authorized but unissued shares of
common stock available to permit an exercise or exchange of rights upon the
occurrence of a flip-in event, we may substitute other specified types of
property for common stock so long as the total value received by the holder of
the rights is equivalent to the value of the common stock that the stockholder
would otherwise have received. We may substitute cash, property, equity
securities or debt, reduce the exercise price of the rights or use any
combination of the foregoing.

NO RIGHTS AS A STOCKHOLDER; TAXES

Until a right is exercised, a holder of rights will have no rights to vote
or receive dividends or any other rights as a stockholder of our common stock.
Stockholders may, depending upon the circumstances, recognize taxable income in
the event that the rights become exercisable for our common stock, or other
consideration, or for the common stock of the acquiring company or are exchanged
as described above.

AMENDMENT OF TERMS OF RIGHTS

Our board of directors may amend any of the provisions of the rights
agreement, other than some specified provisions relating to the principal
economic terms of the rights and the expiration date of the rights, at any time
prior to the time a person becomes an acquiring person. Thereafter, our board of
directors may only amend the rights agreement in order to cure any ambiguity,
defect or inconsistency or to make changes that do not materially and adversely
affect the interests of holders of the rights, excluding the interests of any
acquiring person.

RIGHTS AGENT

JP Morgan Chase Bank, as successor to The Chase Manhattan Bank, serves as
rights agent with regard to the rights.

ANTITAKEOVER EFFECTS

The rights will have anti-takeover effects. They will cause substantial
dilution to any person or group that attempts to acquire us without the approval
of our board of directors. As a result, the overall effect of the rights may be
to make more difficult or discourage any attempt to acquire us even if such
acquisition may be favorable to the interests of our stockholders. Because our
board of directors can redeem the rights or approve a permitted offer, the
rights should not interfere with a merger or other business combination approved
by our board of directors.

DELAWARE ANTITAKEOVER LAW

We are subject to Section 203 of the Delaware General Corporation Law.
Section 203 prohibits Delaware corporations from engaging in a wide range of
specified transactions with any interested stockholder. An interested
stockholder is any person, other than the corporation and any of its majority-
owned subsidiaries, who owns 15% or more of any class or series of stock
entitled to vote generally in the election of directors. Section 203 may tend to
deter any potential unfriendly offers or other efforts to

111

obtain control of our company that are not approved by our board. This may
deprive the stockholders of opportunities to sell shares of our common stock at
prices higher than the prevailing market price.

SELLING SECURITYHOLDERS

The notes were originally issued by us and sold by Deutsche Bank Securities
Inc., Goldman, Sachs & Co., Banc of America Securities LLC, Barclays Capital
Inc., ABN AMRO Rothschild LLC and Commerzbank Capital Markets Corp. (the
"initial purchasers") in transactions exempt from the registration requirements
of the Securities Act to persons reasonably believed by the initial purchasers
to be "qualified institutional buyers" as defined by Rule 144A under the
Securities Act. The selling securityholders may from time to time offer and sell
pursuant to this prospectus any or all of the notes listed below and the shares
of common stock issued upon conversion of such notes. When we refer to the
"selling securityholders" in this prospectus, we mean those persons listed in
the table below, as well as the pledgees, donees, assignees, transferees,
successors and others who later hold any of the selling securityholders'
interests.

The table below sets forth the name of each selling securityholder, the
principal amount of notes that each selling securityholder may offer pursuant to
this prospectus and the number of shares of common stock into which such notes
are convertible. Unless set forth below, to our knowledge, none of the selling
securityholders has, or within the past three years has had, any material
relationship with us or any of our predecessors or affiliates or beneficially
owns in excess of 1% of the outstanding common stock.

The principal amounts of the notes provided in the table below is based on
information provided to us by each of the selling securityholders as of
, 2003, and the percentages are based on $275,000,000 principal amount
of notes outstanding. The number of shares of common stock that may be sold is
calculated based on the current conversion rate of $104.8108 shares of common
stock per each $1,000 principal amount of notes. Since the date on which each
selling securityholder provided this information, each selling securityholder
identified below may have sold, transferred or otherwise disposed of all or a
portion of its notes in a transaction exempt from the registration requirements
of the Securities Act. Information concerning the selling securityholders may
change from time to time and any changed information will be set forth in
supplements to this prospectus to the extent required. In addition, the
conversion ratio, and therefore the number of shares of our common stock
issuable upon conversion of the notes, is subject to adjustment. Accordingly,
the number of shares of common stock issuable upon conversion of the notes may
increase or decrease.

The selling securityholders may from time to time offer and sell any or all
of the securities under this prospectus. Because the selling securityholders are
not obligated to sell the notes or the shares of common stock issuable upon
conversion of the notes, we cannot estimate the amount of the notes or how many
shares of common stock that the selling securityholders will hold upon
consummation of any such sales.

PERCENTAGE OF
AGGREGATE PRINCIPAL NUMBER OF SHARES SHARES OF
AMOUNT OF NOTES PERCENTAGE OF OF COMMON STOCK COMMON STOCK
NAME THAT MAY BE SOLD NOTES OUTSTANDING THAT MAY BE SOLD(1) OUTSTANDING(2)
---- ------------------- ----------------- ------------------- --------------

All other holders of notes
or future transferees,
pledgees, donees,
assignees or successors of
any such holders(3)(4).... $ % %
$ % %
$ % %
------------ ---- ---------- ----
Total....................... $275,000,000 100% 28,822,970(5) %(6)
============ ==== ========== ====

---------------

(1) Assumes conversion of all of the holder's notes at a conversion rate of
104.8108 shares of common stock per $1,000 principal amount of the notes.
This conversion rate is subject to adjustment, however, as described under
"Description of Notes --

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Conversion Rights." As a result, the number of shares of common stock
issuable upon conversion of the notes may increase or decrease in the
future.

(2) Calculated based on Rule 13d-3(d)(i) of the Exchange Act, using common
shares outstanding as of July 21, 2003 In calculating this amount for each
holder, we treated as outstanding the number of shares of common stock
issuable upon conversion of all that holder's notes, but we did not assume
conversion of any other holder's notes.

(3) Information about other selling shareholders will be set forth in prospectus
supplements, if required.

(4) Assumes that any other holders of the notes or any future pledgees, donees,
assignees, transferees or successors of or from any other such holders of
the notes, do not beneficially own any shares of common stock other than the
common stock issuable upon conversion of the notes at the initial conversion
rate.

(5) Represents the number of shares of common stock into which $275,000,000 of
notes would be convertible at the conversion rate described in footnote 1
above.

(6) Represents the amount which the selling securityholders may sell under this
prospectus divided by the sum of the common stock outstanding as of July 21,
2003 plus the 28,822,970 shares of common stock into which the $275,000,000
notes are convertible.

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UNITED STATES FEDERAL INCOME TAX CONSEQUENCES

The following is a summary of the material United States federal income tax
consequences of an investment in the notes and common stock received pursuant to
a conversion of the notes. This summary is based upon United States federal
income tax law in effect on the date of this prospectus, which is subject to
change or different interpretations, possibly with retroactive effect. This
summary does not discuss all aspects of United States federal income taxation
which may be important to particular investors in light of their individual
investment circumstances, such as notes held by investors subject to special tax
rules (e.g., financial institutions, insurance companies, broker-dealers, and
domestic and foreign tax-exempt organizations (including private foundations))
or to persons that will hold the notes or common stock received pursuant to a
conversion of the notes as part of a straddle, hedge, conversion, constructive
sale, or other integrated security transaction for United States federal income
tax purposes or that have a functional currency other than the United States
dollar, all of whom may be subject to tax rules that differ significantly from
those summarized below. In addition, this summary does not discuss any (i)
United States federal income tax consequences to a Non-U.S. Holder (as defined
below) that is (A) engaged in the conduct of a United States trade or business
or (B) a nonresident alien individual and such individual is present in the
United States for 183 or more days during the taxable year and (ii) state,
local, or non-United States tax considerations. This summary assumes that
investors will hold their notes, and common stock received pursuant to a
conversion of notes, as "capital assets" (generally, property held for
investment) under the Internal Revenue Code of 1986 (the Code). Each prospective
investor is urged to consult his tax advisor regarding the United States
federal, state, local, and non-United States income and other tax considerations
of an investment in the notes, including as a result of changes to United States
federal income tax law after the date of this prospectus.

For purposes of this summary, a "U.S. Holder" is a beneficial owner of
notes, or common stock received pursuant to a conversion of the notes, that is,
for United States federal income tax purposes, (i) an individual who is a
citizen or resident of the United States, (ii) a corporation, partnership, or
other entity created in, or organized under the law of, the United States or any
State or political subdivision thereof, (iii) an estate the income of which is
includible in gross income for United States federal income tax purposes
regardless of its source, or (iv) a trust (A) the administration of which is
subject to the primary supervision of a United States court and which has one or
more United States persons who have the authority to control all substantial
decisions of the trust, or (B) that was in existence on August 20, 1996, was
treated as a United States person on the previous day, and elected to continue
to be so treated. A beneficial owner of notes, or common stock received pursuant
to a conversion of the notes, that is not a U.S. Holder is referred to herein as
a "Non-U.S. Holder."

U.S. HOLDERS

PAYMENTS OF INTEREST

Payments of interest on the notes made to a U.S. Holder will be subject to
tax as ordinary income at the time the interest is received or accrued in
accordance with such holder's method of accounting for United States federal
income tax purposes.

MARKET DISCOUNT

If a U.S. Holder acquires the notes at a price that is less than their
issue price, the holder will generally be treated as acquiring the notes with
"market discount." A holder who acquires the notes at a market discount that is
more than a statutorily-defined "de minimis" amount will generally be required
to recognize ordinary income upon a sale or other taxable disposition of the
notes to the extent of the lesser of the accrued market discount on the notes or
any gain recognized upon such disposition. Such market discount will accrue
ratably or, at the election of the holder, under a constant yield method over
the remaining term of the notes. A U.S. Holder will also be required to defer
the deduction of a portion of the interest paid or accrued on indebtedness
incurred to purchase or carry the notes acquired with market discount. In the
alternative, a U.S. Holder may elect to include market discount in income
currently as it

114

accrues on all market discount instruments acquired by such holder in the
taxable year of the election and thereafter, in which case the foregoing rules
will not apply. In addition, a U.S. Holder will not recognize income for any
accrued market discount attributable to notes converted into common stock. Upon
disposition of such common stock received, however, any gain will be treated as
ordinary income to the extent of such accrued market discount not previously
included in income.

BOND PREMIUM

If a U.S. Holder acquires notes at a price that is greater than the stated
principal amount of the notes, the holder will generally be treated as acquiring
the notes with "bond premium" for United States federal income tax purposes. The
amount of such premium will be included in the adjusted tax basis of the notes
which may result in a capital loss upon the sale or other taxable disposition of
the notes. In lieu of the foregoing, the holder may elect to amortize such
premium, as an offset to the payments of interest on the notes using a constant
yield method during the period commencing with the purchase date of the notes
and ending on the maturity date of the notes (or, if it would result in a
smaller amount of amortizable bond premium, an earlier call date).

CONVERSION OF THE NOTES INTO COMMON STOCK

If a U.S. Holder converts the notes into common stock, such holder will
generally not recognize gain or loss except to the extent of cash received in
lieu of a fractional share of common stock. In the case of cash received in lieu
of a fractional share, a holder will generally recognize capital gain or loss,
for United States federal income tax purposes, equal to the difference between
the amount of cash received and the tax basis in such fractional share, except
to the extent of accrued market discount allocable to such share but not
previously included in income which shall be treated as ordinary income to the
extent of any recognized gain. Such gain or loss will generally be long-term if
the holder's holding period in respect of the notes is more than one year. A
U.S. Holder's tax basis in the common stock received upon such conversion should
generally equal such holder's adjusted tax basis in the notes (taking into
account any previously recognized accrued market discount or any adjustments
pursuant to the bond premium rules and hereinafter referred to as the "adjusted
tax basis" in the notes) tendered in exchange therefor, less the tax basis
allocated to any fractional share for which cash is received. A U.S. Holder's
holding period in the common stock received upon conversion of the notes will
include the holding period of notes so converted.

SALE, EXCHANGE, OR OTHER DISPOSITION OF THE NOTES OR COMMON STOCK

Upon a sale, exchange, or other disposition of the notes (other than a
conversion of the notes into common stock as described under "-- Conversion of
the Notes into Common Stock" above), or common stock previously received
pursuant to a conversion of the notes, a U.S. Holder will generally recognize
capital gain or loss equal to the difference between (i) the amount of cash and
the fair market value of any property received upon such disposition and (ii)
the holder's adjusted tax basis in the notes or common stock previously received
pursuant to a conversion or exchange of the notes. Such gain or loss will be (i)
capital gain or loss, except in the case of gain, to the extent of accrued
market discount not previously included in income and (ii) long-term if the
holder's holding period in respect of such notes or common stock is more than
one year.

CONSTRUCTIVE DIVIDENDS

If at any time we make a distribution of property to our stockholders that
would be taxable to the stockholders as a dividend for United States federal
income tax purposes and, in accordance with the anti-dilution provisions of the
notes, the conversion rate of the notes is increased, such increase may be
deemed to be the payment of a taxable dividend, for United States federal income
tax purposes, to holders of the notes. For example, an increase in the
conversion rate in the event of distributions of our debt instruments, or our
assets, or an increase in the event of an extraordinary cash dividend, generally
will result in deemed dividend treatment to holders of the notes, but an
increase in the event of stock dividends or the distribution of rights to
subscribe for our common stock generally will not.
115

NON-U.S. HOLDERS

PAYMENTS OF INTEREST

Payments of interest on the notes made to a Non-U.S. Holder will not be
subject to United States federal income or withholding tax provided that (i)
such holder is not a controlled foreign corporation that is related to us
through stock ownership and (ii) the statement requirement set forth in section
871(h) or 881(c) of the Code is satisfied (the "Statement Requirement"). The
Statement Requirement generally will be satisfied if the beneficial owner of the
notes certifies on United States Internal Revenue Service Form W-8BEN (or a
suitable substitute form), under penalties of perjury, that it is not a United
States person and provides its name and address or otherwise satisfies
applicable documentation requirements.

DIVIDENDS AND CONSTRUCTIVE DIVIDENDS

Dividends paid or constructive dividends deemed paid (see "U.S.
Holders -- Constructive Dividends" above) to a Non-U.S. Holder generally will be
subject to United States federal withholding tax at a 30% rate subject to
reduction or complete exemption under an applicable treaty if the Non-U.S.
Holder provides a United States Internal Revenue Service Form W-8BEN (or a
suitable substitute form) certifying that it is entitled to such treaty
benefits.

SALE, EXCHANGE, CONVERSION, OR OTHER DISPOSITION OF THE NOTES AND CONVERSION
INTO COMMON STOCK

Upon a sale, exchange, conversion, or other disposition of the notes and
common stock received pursuant to a previous conversion of the notes, a Non-U.S.
Holder will generally not be subject to United States federal income tax.

INFORMATION REPORTING AND BACKUP WITHHOLDING

Information returns will be filed annually with the United States Internal
Revenue Service and provided to each Non-U.S. Holder with respect to any
payments on the notes or common stock received pursuant to a previous conversion
of the notes and the proceeds from their sale or other disposition that are
subject to withholding or that are exempt from United States withholding tax
pursuant to an applicable income tax treaty or other reason. Copies of these
information returns also may be made available under the provisions of a
specific treaty or agreement to the tax authorities of the country in which the
Non-U.S. Holder resides. Under certain circumstances, the Code imposes a backup
withholding obligation. Interest, dividends, or constructive dividends paid to a
Non-U.S. Holder of the notes or common stock generally will be exempt from
backup withholding if the Non-U.S. Holder satisfies the Statement Requirement
described above.

The payment of the proceeds from the disposition of the notes or common
stock received pursuant to a previous conversion of the notes to or through the
United States office of any broker, United States or foreign, will be subject to
information reporting and possible backup withholding unless the owner certifies
as to its non-United States status, under penalties of perjury, or otherwise
establishes an exemption, provided that the broker does not have actual
knowledge or reason to know that the holder is a United States person or that
the conditions of any other exemption are not, in fact, satisfied. The payment
of the proceeds from the disposition of the notes or common stock to or through
a non-United States office of a non-United States broker will not be subject to
information reporting or backup withholding unless the non-United States broker
has certain types of relationships with the United States (a "United States
related person"). In the case of the payment of the proceeds from the
disposition of the notes or common stock to or through a non-United States
office of a broker that is either a United States person or a United States
related person, information reporting (but not backup withholding) will apply to
the payment unless the broker has documentary evidence in its files that the
owner is a Non-U.S. Holder and the broker has no knowledge or reason to know
otherwise.

Backup withholding is not an additional tax. Any amounts withheld under the
backup withholding rules from a payment to a Non-U.S. Holder may be refunded or
credited against the Non-U.S. Holder's United States federal income tax
liability, if any, if the Non-U.S. Holder provides, on a timely basis, the
required information to the United States Internal Revenue Service.
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PLAN OF DISTRIBUTION

The selling securityholders will be offering and selling all of the
securities offered and sold under this prospectus. We will not receive any of
the proceeds from the offering of the notes or the shares of common stock by the
selling securityholders. In connection with the initial offering of the notes,
we entered into a registration rights agreement dated as of June 24, 2003 with
the initial purchasers of the notes. Securities may only be offered or sold
under this prospectus pursuant to the terms of the registration rights
agreement. However, selling securityholders may resell all or a portion of the
securities in open market transactions in reliance upon Rule 144 or Rule 144A
under the Securities Act, provided they meet the criteria and conform to the
requirements of one of these rules. We are registering the notes and shares of
common stock covered by this prospectus to permit holders to conduct public
secondary trading of these securities from time to time after the date of this
prospectus. We have agreed, among other things, to bear all expenses, other than
underwriting discounts and selling commissions, in connection with the
registration and sale of the notes and the shares of common stock covered by
this prospectus.

The selling securityholders may sell all or a portion of the notes and
shares of common stock beneficially owned by them and offered hereby from time
to time:

- directly; or

- through underwriters, broker-dealers or agents, who may receive
compensation in the form of discounts, commissions or concessions from
the selling securityholders and/or from the purchasers of the notes and
shares of common stock for whom they may act as agent.

The notes and the shares of common stock may be sold from time to time in
one or more transactions at:

- fixed prices, which may be changed;

- prevailing market prices at the time of sale;

- varying prices determined at the time of sale; or

- negotiated prices.

These prices will be determined by the securityholders or by agreement
between these holders and underwriters or dealers who may receive fees or
commissions in connection with the sale. The aggregate proceeds to the selling
securityholders from the sale of the notes or shares of common stock offered by
them hereby will be the purchase price of the notes or shares of common stock
less discounts and commissions, if any. The sales described in the preceding
paragraph may be effected in transactions:

- on any national securities exchange or quotation service on which the
notes or shares of common stock may be listed or quoted at the time of
sale, including the New York Stock Exchange in the case of the shares of
common stock;

- in the over-the counter market;

- in transactions otherwise than on such exchanges or services or in the
over-the-counter market; or

- through the writing of options.

These transactions may include block transactions or crosses. Crosses are
transactions in which the same broker acts as an agent on both sides of the
trade. In connection with sales of the notes and shares of common stock or
otherwise, the selling securityholders may enter into hedging transactions with
broker-dealers. These broker-dealers may in turn engage in short sales of the
notes and shares of common stock in the course of hedging their positions. The
selling securityholders may also sell the notes and shares of common stock short
and deliver the notes and shares of common stock to close out short positions,
or loan or pledge notes and shares of common stock to broker-dealers that in
turn may sell the notes and shares of common stock.

117

To our knowledge, there are currently no plans, arrangements or
understandings between any selling securityholders and any underwriter,
broker-dealer or agent regarding the sale of the notes and the shares of common
stock by the selling securityholders. Selling securityholders may not sell any,
or may not sell all, of the notes and the shares of common stock offered by them
pursuant to this prospectus. In addition, we cannot assure you that a selling
securityholder will not transfer, devise or gift the notes and the shares of
common stock by other means not described in this prospectus. In addition, any
securities covered by this prospectus which qualify for sale pursuant to Rule
144 or Rule 144A of the Securities Act may be sold under Rule 144 or Rule 144A
rather than pursuant to this prospectus.

The notes were issued and sold in June and July 2003 in transactions exempt
from the registration requirements of the Securities Act to persons reasonably
believed by the initial purchasers to be "qualified institutional buyers," as
defined in Rule 144A under the Securities Act. Pursuant to the registration
rights agreement, we have agreed to indemnify the initial purchasers and each
selling securityholder, and each selling securityholder has agreed to indemnify
us against specified liabilities arising under the Securities Act. The selling
securityholders may also agree to indemnify any broker-dealer or agent that
participates in transactions involving sales of the securities against some
liabilities, including liabilities that arise under the Securities Act.

The selling securityholders and any other person participating in such
distribution will be subject to the Exchange Act. The Exchange Act rules
include, without limitation, Regulation M, which may limit the timing of
purchases and sales of any of the notes and the shares of common stock issuable
upon conversion of the notes by the selling securityholders and any such other
person. In addition, Regulation M of the Exchange Act may restrict the ability
of any person engaged in the distribution of the notes and the shares of common
stock issuable upon conversion of the notes to engage in market-making
activities with respect to the particular notes and the shares of common stock
issuable upon conversion of the notes being distributed for a period of up to
five business days prior to the commencement of distribution. This may affect
the marketability of the notes and the shares of common stock issuable upon
conversion of the notes and the ability of any person or entity to engage in
market-making activities with respect to the notes and the shares of common
stock issuable upon conversion of the notes.

Under the registration rights agreement, we are obligated to use our
reasonable best efforts to keep the registration statement of which this
prospectus is a part effective until the earlier of:

- the sale, pursuant to the registration statement to which this prospectus
relates, of all the securities registered thereunder;

- the expiration of the period referred to in Rule 144(k) of the Securities
Act with respect to all the notes and the shares of common stock issuable
upon conversion of the notes held by persons that are not our affiliates;
and

- June 24, 2005.

Our obligation to keep the registration statement to which this prospectus
relates effective is subject to specified, permitted exceptions set forth in the
registration rights agreement. In these cases, we may prohibit offers and sales
of the notes and shares of common stock issuable upon conversion of the notes
pursuant to the registration statement to which this prospectus relates.

We may suspend the use of this prospectus if we learn of any event that
causes this prospectus to include an untrue statement of a material fact
required to be stated in the prospectus or necessary to make the statements in
the prospectus not misleading in light of the circumstances then existing. If
this type of event occurs, a prospectus supplement or post-effective amendment,
if required, will be distributed to each selling securityholder. Each selling
securityholder has agreed to suspend the use of such prospectus from the time
the selling securityholder receives notice from us of this type of event until
the selling securityholder receives a prospectus supplement or amendment.

118

LEGAL MATTERS

Certain legal matters regarding the notes and shares of common stock into
which notes are convertible will be passed upon for Reliant Resources, Inc. by
Skadden, Arps, Slate, Meagher & Flom LLP, New York, New York.

EXPERTS

The consolidated financial statements and the related financial statement
schedules of Reliant Resources, Inc. as of December 31, 2001 and 2002 and for
each of the three years in the period ended December 31, 2002, incorporated in
this prospectus by reference from the Current Report on Form 8-K of Reliant
Resources, Inc. dated June 30, 2003, have been audited by Deloitte & Touche LLP,
independent auditors, as stated in their report (which report expresses an
unqualified opinion and includes explanatory paragraphs relating to (i) the
change in method of accounting for derivatives and hedging activities in 2001,
(ii) the change in method of accounting for goodwill and other intangibles in
2002, (iii) the change in method of presenting trading and marketing activities
from a gross basis to net basis in 2002, (iv) the change in method of accounting
for early debt extinguishment, (v) accounting for European energy operations as
discontinued operations, and (vi) the restatement of the 2000 and 2001
consolidated financial statements) which is incorporated herein by reference,
and have been so incorporated in reliance upon the report of such firm given
upon their authority as experts in accounting and auditing.

The financial statements of El Dorado Energy, LLC as of December 31, 2002
and 2001 and for each of the three years in the period ended December 31, 2002,
incorporated in this prospectus by reference from the Current Report on Form 8-K
of Reliant Resources, Inc. dated June 30, 2003, have been audited by Deloitte &
Touche LLP, independent auditors, as stated in their report (which report
expresses an unqualified opinion and includes an explanatory paragraph relating
to the change in method of accounting for derivatives and hedging activities in
2001) which is incorporated herein by reference, and have been so incorporated
in reliance upon the report of such firm given upon their authority as experts
in accounting and auditing.

119

APPENDIX A
GLOSSARY OF TERMS

The following terms are used in this prospectus:

Alliance RTO.................. the proposed RTO for all or parts of Missouri,
Illinois, Indiana, Michigan, Ohio, Kentucky,
West Virginia, Pennsylvania, Tennessee,
Virginia and North Carolina.

Bcf........................... one billion cubic feet of natural gas.

Cal ISO....................... California Independent System Operator.

Cal PX........................ California Power Exchange.

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.

Channelview................... Reliant Energy Channelview L.P., one of our
subsidiaries.

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.

Duquesne Light................ Duquesne Light Company

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.

EPA........................... Environmental Protection Agency.

ERCOT......................... Electric Reliability Council of Texas.

ERCOT ISO..................... ERCOT Independent System Operator.

ERCOT Region.................. the electric market operated by ERCOT.

FASB.......................... Financial Accounting Standards Board.

FERC.......................... Federal Energy Regulatory Commission.

FIN No. 46.................... FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation
of ARB No. 51".

FPA........................... the Federal Power Act.

FPSC.......................... Florida Public Service Commission.

GridFlorida RTO............... the FERC approved RTO for Florida.

GW............................ gigawatt.

GWh........................... gigawatt hour.

A-1

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.

KWh........................... kilowatt hour.

LEP........................... Liberty Electric Power, LLC, one of our
subsidiaries.

Liberty....................... Liberty Electric PA, LLC, one of our
subsidiaries.

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.

MW............................ megawatt.

MWh........................... megawatt hour.

NEA........................... NEA, B.V., formerly the coordinating body for
the Dutch electric generating sector.

Nuon.......................... N.V. Nuon, a Netherlands-based electricity
distributor.

NYISO......................... New York Independent System Operator.

NY Market..................... the wholesale electric market operated by
NYISO.

Orion Capital................. Orion Power Capital, LLC., one of our
subsidiaries.

Orion MidWest................. Orion Power MidWest, L.P., one of our
subsidiaries.

Orion NY...................... Orion Power New York, L.P., one of our
subsidiaries.

Orion Power................... Orion Power Holdings, Inc., one of our
subsidiaries.

OTC........................... over-the-counter market.

PEDFA......................... Pennsylvania Economic Development Financing
Authority.

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.

A-2

RECE.......................... Reliant Energy Capital (Europe), Inc., one of
our subsidiaries.

REDB.......................... Reliant Energy Desert Basin, LLC, one of our
subsidiaries.

Reliant Energy................ Reliant Energy, Incorporated and its
subsidiaries.

Reliant Energy Services....... Reliant Energy Services, Inc., one of our
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.

RERH.......................... Reliant Energy Retail Holdings, LLC, one of our
subsidiaries.

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.

SFAS.......................... Statement of Financial Accounting Standards.

SFAS No. 133.................. SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities", as
amended.

SFAS No. 142.................. SFAS No. 142, "Goodwill and Other Intangible
Assets".

SFAS No. 144.................. SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets".

SMD........................... the standard market design for the wholesale
electric market proposed by the FERC.

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.

West Connect RTO.............. the FERC approved RTO for all or part of
Colorado, Arizona, New Mexico and a portion of
Texas.

A-3

PART II

INFORMATION NOT REQUIRED IN PROSPECTUS

ITEM 14. OTHER EXPENSES AND ISSUANCES OF DISTRIBUTION

The following table sets forth all fees and expenses in connection with the
issuance and distribution of the securities being registered hereby (other than
underwriting discounts and commissions). All of such expenses, except the SEC
registration fee are estimated.

SEC registration fee........................................ $22,247.50
Blue sky expenses........................................... *
Attorney's fees and expenses................................ *
Independent Auditor's fees and expenses..................... *
Printing and engraving expenses............................. *
Trustee's fees and expenses................................. *
Miscellaneous expenses...................................... *
----------
Total............................................. $
==========

---------------

* To be filed by amendment.

ITEM 15. INDEMNIFICATION OF DIRECTORS AND OFFICERS

The Registrant is incorporated under the laws of the State of Delaware.
Section 145 ("Section 145") of Title 8 of the Delaware Code gives a corporation
power to indemnify any person who was or is a party or is threatened to be made
a party to any threatened, pending or completed action, suit or proceeding,
whether civil, criminal, administrative or investigative (other than an action
by or in the right of the corporation) by reason of the fact that the person is
or was a director, officer, employee or agent of the corporation, or is or was
serving at the request of the corporation as a director, officer, employee or
agent of another corporation, partnership, joint venture, trust or other
enterprise, against expenses (including attorneys' fees), judgments, fines and
amounts paid in settlement actually and reasonably incurred by the person in
connection with such action, suit or proceeding if the person acted in good
faith and in a manner the person reasonably believed to be in or not opposed to
the best interests of the corporation, and, with respect to any criminal action
or proceeding, had no reasonable cause to believe the person's conduct was
unlawful.

Section 102 of the General Corporation Law of the State of Delaware allows
a corporation to eliminate the personal liability of directors to a corporation
or its stockholders for monetary damages for a breach of a fiduciary duty as a
director, except where the director breached his duty of loyalty, failed to act
in good faith, engaged in intentional misconduct or knowingly violated a law,
authorized the payment of a dividend or approved a stock repurchase or
redemption in violation of Delaware corporate law or obtained an improper
personal benefit.

Section 145 also gives a corporation power to indemnify any person who was
or is a party or is threatened to be made a party to any threatened, pending or
completed action or suit by or in the right of the corporation to procure a
judgment in its favor by reason of the fact that the person is or was a
director, officer, employee or agent of the corporation, or is or was serving at
the request of the corporation as a director, officer, employee or agent of
another corporation, partnership, joint venture, trust or other enterprise
against expenses (including attorneys' fees) actually and reasonably incurred by
the person in connection with the defense or settlement of such action or suit
if the person acted in good faith and in a manner the person reasonably believed
to be in or not opposed to the best interests of the corporation and except that
no indemnification shall be made in respect of any claim, issue or matter as to
which such person shall have been adjudged to be liable to the corporation
unless and only to the extent that the Delaware Court of Chancery or the court
in which such action or suit was brought shall determine upon

II-1

application that, despite the adjudication of liability but in view of all the
circumstances of the case, such person is fairly and reasonably entitled to
indemnity for such expenses which the Delaware Court of Chancery or such other
court shall deem proper. Section 145 further provides that, to the extent that a
present or former director or officer of a corporation has been successful on
the merits or otherwise in defense of any such action, suit or proceeding, or in
defense of any claim, issue or matter therein, such person shall be indemnified
against expenses (including attorneys' fees) actually and reasonably incurred by
such person in connection therewith.

Section 145 also authorizes a corporation to purchase and maintain
insurance on behalf of any person who is or was a director, officer, employee or
agent of the corporation, or is or was serving at the request of the corporation
as a director, officer, employee or agent of another corporation, partnership,
joint venture, trust or other enterprise, against any liability asserted against
him and incurred by him in any such capacity, arising out of his status as such,
whether or not the corporation would otherwise have the power to indemnify him
under Section 145.

The Registrant's Amended and Restated Bylaws provide for the
indemnification of officers and directors to the fullest extent permitted by the
Delaware General Corporation Law, and the Registrant's Restated Certificate of
Incorporation provides that no director shall be personally liable to us or our
stockholders for monetary damages for breach of fiduciary duty as a director,
except as required by law.

All of the Registrant's directors and officers are covered by insurance
policies maintained by the Registrant against certain liabilities for actions
taken in their capacities as such, including liabilities under the Securities
Act of 1933, as amended.

Any of the agents, dealers or underwriters who execute any of the
agreements filed as Exhibit 1 to this Registration Statement will agree to
indemnify the Registrant's directors and their officers who signed the
Registration Statement against certain liabilities that may arise under the
Securities Act with respect to information furnished to the Registrant by or on
behalf of any such indemnifying party.

See "Item 17. Undertakings" for a description of the SEC's position
regarding such indemnification provisions.

ITEM 16. EXHIBITS

See Index to Exhibits at page II-6.

ITEM 17. UNDERTAKINGS

(a) The undersigned Registrant hereby undertakes:

(1) To file, during any period in which offers or sales are being
made, a post-effective amendment to this registration statement:

(i) To include any prospectus required by Section 10(a)(3) of the
Securities Act of 1933;

(ii) To reflect in the prospectus any facts or events arising after
the effective date of the registration statement (or the most recent
post-effective amendment thereof) which, individually or in the
aggregate, represent a fundamental change in the information set forth
in the registration statement. Notwithstanding the foregoing, any
increase or decrease in volume of securities offered (if the total
dollar value of securities offered would not exceed that which was
registered) and any deviation from the low or high end of the estimated
maximum offering range may be reflected in the form of prospectus filed
with the SEC pursuant to Rule 424(b) if, in the aggregate, the changes
in volume and price represent no more than a 20% change in the maximum
aggregate offering price set forth in the "Calculation of Registration
Fee" table in the effective registration statement;

II-2

(iii) To include any material information with respect to the plan
of distribution not previously disclosed in the registration statement
or any material change to such information in the registration
statement;

provided, however, that paragraphs (a)(1)(i) and (a)(1)(ii) of this section
do not apply if the information required to be included in a post-effective
amendment by those paragraphs is contained in periodic reports filed by the
Registrant pursuant to Section 13 or Section 15(d) of the Securities
Exchange Act of 1934 that are incorporated by reference in the registration
statement.

(2) That, for the purpose of determining any liability under the
Securities Act of 1933, each such post-effective amendment shall be deemed
to be a new registration statement relating to the securities offered
therein, and the offering of such securities at that time shall be deemed
to be the initial bona fide offering thereof.

(3) To remove from registration by means of a post-effective amendment
any of the securities being registered which remain unsold at the
termination of the offering.

(b) The undersigned Registrant hereby undertakes that, for purposes of
determining any liability under the Securities Act of 1933, each filing of the
Registrant's annual report pursuant to Section 13(a) or Section 15(d) of the
Securities Exchange Act of 1934 that is incorporated by reference in the
registration statement shall be deemed to be a new registration statement
relating to the securities offered therein, and the offering of such securities
at that time shall be deemed to be the initial bona fide offering thereof.

(c) Insofar as indemnification for liabilities arising under the Securities
Act of 1933 may be permitted to directors, officers and controlling persons of
the Registrant pursuant to the foregoing provisions, or otherwise, the
Registrant has been advised that in the opinion of the Securities and Exchange
Commission such indemnification is against public policy as expressed in the Act
and is, therefore, unenforceable. In the event that a claim for indemnification
against such liabilities (other than the payment by the Registrant of expenses
incurred or paid by a director, officer or controlling person of the Registrant
in the successful defense of any action, suit or proceeding) is asserted by such
director, officer or controlling person in connection with the securities being
registered, the Registrant will, unless in the opinion of its counsel the matter
has been settled by controlling precedent, submit to a court of appropriate
jurisdiction the question whether such indemnification by it is against public
policy as expressed in the Act and will be governed by the final adjudication of
such issue.

II-3

SIGNATURES

Pursuant to the requirements of the Securities Act of 1933, the Registrant
certifies that it has reasonable grounds to believe that it meets all of the
requirements for filing on Form S-3 and has duly caused this Registration
Statement to be signed on its behalf by the undersigned, thereunto duly
authorized, in the City of Houston, the State of Texas, on July 24, 2003.

RELIANT RESOURCES, INC.
(Registrant)

By: /s/ JOEL V. STAFF
------------------------------------
Name: Joel V. Staff
Title: Chairman and Chief Executive
Officer

POWER OF ATTORNEY

KNOW ALL MEN BY THESE PRESENTS, that each person whose signature appears
below constitutes and appoints Stephen W. Naeve, Mark M. Jacobs, Joel V. Staff
and Michael L. Jines, and each of them severally, his or her true and lawful
attorney or attorneys-in-fact and agents, with full power to act with or without
the others and with full power of substitution and resubstitution, to execute in
his or her name, place and stead, in any and all capacities, any or all
amendments (including pre-effective and post-effective amendments) to this
Registration Statement and any registration statement for the same offering
filed pursuant to Rule 462 under the Securities Act of 1933, as amended, and to
file the same, with all exhibits thereto, and other documents in connection
therewith, with the Securities and Exchange Commission, granting unto said
attorneys-in-fact and agents and each of them full power and authority, to do
and perform in the name and on behalf of the undersigned, in any and all
capacities, each and every act and thing necessary or desirable to be done in
and about the premises, to all intents and purposes and as fully as they might
or could do in person, hereby ratifying and confirming all that said
attorneys-in-fact and agents or their substitutes may lawfully do or cause to be
done by virtue hereof.

Pursuant to the requirements of the Securities Act of 1933, this
Registration Statement has been signed by the following persons in the
capacities and on the dates indicated.

SIGNATURE TITLE DATE
--------- ----- ----

/s/ JOEL V. STAFF Chairman and Chief Executive July 24, 2003
-------------------------------------------------- Officer (Principal Executive
Joel V. Staff Officer)

/s/ MARK M. JACOBS Executive Vice President and July 24, 2003
-------------------------------------------------- Chief Financial Officer
Mark M. Jacobs (Principal Financial Officer)

/s/ THOMAS C. LIVENGOOD Vice President and Controller July 24, 2003
-------------------------------------------------- (Principal Accounting Officer)
Thomas C. Livengood

/s/ E. WILLIAM BARNETT Director July 24, 2003
--------------------------------------------------
E. William Barnett

/s/ DONALD J. BREEDING Director July 24, 2003
--------------------------------------------------
Donald J. Breeding

II-4

SIGNATURE TITLE DATE
--------- ----- ----

/s/ LAREE E. PEREZ Director July 24, 2003
--------------------------------------------------
Laree E. Perez

/s/ WILLIAM L. TRANSIER Director July 24, 2003
--------------------------------------------------
William L. Transier

II-5

INDEX TO EXHIBITS

SEC FILE
OR
EXHIBIT REPORT OR REGISTRATION EXHIBIT
NUMBER DOCUMENT DESCRIPTION REGISTRATION STATEMENT NUMBER REFERENCE
------- -------------------- ---------------------- ------------ ---------

4.1 Restated Certificate of Incorporation Registration Statement 333-48038 3.1
on Form S-1
4.2 Amended and Restated Bylaws Quarterly Report on 1-16455 3
Form 10-Q for the
Quarterly Period Ended
March 31, 2001
4.3 Specimen Stock Certificate Registration Statement 333-48038 4.1
on Form S-1, dated
October 16, 2000
4.4 Rights Agreement effective as of January 15, Amendment No. 4 to 333-48038 4.2
2001 between Reliant Resources, Inc. and The Registration Statement
Chase Manhattan Bank, as Rights Agent, on Form S-1, dated
including a form of Rights Certificate January 18, 2001
*4.5 Indenture, dated as of June 24, 2003, between
Reliant Resources, Inc. and Wilmington Trust
Company, as Trustee
*4.6 Form of 5.00% Convertible Senior Subordinated
Notes due 2010 (included in Exhibit 4.5)
*4.7 Registration Rights Agreement dated as of June
24, 2003 among Reliant Resources, Inc,
Deutsche Bank Securities Inc., Goldman, Sachs
& Co. and Banc of America Securities LLC
**5 Opinion of Skadden, Arps, Slate, Meagher &
Flom LLP.
*12 Ratio of Earnings to Fixed Charges
*23.1 Consent of Deloitte & Touche LLP
**23.2 Consent of Skadden, Arps, Slate, Meagher &
Flom LLP (included in Exhibit 5)
*24 Power of Attorney (included on page II-4 of
this Registration Statement)
*25.1 Form T-1 Statement of Eligibility and
Qualification under the Trust Indenture Act of
1939, under the Indenture

---------------

* Filed herewith.

** To be filed by amendment or in a Current Report on Form 8-K.

II-6