RELIANT RESOURCES INC - 10-Q Quarterly Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q

(Mark One)
[ X ] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.

FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934.

For the transition period from ______________ to _______________

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Commission file number 1-16455

RELIANT RESOURCES, INC.
(Exact Name of Registrant as Specified in its Charter)

Delaware 76-0655566
(State or other jurisdiction of incorporation or (I.R.S. Employer
organization) Identification No.)

1111 Louisiana
Houston, Texas 77002
(Address of principal executive offices) (Zip Code)

(713) 497-3000
(Registrant's Telephone Number, Including Area Code)

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Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes X No
----- -----.

Indicate by check mark whether the registrant is an accelerated filer (as
defined in Rule 125-2 of the Exchange Act). Yes X No
----- ----- .

As of May 13, 2003, Reliant Resources, Inc. (Reliant Resources) had 292,294,141
shares of common stock outstanding, excluding 7,509,859 shares held by the
Registrant as treasury stock.

RELIANT RESOURCES, INC. AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Statements of Consolidated Operations (unaudited)
Three Months Ended March 31, 2002 (as restated) and 2003................................................. 1

Consolidated Balance Sheets (unaudited)
December 31, 2002 and March 31, 2003 .................................................................... 2

Statements of Consolidated Cash Flows (unaudited)
Three Months Ended March 31, 2002 (as restated) and 2003................................................. 3

Notes to Unaudited Consolidated Interim Financial Statements............................................. 4

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.................. 42

Item 3. Quantitative and Qualitative Disclosures About Market Risk............................................. 71

Item 4. Controls and Procedures................................................................................. 74

PART II. OTHER INFORMATION

Item 1. Legal Proceedings...................................................................................... 75

Item 2. Changes in Securities and Use of Proceeds.............................................................. 75

Item 5. Exhibits and Reports on Form 8-K....................................................................... 75

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

This Form 10-Q 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," "forecasts," "goal,"
"intends," "may," "objective," "plans," "potential," "predicts," "projection,"
"should," "will" and similar words.

We have based our forward-looking statements on management's beliefs
and assumptions based on information available at the time the statements are
made. We caution you that assumptions, beliefs, expectations, intentions and
projections about future events and performance may and often do vary materially
from actual results. Therefore, actual results may differ materially from those
expressed or implied by our forward-looking statements. For more information
regarding the risks and uncertainties that could cause our actual results to
differ materially from those expressed or implied in our forward-looking
statements, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations" in Item 2 of this Form 10-Q and "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Risk Factors" in
Item 7 of our Form 10-K/A, which are incorporated herein by this reference.

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PART I.
FINANCIAL INFORMATION

RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED OPERATIONS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

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RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

2

RELIANT RESOURCES, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to our Unaudited Consolidated Interim Financial Statements

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

In this Quarterly Report on Form 10-Q (Form 10-Q), "Reliant Resources"
refers to Reliant Resources, Inc. (Reliant Resources), and "we", "us" and "our"
refer to Reliant Resources, Inc. and its subsidiaries, unless we specify or the
context indicates otherwise. Included in this Form 10-Q are our interim
consolidated financial statements and notes (interim financial statements). The
interim financial statements are unaudited, omit certain financial statement
disclosures and should be read with the annual report on Form 10-K/A of Reliant
Resources for the year ended December 31, 2002 filed on May 1, 2003 (Form
10-K/A).

Reliant Energy, Incorporated (Reliant Energy) adopted a business
separation plan in response to the Texas Electric Choice Plan (Texas electric
restructuring law) adopted by the Texas legislature in June 1999. The Texas
electric restructuring law substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail electric
competition with respect to all customer classes beginning in January 2002.
Under its business separation plan filed with the Public Utility Commission of
Texas (PUCT), Reliant Energy transferred substantially all of its unregulated
businesses to Reliant Resources in order to separate its regulated and
unregulated operations. In accordance with the plan, in May 2001, Reliant
Resources offered 59.8 million shares of its common stock to the public at an
initial offering price of $30 per share (IPO) and received net proceeds from the
IPO of $1.7 billion. For additional information regarding the IPO, see notes 3
and 10(a) to our Form 10-K/A.

CenterPoint Energy, Inc. was formed on August 31, 2002 as the new
holding company of Reliant Energy. We refer to CenterPoint Energy, Inc. and its
predecessor company, Reliant Energy, as "CenterPoint." Unless clearly indicated
otherwise these references to "CenterPoint" mean CenterPoint Energy, Inc. on or
after August 31, 2002 and Reliant Energy prior to August 31, 2002. CenterPoint
is a diversified international energy services and energy delivery company that
owned the majority of Reliant Resources outstanding common stock prior to
September 30, 2002. On September 30, 2002, CenterPoint distributed all of the
240 million shares of our common stock it owned to its common shareholders of
record as of the close of business on September 20, 2002 (Distribution). The
Distribution completed the separation of Reliant Resources and CenterPoint into
two separate publicly held companies.

RESTATEMENT

Subsequent to the issuance of our financial statements for the first
three quarters of 2002, we determined that we had incorrectly calculated the
amount of hedge ineffectiveness for 2001 and the first three quarters of 2002
for hedging instruments entered into prior to the adoption of the Financial
Accounting Standards Board (FASB) Statement of Financial Accounting Standards
(SFAS) No. 133, "Accounting for Derivative Instruments and Hedging Activities,"
as amended (SFAS No. 133). These hedging instruments included long-term forward
contracts for the sale of power in the California market through December 2006.
The amount of hedge ineffectiveness for these forward contracts was calculated
using the trade date. However, the proper date for the hedge ineffectiveness
calculation is hedge inception, which for these contracts was deemed to be
January 1, 2001, concurrent with the adoption of SFAS No. 133. This restatement
in accounting for hedge ineffectiveness resulted in a reduction of revenues of
$1.1 million ($0.7 million after-tax) for the three months ended March 31, 2002.

The statements of consolidated operations and cash flows for the three
months ended March 31, 2002 have been restated from amounts previously reported
to correctly account for the amount of hedge ineffectiveness in the first
quarter of 2002. The restatement had no impact on previously reported
consolidated total operating, investing and financing cash flows for the three
months ended March 31, 2002. The following is a summary of the principal effects
of the restatement and the revisions for changes in accounting principles and
discontinued operations for the three months ended March 31, 2002: (Note - Those
line items for which no change in amounts are shown were not affected by the
restatement.)

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(1) Beginning with the quarter ended September 30, 2002, we now report all
energy trading and marketing activities on a net basis as allowed by
Emerging Issues Task Force (EITF) Issue No. 98-10, "Accounting for
Contracts involved in Energy Trading and Risk Management Activities"
(EITF No. 98-10). Comparative financial statements for prior periods
have been reclassified to conform to this presentation. For information
regarding the presentation of trading and marketing activities on a net
basis, see note 2. Revenues, fuel and cost of gas sold expense and
purchased power expense have been reclassified to conform to this
presentation.

(2) In February 2003, we signed an agreement to sell our European energy
operations to n.v. Nuon (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, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144). Comparative financial
statements for prior periods have been reclassified to conform to this
presentation.

(3) During the third quarter of 2002, we completed the transitional
impairment test for the adoption of SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS No. 142) on our interim financial statements,
including the review of goodwill for impairment as of January 1, 2002
(see note 7). Based on this impairment test, we recorded an impairment
of our European energy segment's goodwill of $234 million, net of tax.
This impairment loss was recorded retroactively as a cumulative effect
of a change in accounting principle for the quarter ended March 31,
2002.

(4) Some amounts from the previous period have been reclassified to conform
to the presentation of our statement of consolidated operations for the
three months ended March 31, 2003. These reclassifications do not
affect operating income or net income.

BASIS OF PRESENTATION

The preparation of financial statements in conformity with accounting
principles generally accepted in the United States of America (GAAP) requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, disclosure of contingent assets and liabilities at the
date of the financial statements and the reported amounts of revenues and
expenses during the reporting period. Actual results could differ from those
estimates.

The interim financial statements reflect all normal recurring
adjustments that are, in the opinion of management, necessary to present fairly
the financial position and results of operations for the respective periods.
Amounts reported in the statements of consolidated operations are not
necessarily indicative of amounts expected for a full year period due to the
effects of, among other things, (a) seasonal fluctuation in demand for energy
and energy
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services, (b) changes in energy commodity prices, (c) timing of maintenance and
other expenditures, (d) acquisitions and dispositions of businesses, assets and
other interests and (e) changes in interest expense. In addition, some amounts
from the prior period have been reclassified to conform to the 2003 presentation
of financial statements. These reclassifications do not affect earnings.

The statements of consolidated operations include all revenues and
costs directly attributable to us, including costs for facilities and costs for
functions and services performed by centralized CenterPoint organizations and
directly charged to us based on usage or other allocation factors prior to the
Distribution. The results of operations for the three months ended March 31,
2002, in these interim financial statements also include general corporate
expenses allocated by CenterPoint to us prior to the Distribution. All of the
allocations in the interim financial statements are based on assumptions that
management believes are reasonable under the circumstances. However, these
allocations may not necessarily be indicative of the costs and expenses that
would have resulted if we had operated as a separate entity prior to the
Distribution.

Our financial reporting segments include the following: retail energy,
wholesale energy, European energy and other operations. The retail energy
segment includes our retail electric operations and associated supply
activities. This segment provides customized, integrated energy services to
large commercial, industrial and institutional customers and standardized
electricity and related services to residential and small commercial customers
in Texas. In addition, the retail energy segment includes our Electric
Reliability Council of Texas (ERCOT) generation facilities. The wholesale energy
segment engages in the acquisition, development and operation of domestic
non-rate regulated electric power generation facilities as well as wholesale
energy trading, marketing, power origination and risk management activities
related to energy and energy-related commodities in North America. The European
energy segment operates power generation facilities in the Netherlands and
conducts wholesale energy trading and origination activities in Europe; see note
16 regarding the sale of our European energy operations and the classification
as discontinued operations. The other operations segment primarily includes
unallocated general corporate expenses and non-operating investments.

Each of Orion Power New York, LP (Orion NY), Orion Power New York LP,
LLC, Orion Power New York GP, Inc., Astoria Generating Company, L.P., Carr
Street Generating Station, LP, Erie Boulevard Hydropower, LP, Orion Power
MidWest, LP (Orion MidWest), Orion Power Midwest LP, LLC, Orion Power Midwest
GP, Inc., Twelvepole Creek, LLC and Orion Power Capital, LLC (Orion Capital) is
a separate legal entity and has its own assets.

(2) NEW ACCOUNTING PRONOUNCEMENTS

SFAS No. 142. See note 7 for a discussion regarding our adoption of
SFAS No. 142 on January 1, 2002.

SFAS No. 143. In August 2001, the FASB issued SFAS No. 143, "Accounting
for Asset Retirement Obligations" (SFAS No. 143). On January 1, 2003, we adopted
the provisions of this statement. SFAS No. 143 requires the fair value of a
liability for an asset retirement legal obligation to be recognized in the
period in which it is incurred. When the liability is initially recorded,
associated costs are capitalized by increasing the carrying amount of the
related long-lived asset. Over time, the liability is accreted to its present
value each period, and the capitalized cost is depreciated over the useful life
of the related asset. SFAS No. 143 requires entities to record a cumulative
effect of a change in accounting principle in the statement of operations in the
period of adoption. Prior to the adoption of SFAS No. 143, we recorded asset
retirement obligations in connection with certain business combinations. These
obligations were recorded at their undiscounted estimated fair values on the
dates of acquisition. Our asset retirement obligations primarily relate to the
future dismantling of power plants and auxiliary equipment at our European
energy operations. We also have asset retirement obligations related primarily
to future dismantlement of power plants on leased property and environmental
obligations related to ash disposal site closures in our wholesale energy
segment. The impact of the adoption of SFAS No. 143 resulted in a gain of $19
million, net of tax of $10 million, or $0.06 per share, as a cumulative effect
of an accounting change in our statement of consolidated operations for the
three months ended March 31, 2003. Included in the gain is $16 million, net of
tax of $8 million, related to our European energy operations, which are now
reported as discontinued operations.

The adoption of SFAS No. 143 for our continuing operations resulted in
a January 1, 2003 cumulative effect of an accounting change to record (a) a $6
million increase in the carrying values of property, plant and equipment, (b) a
$1 million increase in accumulated depreciation of property, plant and
equipment, (c) a $1 million decrease in asset retirement obligations and (d) a
$3 million increase in deferred income tax liabilities. The net impact of these
items was to record a gain of $3 million, net of tax, as a cumulative effect of
an accounting change in our results of continuing operations upon adoption on
January 1, 2003.

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The following unaudited pro forma financial information has been
prepared to give effect to the adoption of SFAS No. 143 as if it had been
applied in 2002:

The following table presents the detail of our asset retirement
obligations for continuing operations, which are included in other long-term
liabilities in our consolidated balance sheet (in millions):

SFAS No. 144. In August 2001, the FASB issued SFAS No. 144. SFAS No.
144 provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets and for
Long-Lived Assets to Be Disposed Of," and Accounting Principles Board Opinion
No. 30, "Reporting the Results of Operations - Reporting the Effects of Disposal
of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," while retaining many of the requirements of
these two statements. Under SFAS No. 144, assets held for sale that are a
component of an entity will be included in discontinued operations if the
operations and cash flows will be or have been eliminated from the ongoing
operations of the entity and the entity will not have any significant continuing
involvement in the operations prospectively. SFAS No. 144 did not materially
change the methods used by us to measure impairment losses on long-lived assets.
We adopted SFAS No. 144 on January 1, 2002. In accordance with SFAS No. 144, our
European energy operations are being reflected as discontinued operations (see
note 16).

SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission
of FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the

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statement of operations. Instead, such gains and losses will be classified as
extraordinary items only if they are deemed to be unusual and infrequent. SFAS
No. 145 also requires sale-leaseback accounting for certain lease modifications
that have economic effects that are similar to sale-leaseback transactions. The
changes related to debt extinguishment will be effective for fiscal years
beginning after May 15, 2002, and the changes related to lease accounting are
effective for transactions occurring after May 15, 2002. We began to apply the
guidance related to debt extinguishments effective January 1, 2003.

SFAS No. 148. In December 2002, the FASB issued SFAS No. 148,
"Accounting for Stock-Based Compensation - Transition and Disclosure, an
amendment to SFAS No. 123" (SFAS No. 148). This statement provides alternative
methods of transition for a company that voluntarily changes to the fair value
method of accounting for stock-based employee compensation. SFAS No. 148 also
amends disclosure requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation," (SFAS No. 123), to require prominent disclosure in both annual
and interim financial statements about the method of accounting for stock-based
employee compensation and the effect of the method used on reported results.
SFAS No. 148 is effective for annual financial statements for fiscal years
ending after December 15, 2002 and condensed financial statements for interim
periods beginning after December 15, 2002. In addition, on April 22, 2003, the
FASB decided to require all companies to expense the fair value of employee
stock options. The FASB is still evaluating how to measure "fair value" and
other items. The FASB plans to issue an exposure draft in late 2003 that would
become effective in 2004. We have decided not to change to the fair value method
of accounting for stock-based employee compensation in 2003. We have adopted the
disclosure requirements of SFAS No. 148 for our interim financial statements for
2003.

We apply the intrinsic method of accounting for employee stock-based
compensation plans in accordance with Accounting Principles Board Opinion No.
25, "Accounting for Stock Issued to Employees" (APB No. 25). Under the intrinsic
value method, no compensation expense is recorded when options are issued with
an exercise price equal to the market price of the underlying stock on the date
of grant. Since our stock options have all been granted at market value or the
exercise price is greater than the market value at date of grant, no
compensation expense has been recognized under APB No. 25. We comply with the
disclosure requirements of SFAS No. 123 and SFAS No. 148 and disclose the pro
forma effect on net income (loss) and per share amounts as if the fair value
method of accounting had been applied to all stock awards. Had compensation
costs been determined as prescribed by SFAS No. 123, our net loss and per share
amounts would have approximated the following pro forma results for the three
months ended March 31, 2002 and 2003, which take into account the amortization
of stock-based compensation, including performance shares, purchases under the
employee stock purchase plan and stock options, to expense on a straight-line
basis over the vesting periods:

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For further information regarding our stock-based compensation plans
and our assumptions used to compute pro forma amounts, see note 12 to our Form
10-K/A.

SFAS No. 149. In April 2003, the FASB issued SFAS No. 149 "Amendment of
Statement 133 on Derivative Instruments and Hedging Activities" (SFAS No. 149).
SFAS No. 149 clarifies when a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133 and when a
derivative contains a financing component. SFAS No. 149 also amends certain
existing pronouncements, which will result in more consistent reporting of
contracts as either derivative or hybrid instruments. SFAS No. 149 is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003 and should be applied
prospectively. Certain paragraphs of this statement that relate to forward
purchases or sales of when-issued securities or other securities that do not yet
exist, should be applied to both existing contracts and new contracts entered
into after June 30, 2003. The provisions of this statement that relate to SFAS
No. 133 implementation issues that have been effective for fiscal quarters that
began prior to June 15, 2003, should continue to be applied in accordance with
their respective effective dates. We are currently assessing the impact that
this statement will have on our consolidated financial statements.

FIN No. 45. In November 2002, the FASB issued FASB Interpretation No.
45, "Guarantor's Accounting and Disclosure Requirements for Guarantees,
Including Direct Guarantees of Indebtedness of Others," (FIN No. 45) which
increases the disclosure requirements for a guarantor in its interim and annual
financial statements about its obligations under certain guarantees that it has
issued. It clarifies that a guarantor's required disclosures include the nature
of the guarantee, the maximum potential undiscounted payments that could be
required, the current carrying amount of the liability, if any, for the
guarantor's obligations (including the liability recognized under SFAS No. 5,
"Accounting for Contingencies"), and the nature of any recourse provisions or
available collateral that would enable the guarantor to recover amounts paid
under the guarantee. It also requires a guarantor to recognize, at the inception
of a guarantee issued after December 31, 2002, a liability for the fair value of
the obligation undertaken in issuing the guarantee, including its ongoing
obligation to stand ready to perform over the term of the guarantee in the event
that specified triggering events or conditions occur. We adopted the reporting
requirements of FIN No. 45 on January 1, 2003. The adoption of FIN No. 45 will
have no impact to our historical interim financial statements, as existing
guarantees are not subject to the measurement provisions. The adoption of FIN
No. 45 did not have a material impact on our consolidated financial position or
results of operations for the three months ended March 31, 2003.

FIN No. 46. In January 2003, the FASB issued FASB Interpretation No. 46
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51"
(FIN No. 46). The objective of FIN No. 46 is to achieve more consistent
application of consolidation policies to variable interest entities and to
improve comparability between enterprises engaged in similar activities. FIN No.
46 states that an enterprise must consolidate a variable interest entity if the
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receives a majority of the entity's expected
residual returns if they occur, or both. If one enterprise absorbs a majority of
a variable interest entity's expected losses and another enterprise receives a
majority of that entity's expected residual returns, the enterprise absorbing a
majority of the losses shall consolidate the variable interest entity and will
be called the primary beneficiary. FIN No. 46 is effective immediately to
variable interest entities created after January 31, 2003, and to variable
interest entities in which an enterprise obtains an interest after that date.
For enterprises that acquired variable interests prior to February 1, 2003, the
effective date is for fiscal years or interim periods beginning after June 15,
2003. FIN No. 46 requires entities to either (a) record the effects
prospectively with a

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cumulative effect adjustment as of the date on which FIN No. 46 is first applied
or (b) restate previously issued financial statements for the years with a
cumulative effect adjustment as of the beginning of the first year being
restated. We adopted FIN No. 46 on January 1, 2003. Results for the three months
ended March 31, 2003, include the cumulative effect of accounting change of $1
million loss, net of tax, effective January 1, 2003 related to the adoption of
FIN No. 46. See note 13(a).

We had variable interests in three power generation projects that were
being constructed by off-balance sheet special purpose entities under
construction agency agreements as of December 31, 2002, which pursuant to this
guidance would require consolidation upon adoption. As of January 1, 2003, these
special purpose entities had property, plant and equipment of $1.3 billion, net
other assets of $3 million and secured debt obligations of $1.3 billion. These
special purpose entities' financing agreement, the construction agency
agreements and the related guarantees were terminated as part of the refinancing
in March 2003. For information regarding these special purpose entities and the
refinancing, see note 10.

EITF No. 02-03. In June 2002, the EITF had its initial meeting
regarding EITF No. 02-03 and reached a consensus that all mark-to-market gains
and losses on energy trading contracts should be shown net in the statement of
operations whether or not settled physically. In October 2002, the EITF issued a
consensus that superceded the June 2002 consensus. The October 2002 consensus
required, among other things, that energy derivatives held for trading purposes
be shown net in the statement of operations. This new consensus is effective for
fiscal periods beginning after December 15, 2002. However, consistent with the
new consensus and as allowed under EITF No. 98-10, beginning with the quarter
ended September 30, 2002, we now report all energy trading and marketing
activities on a net basis in the statements of consolidated operations.
Comparative financial statements for prior periods have been reclassified to
conform to this presentation.

The adoption of net reporting resulted in reclassifications of
revenues, fuel and cost of gas sold, purchased power expense for the three
months ended March 31, 2002 as follows:

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(1) Some amounts from the previous period have been reclassified to conform
to the presentation of our statement of consolidated operations for the
three months ended March 31, 2003. These reclassifications do not
affect operating income or net income.

Furthermore, in October 2002, under EITF No. 02-03, the EITF reached a
consensus to rescind EITF No. 98-10. All new contracts that would have been
accounted for under EITF No. 98-10, and that do not fall within the scope of
SFAS No. 133 should no longer be marked-to-market through earnings beginning
October 25, 2002. In addition, mark-to-market accounting is no longer applied to
inventories used in the trading and marketing operations. This transition is
effective for us for the first quarter of 2003. We recorded a cumulative effect
of a change in accounting principle of $43 million loss, net of tax of $22
million, or $(0.15) per share, effective January 1, 2003, related to EITF No.
02-03. This cumulative effect reflects the fair value, as of January 1, 2003, of
certain contracts that had been marked to market under EITF No. 98-10 and do not
meet the definition of a derivative under SFAS No. 133. Additionally, beginning
in January 2003, we began applying the "normal" purchase and sale exception of
SFAS No. 133 to our retail large commercial, industrial and institutional sales
contracts that had previously been recorded under mark-to-market accounting
under EITF No. 98-10. Under the "normal" purchase and sale exception, we utilize
accrual accounting for these contracts because they represent physical power
sales in the normal course of business.

Prior to 2003, our retail energy segment's contracted electricity sales
to large commercial, industrial and institutional customers and the related
energy supply contracts for contracts entered into prior to October 25, 2002

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were accounted for under the mark-to-market method of accounting pursuant to
EITF No. 98-10. Under the mark-to-market method of accounting, these contractual
commitments were recorded at fair value in revenues on a net basis upon contract
execution. The net changes in their fair values were recognized in the
statements of consolidated operations as revenues on a net basis in the period
of change through 2002. Effective January 1, 2003, we no longer mark to market
in earnings these electricity sales contracts and a substantial portion of the
related energy supply contracts in connection with the implementation of EITF
No. 02-03. The related revenues and purchased power are now recorded on a gross
basis in our results of operations. Due to the implementation of EITF No. 02-03,
the results of operations related to our contracted electricity sales to large
commercial, industrial and institutional customers and the related energy supply
contracts for contracts entered into prior to October 25, 2002 are not
comparable between the three months ended March 31, 2002 and 2003. During the
three months ended March 31, 2002, our retail energy segment recognized $2
million of losses related to its contracted electricity sales to large
commercial, industrial and institutional customers and the related energy supply
contracts. During the three months ended March 31, 2003, volumes were delivered
under contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts for which $20
million was previously recognized as unrealized earnings in prior periods. As of
March 31, 2003, our retail energy segment has unrealized gains that have been
previously recorded in our results of operations of $83 million that will be
realized when the electricity is delivered to our customers ($54 million in the
remainder of 2003 and $29 million in 2004 and beyond). These unrealized gains of
$83 million are recorded in non-trading derivative assets/liabilities in our
consolidated balance sheet as of March 31, 2003.

The EITF has not reached a consensus on whether recognition of dealer
profit or unrealized gains and losses at inception of an energy trading contract
is appropriate in the absence of quoted market prices or current market
transactions for contracts with similar terms. In the June 2002 EITF meeting and
again in the October 2002 EITF meeting, the FASB staff indicated that until such
time as a consensus is reached, the FASB staff will continue to hold the view
that previous EITF consensuses do not allow for recognition of dealer profit,
unless evidenced by quoted market prices or other current market transactions
for energy trading contracts with similar terms and counterparties. During the
three months ended March 31, 2002, we recorded $20 million of fair value at the
contract inception related to trading and marketing activities. For the three
months ended March 31, 2003, we did not recognize any gains at inception.
Inception gains recorded were evidenced by quoted market prices and other
current market transactions for energy trading contracts with similar terms and
counterparties.

(3) HISTORICAL RELATED PARTY TRANSACTIONS

The interim financial statements include significant transactions
between CenterPoint and us. Some of these transactions involve services,
including various corporate support services (including accounting, finance,
investor relations, planning, legal, communications, governmental and regulatory
affairs and human resources), information technology services and other shared
services such as corporate security, facilities management, accounts receivable,
accounts payable and payroll, office support services and purchasing and
logistics. The costs of services have been directly charged or allocated to us
using methods that management believes are reasonable. These methods include
negotiated usage rates, dedicated asset assignment, and proportionate corporate
formulas based on assets, operating expenses and employees. These charges and
allocations are not necessarily indicative of what would have been incurred had
we been an unaffiliated entity. Amounts charged and allocated to us for these
services for the three months ended March 31, 2002, were $5 million and are
included primarily in operation and maintenance expenses and general and
administrative expenses. Some of our subsidiaries have entered into office
rental agreements with CenterPoint. During the three months ended March 31,
2002, we incurred $8 million of rent expense to CenterPoint. Net interest income
related to various net receivables representing transactions between us and
CenterPoint or its subsidiaries was $3 million during the three months ended
March 31, 2002.

We purchased natural gas, natural gas transportation services, electric
generation energy and capacity, and electric transmission services from,
supplied natural gas to, and provided marketing and risk management services to
affiliates of CenterPoint. Purchases and sales related to our trading and
marketing activities are recorded net in trading margins in the statements of
consolidated operations. Purchases of electric generation energy and capacity
and electric transmission services from CenterPoint and its subsidiaries were
$366 million for the three months ended March 31, 2002. During the three months
ended March 31, 2002, the net purchases and sales and services from/to
CenterPoint and its subsidiaries related to our trading and marketing operations
totaled $71 million. In addition, during the three months ended March 31, 2002,
other sales and services to CenterPoint and its subsidiaries totaled $1 million.
Sales and purchases to/from CenterPoint subsequent to the Distribution are not
reported as affiliated transactions.

11

During the three months ended March 31, 2002 and 2003, we purchased
entitlements to some of the generation capacity of electric generation assets of
Texas Genco, LP, which is a wholly-owned subsidiary of Texas Genco Holdings,
Inc. (Texas Genco), a majority-owned subsidiary of CenterPoint. We purchased
these entitlements in capacity auctions conducted by Texas Genco and pursuant to
rights granted to us under the Master Separation Agreement, see note 4(b) to our
Form 10-K/A. As of March 31, 2003, we had purchased entitlements to capacity of
Texas Genco averaging 6,567 megawatts (MW) per month in 2003. Our anticipated
capacity payments related to these capacity entitlements are $341 million for
the remainder of 2003. For additional information regarding agreements relating
to Texas Genco, see note 4(b) to our Form 10-K/A.

During the three months ended March 31, 2002 and 2003, CenterPoint made
equity contributions to us of $0 and $47 million, respectively. The
contributions in 2003 primarily related to the non-cash conversion to equity of
accounts payable to CenterPoint.

(4) AGREEMENTS RELATING TO TEXAS GENCO

Texas Genco owns the Texas generating assets formerly held by
CenterPoint's electric utility division. Texas Genco, as the affiliated power
generator of CenterPoint, is required by law to sell at auction 15% of the
output of its installed generating capacity. These auction obligations will
continue until January 2007, unless at least 40% of the electricity consumed by
residential and small commercial customers in CenterPoint's service territory is
being served by retail electric providers other than us. Texas Genco has agreed
to auction all of its capacity that remains subsequent to the capacity auctions
mandated under PUCT rules and after certain other adjustments. We have the right
to purchase 50% (but not less than 50%) of such remaining capacity at the prices
established in such auctions. We also have the right to participate directly in
such auctions. Texas Genco's obligation to auction its capacity and our
associated rights terminate (a) if we do not exercise our option to acquire
CenterPoint's ownership interest in Texas Genco by January 24, 2004 or (b) if we
exercise our option to acquire CenterPoint's ownership interest in Texas Genco,
on (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.

On October 1, 2002, we entered into a master power purchase contract
with Texas Genco covering, among other things, our purchases of capacity and/or
energy from Texas Genco's generating units, under an unsecured line of credit.
This contract was amended in connection with our March 2003 refinancing. This
amendment grants Texas Genco a security interest in the accounts receivable and
related assets of certain of our 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 January 2003, CenterPoint distributed approximately 19% of the
common stock of Texas Genco. CenterPoint has granted us an option to purchase
all of the remaining shares of common stock of Texas Genco held by CenterPoint.
Subject to the exercise price of the option, market conditions, available
financing and our due diligence investigation of Texas Genco, we may elect to
exercise the Texas Genco option between January 10, 2004 and January 24, 2004.
The per share exercise price under the option will be set as the average daily
closing price on the national exchange for publicly held shares of common stock
of Texas Genco for the 30 consecutive trading days with the highest average
closing price during the 120 trading days immediately preceding January 9, 2004,
plus a control premium, up to a maximum of 10%, to the extent a control premium
is included in the valuation determination made by the PUCT. The exercise price
is also subject to adjustment based on the difference between the per share
dividends paid during the period there is a public ownership interest in Texas
Genco and Texas Genco's per share earnings during that period. We have agreed
that if we exercise the Texas Genco option, we will also purchase all notes and
other receivables from Texas Genco then held by CenterPoint, at their principal
amount, plus accrued interest. Similarly, if Texas Genco holds notes or
receivables from CenterPoint, we will assume CenterPoint's obligations in
exchange for a payment to us by CenterPoint of an amount equal to the principal,
plus accrued interest.

We have entered into a support agreement with CenterPoint, pursuant to
which we provide engineering and technical support services and environmental,
safety and industrial health services to support operations and maintenance of
Texas Genco's facilities. We also provide systems, technical, programming and
consulting support services and hardware maintenance (but excluding
plant-specific hardware) necessary to provide dispatch planning, dispatch and
settlement and communication with the independent system operator. The fees we
charge for these

12

services are designed to allow us to recover our fully allocated direct and
indirect costs and reimbursement of out-of-pocket expenses. Expenses associated
with capital investment in systems and software that benefit both the operation
of Texas Genco's facilities and our facilities in other regions are allocated on
an installed MW basis. The term of this agreement will end on the first to occur
of (a) the closing date of our acquisition of Texas Genco under the option, (b)
CenterPoint's sale of Texas Genco, or all or substantially all of the assets of
Texas Genco, if we do not exercise the Texas Genco option, or (c) May 31, 2005
if we do not exercise the option; however, Texas Genco may extend the term of
this agreement until December 31, 2005.

(5) COMPREHENSIVE INCOME (LOSS)

The following table summarizes the components of total comprehensive
income (loss):

(6) BUSINESS ACQUISITIONS

In February 2002, we acquired all of the outstanding shares of common
stock of Orion Power Holdings, Inc. (Orion Power) for an aggregate purchase
price of $2.9 billion and assumed debt obligations of $2.4 billion. We funded
the Orion Power acquisition with a $2.9 billion credit facility (see note 10)
and $41 million of cash on hand. As a result of the acquisition, our
consolidated debt obligations also increased by the amount of Orion Power's debt
obligations. As of February 19, 2002, Orion Power's debt obligations were $2.4
billion ($2.1 billion net of restricted cash pursuant to debt covenants). Orion
Power is an electric power generating company with a diversified portfolio of
generating assets, both geographically across the states of New York,
Pennsylvania, Ohio and West Virginia, and by fuel type, including gas, oil, coal
and hydro. The primary reason for the acquisition was to enhance our then
current domestic power generation position by combining our domestic generation
capacity and Orion Power's domestic generation capacity. The Orion Power
acquisition expanded our market presence into the New York and East Central Area
Reliability Coordinating Counsel power markets. As of February 19, 2002, Orion
Power had 81 generating facilities with a total generating capacity of 5,644 MW
and two development projects with an additional 804 MW of capacity under
construction. As of March 31, 2003, both projects under construction had reached
commercial operation.

We accounted for the acquisition as a purchase with assets and
liabilities of Orion Power reflected at their estimated fair values. Our fair
value adjustments primarily included adjustments in property, plant and
equipment, contracts, severance liabilities, debt, unrecognized pension and
postretirement benefits liabilities and related deferred taxes. We finalized
these fair value adjustments in February 2003, based on final valuations of
property, plant and equipment, intangible assets and other assets and
obligations.

The following factors contributed to the recognized goodwill of $1.3
billion: commercialization value attributable to our marketing and trading
capabilities, commercialization and synergy value associated with fuel
procurement in conjunction with existing generating plants in the region, entry
into the New York power market, general and administrative cost synergies with
existing Pennsylvania-New Jersey-Maryland power market generating assets and
headquarters, and risk diversification value due to increased scale, fuel supply
mix and the nature of the acquired assets. Of the resulting goodwill, all but
$105 million is not deductible for United States income tax purposes. The $1.3
billion of goodwill was assigned to the wholesale energy segment.

Our results of operations include the results of Orion Power for the
period beginning February 19, 2002. The following table presents selected
financial information and unaudited pro forma information for the three months
ended March 31, 2002, as if the acquisition had occurred on January 1, 2002.

13

These unaudited pro forma results, based on assumptions we deem
appropriate, have been prepared for informational purposes only and are not
necessarily indicative of the amounts that would have resulted if the
acquisition of Orion Power had occurred on January 1, 2002. Purchase-related
adjustments to the results of operations include the effects on revenues, fuel
expense, depreciation and amortization, interest expense, interest income and
income taxes. Adjustments that affected revenues and fuel expense were a result
of the amortization of contractual rights and obligations relating to the
applicable power and fuel contracts that were in existence at January 1, 2002,
as applicable. Such amortization included in the pro forma results above was
based on the value of the contractual rights and obligations at February 19,
2002. The amounts applicable to 2002 were retroactively applied to January 1,
2002 through February 19, 2002 to arrive at the pro forma effect on those
periods. The unaudited pro forma condensed interim financial statements reflect
the acquisition of Orion Power in accordance with SFAS No. 141 and SFAS No. 142.

(7) GOODWILL AND INTANGIBLES

In July 2001, the FASB issued SFAS No. 142, which states that goodwill
and certain intangibles with indefinite lives will not be amortized into results
of operations, but instead will be reviewed periodically for impairment and
written down and charged to results of operations only in the periods in which
the recorded value of goodwill and certain intangibles with indefinite lives is
more than their fair values. We adopted the provisions of the statement, which
apply to goodwill and intangible assets acquired prior to June 30, 2001 on
January 1, 2002, and thus discontinued amortizing goodwill into our results of
operations.

During the third quarter of 2002, we completed the transitional
impairment test for the adoption of SFAS No. 142 on our interim financial
statements, including the review of goodwill for impairment as of January 1,
2002. This impairment test is performed in two steps. The initial step is
designed to identify potential goodwill impairment by comparing an estimate of
the fair value of the applicable reporting unit to its carrying value, including
goodwill. If the carrying value exceeded fair value, a second step is performed,
which compares the implied fair value of the applicable reporting unit's
goodwill with the carrying amount of that goodwill, to measure the amount of the
goodwill impairment, if any. Based on this impairment test, we recorded an
impairment of our European energy segment's goodwill of $234 million, net of
tax. This impairment loss was recorded retroactively as a cumulative effect of a
change in accounting principle for the quarter ended March 31, 2002. Based on
the first step of this goodwill impairment test, no goodwill was impaired for
our other reporting units.

The circumstances leading to the goodwill impairment of our European
energy segment included a significant decline in electric margins attributable
to the deregulation of the European electricity market in 2001, lack of growth
in the wholesale energy trading markets in Northwest Europe, continued
regulation of certain European fuel markets and the reduction of proprietary
trading in our European operations. Our measurement of the fair value of the
European energy segment was based on a weighted-average approach considering
both an income approach, using future discounted cash flows, and a market
approach, using acquisition multiples, including price per MW, based on publicly
available data for recently completed European transactions.

As of March 31, 2002, we completed our assessment of intangible assets
and no indefinite lived intangible assets were identified. No related impairment
losses were recorded in the first quarter of 2002 and no changes were made to
the expected useful lives of our intangible assets as a result of this
assessment.

14

SFAS No. 142 also requires goodwill to be tested annually and between
annual tests if events occur or circumstances change that would more likely than
not reduce the fair value of a reporting unit below its carrying amount.
Currently, we have elected to perform our annual test for indications of
goodwill impairment as of November 1, in conjunction with our annual planning
process. In estimating the fair value of our European energy segment for the
annual impairment test as of November 1, 2002, we considered the sales price in
the agreement that we signed in February 2003 to sell our European energy
operations to a Netherlands-based electricity distributor (see note 16). We
concluded that the sales price reflects the best estimate of fair value of our
European energy segment as of November 1, 2002, to use in our annual impairment
test. Based on our annual impairment test, we determined that an impairment of
the full amount of our European energy segment's net goodwill of $482 million
should be recorded in the fourth quarter of 2002. For additional information
regarding this transaction and its impacts, see note 16.

Based on our annual impairment test as of November 1, 2002, no goodwill
was impaired for our other reporting units. Our impairment analyses for our
other reporting units include numerous assumptions, including but not limited
to:

o 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;

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

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

These assumptions are consistent with our fundamental belief that long run
market prices must reach levels sufficient to support an adequate rate of return
on the construction of new power generation.

An impairment analysis requires estimates of future market prices,
valuation of plant and equipment, growth, competition and many other factors as
of the determination date. The resulting impairment analysis is highly dependent
on these underlying assumptions. Such assumptions are consistent with those
utilized in our annual planning process and industry valuation and appraisal
reports. If the assumptions and estimates underlying this goodwill impairment
evaluation differ greatly from the actual results or to the extent that such
assumptions change through time, there could be additional goodwill impairments
in the future.

(8) DERIVATIVE FINANCIAL INSTRUMENTS

Effective January 1, 2001, we adopted SFAS No. 133, which establishes
accounting and reporting standards for derivative instruments, including certain
derivative instruments embedded in other contracts and for hedging activities.
This statement requires that derivatives be recognized at fair value in the
balance sheet and that changes in fair value be recognized either currently in
earnings or deferred as a component of accumulated other comprehensive income
(loss), net of applicable taxes, depending on the intended use of the
derivative, its resulting designation and its effectiveness. If certain
conditions are met, an entity may designate a derivative instrument as hedging
(a) the exposure to changes in the fair value of an asset or liability (fair
value hedge), (b) the exposure to variability in expected future cash flows
(cash flow hedge) or (c) the foreign currency exposure of a net investment in a
foreign operation. For a derivative not designated as a hedging instrument, the
gain or loss is recognized in earnings in the period it occurs. During the three
months ended March 31, 2002 and 2003, we did not enter into any fair value
hedges.

Cash Flow Hedges. During the three months ended March 31, 2002 and
2003, the amount of hedge ineffectiveness recognized in revenues from
derivatives that are designated and qualify as cash flow hedges, including
interest rate derivative instruments (see note 10(c)), was a loss of $1 million
and a loss of $20 million, respectively. For the three months ended March 31,
2002 and 2003, no component of the derivative instruments' gain or loss was
excluded from the assessment of effectiveness. If it becomes probable that an
anticipated transaction will not occur, we realize in net income (loss) the
deferred gains and losses recognized in accumulated other comprehensive income
(loss). Should any forecasted interest payments become probable of not
occurring, any applicable deferred amounts will be recognized immediately as an
expense. During the three months ended March

15

31, 2002 and 2003, there were no deferred gains or losses recognized in earnings
as a result of the discontinuance of cash flow hedges because it was probable
that the forecasted transaction would not occur. Once the anticipated
transaction occurs, the accumulated deferred gain or loss recognized in
accumulated other comprehensive loss is reclassified and included in our
statements of consolidated operations under the captions (a) fuel expenses, in
the case of natural gas purchase transactions, (b) purchased power, in the case
of electric power purchase transactions, (c) revenues, in the case of electric
power and natural gas sales transactions and financial electric power or natural
gas derivatives and (d) interest expense, in the case of interest rate swap
transactions. As of March 31, 2003, we expect $37 million of gains netted in
accumulated other comprehensive loss to be reclassified into net income/loss
during the period from April 1, 2003 to March 31, 2004.

For a discussion of our interest rate derivative instruments, see note
10(c).

(9) EQUITY INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES

We have a 50% interest in a 470 MW electric generation plant in Boulder
City, Nevada. The plant became operational in May 2000. We have a 50%
partnership interest in a 108 MW cogeneration plant in Orange, Texas.

Our equity investments in unconsolidated subsidiaries are as follows:

Our income (loss) from equity investments of unconsolidated
subsidiaries is as follows:

16

During the three months ended March 31, 2002 and 2003, the net
distributions were $2 million and $1 million respectively, from these
investments.

As of March 31, 2003 the companies, in which we have an unconsolidated
equity investment, carry debt that is currently estimated to be $144 million
($72 million based on our proportionate ownership interests of the investments).

Summarized financial information for our equity method investments'
operating results is as follows:

Summarized financial information for our equity method investments'
financial position is as follows:

17

(10) BANKING OR DEBT FACILITIES, BONDS, NOTES AND OTHER DEBT

As more fully described below, we refinanced certain credit facilities
in March 2003, which included $1.3 billion previously incurred by a special
purpose entity, which we began to consolidate effective January 1, 2003. See
notes 2 and 13(a) for further discussion.

The following table presents our debt outstanding to third parties as
of December 31, 2002 and March 31, 2003:

(1) The weighted average interest rate is for borrowings outstanding as of
December 31, 2002 or March 31, 2003, as applicable.

(2) Includes amounts due within one year of the date noted, as well as
loans outstanding under revolving and working capital facilities
classified as current liabilities.

(3) See below for a discussion of the facilities refinanced in March 2003.
As a result of the refinancing, $3.9 billion has been classified as
long-term as of December 31, 2002.

(4) Debt and interest rate swaps acquired in the Orion Power acquisition
were adjusted to fair market value as of the acquisition date. Included
in interest expense is amortization of $1 million and $2 million for
valuation adjustments for debt and $3 million and $7 million for
valuation adjustments for interest rate swaps, respectively, for the
three months ended March 31, 2002 and 2003, respectively. These
valuation adjustments are being amortized over the respective remaining
terms of the related financial instruments.

(5) The fair value of the warrants issued in March 2003 of $15 million is
reduced from the debt balance. See below for further discussion.

Restricted Net Assets of Subsidiaries. As of December 31, 2002, certain
of Reliant Resources' subsidiaries have effective restrictions on their ability
to pay dividends or make intercompany loans and advances pursuant to their
financing arrangements. The amount of restricted net assets of Reliant
Resources' subsidiaries as of December 31, 2002 is approximately $3.3 billion.
The restrictions are on the net assets of Orion Capital, Liberty and
Channelview. Orion MidWest and Orion NY are indirect wholly-owned subsidiaries
of Orion Capital.

18

(a) BANKING OR DEBT FACILITIES, BONDS AND NOTES.

The following table provides a summary of the amounts owed and amounts
available as of March 31, 2003 under our various committed credit facilities,
bonds and notes:

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

(1) Included in this amount is $305 million of letters of credit
outstanding that support the $300 million of PEDFA bonds outstanding
for the Seward plant.

(2) The senior priority revolver facility expires on the earlier of the
closing of the Texas Genco acquisition, if we elect to exercise the
option, or December 15, 2004.

(3) Letters of credit may be issued under this facility until January 2004
and may remain outstanding until January 2005.

(4) Although the commitment is still available, in return for the waiver
from the lenders under the Liberty credit facility from the requirement
that Liberty enforce all of its respective rights under the tolling
agreement (see note 13(g)), Liberty has agreed that for the term of the
waiver, it will not make draws on the working capital facility.

As of March 31, 2003, we had $9.3 billion in committed credit
facilities, bonds and notes of which $768 million was unused. These facilities,
bonds and notes expire for the remainder of 2003 and the five succeeding years
and beyond as follows (in millions):

2003 ..................................... $ 155
2004 ..................................... 440
2005 ..................................... 1,416
2006 ..................................... 24
2007 ..................................... 5,993
2008 and beyond .......................... 1,242
--------
Total .................................. $ 9,270
========

As of March 31, 2003, committed credit facilities and notes aggregating
$451 million were unsecured.

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 (see note 13(a)), 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 the closing of the Texas Genco
acquisition if we elect to exercise the option 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.

19

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 in connection with our election to
exercise the option to acquire Texas Genco.

The loans under the refinanced credit facilities bear interest at the
London inter-bank offered rate (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. 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). Our March 2003 credit facilities restrict our ability
to take specific actions, subject to numerous exceptions that are designed to
allow for the execution of our business plans in the ordinary course, including
the completion of all four of the power plants currently under construction, the
preservation and optimization of all of our existing investments in the retail
energy and wholesale energy businesses, the ability to provide credit support
for our commercial obligations and the possible exercise of the option to
acquire a majority interest in Texas Genco, and the financings related thereto.
Such restrictions include our ability to (a) encumber our assets, (b) enter into
business combinations or divest our assets, (c) incur additional debt or engage
in sale and leaseback transactions, (d) pay dividends or prepay other debt, (e)
make investments or acquisitions, (f) enter into transactions with affiliates,
(g) make capital expenditures, (h) materially change our business, (i) amend our
debt and other material agreements, (j) repurchase our capital stock, (k) allow
distributions from our subsidiaries and (l) 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. 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. See (c) below for further discussion.

To date, we have incurred approximately $190 million in financing costs
(which includes $15 million to be paid at maturity). We capitalized $155 million
and expensed $35 million (of which $12 million was expensed in the fourth
quarter of 2002 and $23 million was expensed during the three months ended March
31, 2003) in fees and other costs related to our refinancing efforts.

Cash Collateralized Letter of Credit Facility. In January 2003, we
entered into a $200 million cash-secured, revolving letter of credit facility
with a financial institution. Outstanding letters of credit are required to be
103% cash collateralized. Under the facility, letters of credit may be issued
until January 29, 2004 and may remain outstanding until January 29, 2005. The
facility is not cross-defaulted to any other facility. The facility agreement
contains certain limited affirmative and negative covenants, but no financial
covenants. This letter of credit facility is subject to monthly letter of credit
and unused line fees that are calculated on the outstanding letters of credit
and the unused commitment, respectively. As of March 31, 2003,
outstanding letters of credit under this facility were $128 million. In
connection with this facility we have cash collateral of $145 million as of
March 31, 2003,

20

included in our consolidated balance sheet. We are currently in the process of
reducing the total letters of credit outstanding under the facility. As of May
8, 2003, the committed credit under the facility had been reduced to $20 million
and the outstanding letters of credit had been reduced to $2 million.

Orion Acquisition Term Loan. We entered into an unsecured syndicated
$2.2 billion term loan facility during the fourth quarter of 2001, which was
amended in January 2002 to provide for $2.9 billion in funding to finance the
purchase of Orion Power. For discussion of the acquisition of Orion Power, see
note 6. Interest rates on the borrowings under this facility were based on
either (a) LIBOR plus a margin based on Reliant Resources' credit rating and
length of time outstanding, which was 2.0% at December 31, 2002 or (b) a base
rate. This facility was funded on February 19, 2002 for $2.9 billion. During
March 2003, we refinanced this term loan facility; see discussion above.

364-day Revolver/Term Loan and Three-year Revolver. In 2001, we entered
into two unsecured syndicated revolving credit facilities, which provided for
$800 million each or an aggregate of $1.6 billion in committed credit. The
one-year term-out provision in the $800 million unsecured 364-day revolving
credit facility was exercised before it matured on August 22, 2002, resulting in
a one-year term loan with a maturity of August 22, 2003. The three-year revolver
had a maturity date of August 22, 2004. As of December 31, 2002, there was $1.4
billion in borrowings outstanding under these facilities. At December 31, 2002,
letters of credit outstanding under these two facilities aggregated $235
million. Interest rates on the borrowings were based on (a) LIBOR plus a margin
based on our credit rating, (b) a base rate or (c) a rate determined through a
bidding process. The LIBOR margin as of December 31, 2002 was 1.375% for the
364-day facility and 1.075% for the three-year facility. During March 2003, we
refinanced these facilities; see discussion above.

Orion Power's Debt Obligations. As a result of our acquisition of Orion
Power in early 2002, our consolidated net debt obligations also increased by the
amount of Orion Power's net debt obligations, which are discussed below. In
October 2002, a portion of this debt was refinanced, the terms of which are also
discussed below.

Orion Power 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. For the period February 20, 2002 to March 31,
2002, $1 million was amortized to interest expense for the senior notes. For the
three months ended March 31, 2003, $2 million was amortized to interest expense.
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 Revolving Senior Credit Facility. Orion Power had an
unsecured syndicated revolving senior credit facility. This facility was prepaid
and terminated in October 2002 in connection with the execution of the amended
and restated Orion MidWest and Orion NY credit facilities. See below for further
discussion of the debt refinancing. Amounts outstanding under the facility bore
interest at a floating rate.

Orion MidWest Credit Agreement. Orion MidWest, an indirect wholly-owned
subsidiary of Orion Power, had a secured, syndicated credit agreement, which
included a $988 million acquisition facility and a $75 million revolving working
capital facility, including letters of credit. This debt was refinanced in
October 2002; see below for further discussion. The loans bore interest at the
borrower's option at LIBOR plus 2.00% or a base rate plus 1.00%.

Orion New York Credit Agreement. Orion NY, an indirect wholly-owned
subsidiary of Orion Power, had a secured, syndicated credit agreement, which
included a $412 million acquisition facility and a $30 million revolving working
capital facility, including letters of credit. This debt was refinanced in
October 2002; see below for further discussion. The loans bore interest at the
borrower's option at LIBOR plus 1.75% or a base rate plus 0.75%.

In connection with the Orion Power acquisition, the existing interest
rate swaps for the Orion MidWest credit facility and the Orion NY credit
facility were bifurcated into a debt component and a derivative component. The
fair values of the debt components, approximately $59 million for the Orion
MidWest credit facility and $31 million for the Orion NY credit facility, were
based on our incremental borrowing rates at the acquisition date for similar

21

types of borrowing arrangements. The value of the debt component will be reduced
as interest rate swap payments are made. For the period from February 20, 2002
through March 31, 2002, the value of the debt component was reduced by $2
million and $1 million for Orion MidWest and Orion NY, respectively. For the
three months ended March 31, 2003, the value of the debt component was reduced
by $5 million and $2 million for Orion MidWest and Orion NY, respectively. See
note 8 for information regarding our derivative financial instruments. See below
for further discussion regarding our interest rate swaps.

Orion Power's Refinanced Debt. During October 2002, the Orion Power
revolving credit facility was prepaid and terminated and, as part of the same
transaction, we refinanced the Orion MidWest and Orion NY credit facilities,
which refinancing included an extension of the maturities by three years to
October 2005. In connection with these refinancings, we applied excess cash of
$145 million to prepay and terminate the Orion Power revolving credit facility
and to reduce the term loans and revolving working capital facilities at Orion
MidWest and Orion NY. As of the refinancing date, the amended and restated Orion
MidWest credit facility 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
under one facility to be made available to the other borrower to meet shortfalls
in the other borrower's ability to make certain payments, including operating
costs. This is effected through distributions of such available cash to Orion
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 (each described below) was
provided in connection with the refinancing, the ability of the borrowers to
make subsequent dividends to Orion Power for such interest payments or otherwise
is subject to certain requirements (described below) that 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.

22

Liberty Credit Agreement. In July 2000, Liberty Electric Power, LLC
(LEP) and Liberty Electric PA, LLC (Liberty), indirect wholly-owned subsidiaries
of Orion Power, entered into a 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.

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 (see note 13(g)). 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 additional information regarding the Liberty credit agreement
related issues and concerns, see note 13(g). Given that we believe that it is
probable that a credit agreement default will occur and thus make the obligation
callable before March 31, 2004, we have classified the debt as a current
liability. We, including Orion Power, would not be in default under our other
current debt agreements if any credit agreement default occurs at Liberty.

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 to be 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
(see note 2). Three series of tax-exempt revenue bonds relating to the Seward
project have been issued by the Pennsylvania Economic Development Financing
Authority (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 Form 10-K/A for a
discussion of REMA's lease obligations. The letter of credit facilities expire
in August 2003. The amount of each letter of credit is equal to an amount
representing the greater of (a) the next six months' scheduled rental payments
under the related lease, or (b) 50% of the scheduled rental payments due in the
next twelve months under the

23

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
anticipates refinancing or replacing the letter of credit facilities prior to
their maturity. REMA anticipates that the terms may be more restrictive and may
include higher fees, and the providers of the facilities may require security.

Reliant Energy Channelview L.P. In 1999, Reliant Energy Channelview
L.P. (Channelview), a special purpose project subsidiary of Reliant Energy Power
Generation, Inc. (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.

(b) OTHER DEBT.

Orion Convertible Senior Notes. As of the acquisition date, Orion Power
had outstanding $200 million of aggregate principal amount of 4.5% convertible
senior notes, due on June 1, 2008. Pursuant to certain change of control
provisions, Orion Power commenced an offer to repurchase the convertible senior
notes on March 1, 2002, which expired on April 10, 2002. During the second
quarter of 2002, we repurchased $189 million in principal amount under the offer
to repurchase. During the fourth quarter of 2002, the remaining $11 million
aggregate principal amount of the convertible senior notes were repurchased for
$8 million.

(c) INTEREST RATE DERIVATIVE INSTRUMENTS AND WARRANTS.

24

As discussed above in (a), we issued to the lenders 20,373,326 warrants
to acquire shares of our common stock. The fair value of the warrants issued of
$15 million was determined using a binomial model created by outside
consultants. The value is recorded as a discount to debt and an increase to
additional paid-in capital. The debt discount will be amortized to interest
expense using the effective interest method over the life of the related debt.

Certain of our subsidiaries are party to interest rate swap contracts
with an aggregate notional amount of $1.1 billion as of December 31, 2002 and
March 31, 2003 that fix the interest rate applicable to floating rate long-term
debt. As of March 31, 2003, floating rate LIBOR-based interest payments are
exchanged for weighted fixed rate interest payments of 6.96%. These swaps
qualify as cash flow hedges under SFAS No. 133 and the periodic settlements are
recognized as an adjustment to interest expense in the statements of
consolidated operations over the term of the swap agreements. See note 8 for
further discussion of our cash flow hedges.

In January 2002, we entered into forward-starting interest rate swaps
having an aggregate notional amount of $1.0 billion to hedge the interest rate
on a portion of future offerings of long-term fixed-rate notes. On May 9, 2002,
we liquidated $500 million notional amount of these forward-starting interest
rate swaps. The liquidation of these swaps resulted in a loss of $3 million,
which was recorded in accumulated other comprehensive loss and is being
amortized into interest expense in the same period during which the forecasted
interest payment affects earnings. In November 2002, we liquidated the remaining
$500 million notional amount of swaps at a loss of $52 million that was recorded
in accumulated other comprehensive loss and is being amortized into interest
expense in the same period during which the forecasted interest payment affects
earnings. At March 31, 2003, the unamortized balance of such loss was $39
million.

During January 2003, we purchased three-month LIBOR interest rate caps
to hedge our future floating rate risk associated with various credit
facilities. We have hedged $4.0 billion for the period from July 1 to December
31, 2003, $3.0 billion for 2004 and $1.5 billion for 2005. The LIBOR interest
rates are capped at a weighted average rate of 2.06% for the period from July 1
to December 31, 2003, 3.18% for 2004 and 4.35% for 2005. These interest rate
caps qualify for hedge accounting under SFAS No. 133 with any changes in fair
market value recorded to other comprehensive income (loss) and any
ineffectiveness recorded to net income/loss. We recorded ineffectiveness of $2
million in interest expense during the three months ended March 31, 2003 on
these interest rate caps.

(11) STOCKHOLDERS' EQUITY

(a) TREASURY STOCK PURCHASES.

On December 6, 2001, Reliant Resources' board of directors authorized
the purchase of up to an additional 10 million shares of its common stock
through June 2003, bringing the total shares authorized for purchase to 21
million, of which 11 million had previously been purchased. Any purchases are to
be made on a discretionary basis in the open market or otherwise at times and in
amounts as determined by management subject to market conditions, legal
requirements and other factors. Since December 6, 2001, Reliant Resources has
not purchased any shares of its common stock under this program. Based on the
refinancing of certain credit facilities in March 2003, Reliant Resources is
restricted from purchasing its common stock, other than in connection with its
various employee benefit plans; see note 10.

(b) TREASURY STOCK ISSUANCES AND TRANSFERS.

During the three months ended March 31, 2002 and 2003, we issued
550,781 shares and 717,931 shares, respectively, of treasury stock to employees
under our employee stock purchase plan. In addition, during the three months
ended March 31, 2003, we transferred 725,877 shares of treasury stock to our
savings plans and 82,713 shares of treasury stock to fund a portion of our
long-term incentive awards.

25

(12) EARNINGS PER SHARE

The following table presents our basic and diluted earnings (loss) per
share (EPS) calculation.

For the three months ended March 31, 2002, the computation of diluted
EPS excludes purchase options for 8,359,907 shares of common stock that have an
exercise price (ranging from $15.33 - $34.03 per share) greater than the per
share average market price ($13.73) for the period and would thus be
anti-dilutive if exercised. For the three months ended March 31, 2003, as we
incurred a loss from continuing operations, we do not assume any potentially
dilutive shares in the computation of diluted EPS. The computation of diluted
EPS excludes incremental shares from assumed conversions for stock options of
37,737 shares, restricted stock of 894,303 shares and employee stock purchase
plan rights of 173,724 shares for the three months ended March 31, 2003. The
computation of diluted EPS also excludes an adjustment to net loss and weighted
average shares outstanding for the warrants issued in connection with our March
2003 refinancing (see note 10(c)) as we incurred a loss from continuing
operations. The incremental shares from assumed conversions exclude purchase
options for 18,617,447 shares of common stock that have an exercise price
(ranging from $4.01 to $34.03 per share) greater than the average market price
($3.97) for the period and would thus be anti-dilutive if exercised.

(13) COMMITMENTS AND CONTINGENCIES

(a) CONSTRUCTION AGENCY AGREEMENTS SPECIAL PURPOSE ENTITIES.

In 2001, we, through several of our subsidiaries, entered into
operative documents with special purpose entities to facilitate the development,
construction, financing and leasing of several power generation projects. We did
not consolidate the special purpose entities as of December 31, 2002. Due to the
early adoption of FIN No. 46 (as explained in note 2), we consolidated these
special purpose entities effective January 1, 2003. As of January 1, 2003, we
consolidated property, plant and equipment of $1.3 billion, net other assets of
$3 million and secured debt obligations of $1.3 billion. As of January 1, 2003,
$1.0 billion of the debt obligations outstanding bore interest at LIBOR plus a
margin of 2.25%, while the remaining $0.3 billion of the debt obligations
outstanding bore interest at a weekly floating interest rate.

The special purpose entities' construction agency agreements and the
related guarantees were terminated and the related credit agreement was
refinanced as part of the refinancing in March 2003. See note 14(b) to our Form
10-K/A for additional information on the special purpose entities' financing
agreement, the construction agency agreements and the related guarantees. For
information regarding the refinancing, see note 10.

(b) PAYMENT TO CENTERPOINT IN 2004.

We may be required to make a payment to CenterPoint in 2004 to the
extent the affiliated retail electric provider's price to beat for providing
retail electric service to residential and small commercial customers in
CenterPoint's Houston service territory during 2002 and 2003 exceeds the market
price of electricity. This payment

26

is required by the Texas electric restructuring law, unless the PUCT determines,
on or prior to January 1, 2004, that 40% or more of the amount of electric power
that was consumed in 2000 by residential or small commercial customers, as
applicable, within CenterPoint's Houston service territory is committed to be
served by retail electric providers other than us. This amount will not exceed
$150 per customer, multiplied by the number of residential or small commercial
customers, as the case may be, that we serve on January 1, 2004 in CenterPoint's
Houston service territory, less the number of residential or small commercial
electric customers, as the case may be, we serve in other areas of Texas.
Currently, we believe it is probable that we will be required to make such
payment to CenterPoint related to our residential customers. We believe that the
payment related to our residential customers will be in the range of $160
million to $190 million (pre-tax), with a most probable estimate of $175
million. We will recognize the total obligation over the period we recognize the
related revenues based on the difference between the amount of the price to beat
and the estimated market price of electricity multiplied by the estimated energy
sold through January 1, 2004 not to exceed the maximum cap of $150 per customer.
We recognized $128 million (pre-tax) during the third and fourth quarters of
2002 and $47 million for the three months ended March 31, 2003 for a total
accrual of $175 million as of March 31, 2003. Through March 31, 2003, we have
accrued up to the maximum of $150 per customer. In the future, we will revise
our estimates of this payment as additional information about the market share
that will be served by us and other retail electric providers on January 1, 2004
becomes available and we will adjust the related accrual at that time.

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

(c) GUARANTEES.

We have issued a guarantee on behalf of another entity that provides
financial assurance to third parties.

The following table details our guarantee, including the maximum
potential amount of future payments, assets held as collateral and the carrying
amount of the liability recorded on our consolidated balance sheet, if
applicable, as of March 31, 2003:

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

(1) We have guaranteed, in the event CenterPoint becomes insolvent, certain
non-qualified benefits of CenterPoint's and its subsidiaries' existing
retirees at the Distribution.

We believe the likelihood that we would be required to perform or
otherwise incur any significant losses associated with this guarantee is remote.

We have entered into contracts that include indemnification provisions
as a routine part of our business activities. Examples of these contracts
include asset purchase and sale agreements, commodity purchase and sale
agreements, operating agreements, lease agreements, procurement agreements and
certain debt agreements. In general, these provisions indemnify the counterparty
for matters such as breaches of representations and warranties and covenants
contained in the contract and/or against third party liabilities. In the case of
commodity purchase and sale agreements, generally damages are limited through
liquidated damages clauses whereby the parties agree to establish damages as the
costs of covering any breached performance obligations. In the case of debt
agreements, we generally indemnify against liabilities that arise from the
preparation, entry into, administration or enforcement of the agreement. Under
our indemnifications, the maximum potential amount is not estimable given that
the magnitude of any claims under the indemnifications would be a function of
the extent of damages actually incurred, which is not practicable to estimate
unless and until the event occurs. We consider the likelihood of making any
material payments under these provisions to be remote.

(d) ENVIRONMENTAL AND LEGAL MATTERS.

We are involved in environmental and legal proceedings before various
courts and governmental agencies,

27

some of which involve substantial amounts. In addition, we are subject to a
number of ongoing investigations by various governmental agencies. Certain of
these proceedings and investigations are the subject of intense, highly charged
media and political attention. As these matters progress, additional issues may
be identified that could expose us to further proceedings and investigations.
Our management regularly analyzes current information and, as necessary,
provides accruals for probable liabilities on the eventual disposition of these
matters that can be estimated.

We have an agreement with CenterPoint that requires us to indemnify
CenterPoint for matters relating to our business and operations prior to the
Distribution, as well as for any untrue statement of a material fact, or
omission of a material fact necessary to make any statement not misleading, in
the registration statement or prospectus that we filed with the SEC in
connection with our IPO. CenterPoint has been named as a defendant in many legal
proceedings relative to such matters and has requested indemnification from us.

Legal Matters.

Unless otherwise indicated, the ultimate outcome of the following
lawsuits, proceedings and investigations cannot be predicted at this time. The
ultimate disposition of some of these matters could have a material adverse
effect on our financial condition, results of operations and cash flows.

California Class Actions. We, as well as certain of our former
officers, have been named as defendants in a number of class action lawsuits in
California. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in California in violation of California's antitrust and
unfair and unlawful business practices laws. The lawsuits seek injunctive
relief, treble the amount of damages alleged, restitution of alleged
overpayments, disgorgement of alleged unlawful profits for sales of electricity,
costs of suit and attorneys' fees. In general, these lawsuits can be segregated
into two groups based on their pre-trial status. The first group consists of (a)
three lawsuits filed in the Superior Court of the State of California, San Diego
County filed on November 27, 2000, November 29, 2000 and January 16, 2001; (b)
two lawsuits filed in the Superior Court of the State of California, San
Francisco County on January 18, 2001 and January 24, 2001; and (c) one lawsuit
filed in the Superior Court of the State of California, Los Angeles County on
May 2, 2001. These six lawsuits were consolidated and removed to the United
States District Court for the Southern District of California. In December 2002,
the court ordered these six lawsuits be remanded to state court for further
consideration. We, and our co-defendants, filed a petition with the United
States Court of Appeals for the Ninth Circuit seeking a review of the order to
remand. The petition is under consideration by the court. The second group
consists of two lawsuits filed in the Superior Court of the State of California,
San Mateo County filed on April 23, 2002 and May 15, 2002, two lawsuits filed in
the Superior Court of the State of California, San Francisco County on May 14,
2002 and May 24, 2002, two lawsuits filed in the Superior Court of the State of
California, Alameda County on May 21, 2002, one lawsuit filed in the Superior
Court of the State of California, San Joaquin County on May 10, 2002 and one
lawsuit filed in the Superior Court of the State of California, Los Angeles
County on October 18, 2002. These eight lawsuits were consolidated in the United
States District Courts, six of which were removed to the United States District
Court for the Northern District of California, one was removed to the United
States District Court for the Eastern District of California, and one was
removed to the United States District Court for the Central District of
California. Additionally, on July 15, 2002, the Snohomish County Public Utility
District filed a class action lawsuit against us in United States District Court
for the Central District of California. In January 2003, the court granted our
motion to dismiss this lawsuit on the grounds that the plaintiffs' claims are
barred by federal preemption and the FERC filed rate doctrine. The plaintiffs
have appealed to the United States Court of Appeals for the Ninth Circuit.

On April 16, 2003, a class action lawsuit was filed against us and one
of our employees in the Superior Court of the State of California, Los Angeles
County. The plaintiffs allege that we engaged in unfair, unlawful and fraudulent
business practices and entered into certain contracts in furtherance of a
conspiracy to increase the price of natural gas in California in
violation of the Cartwright Act and California's antitrust and unfair and
unlawful business practices laws. The lawsuit seeks injunctive and declaratory
relief, treble the amounts of damages, restitution, disgorgement of unjust
enrichment, costs of suit and attorneys' fees.

On May 1, 2003, a class action lawsuit was filed against us in the
Superior Court of the State of California, San Diego County. The plaintiffs
allege that we engaged in unfair, unlawful and fraudulent business practices by
manipulating energy markets in California and the West. The action is brought on
behalf of all persons and businesses residing in Oregon, Washington, Utah,
Nevada, Idaho, New Mexico, Arizona and Montana. The lawsuit seeks injunctive
relief, treble the amount of damages, restitution, costs of suit and attorneys'
fees.

Oregon Class Actions. On December 16, 2002, a class action lawsuit was
filed against us in the Circuit Court of the State of Oregon, County of
Multnomah. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in Oregon in violation of Oregon's consumer protection,
fraud and negligence laws. The lawsuit seeks injunctive relief, treble the
amount of damages alleged, restitution of alleged overpayments, disgorgement of
alleged unlawful profits for sales of electricity, costs of suit and attorneys'
fees. This lawsuit was removed to the United States District Court for the
Northern District of California. On May 2, 2003, the plaintiffs filed a motion
to dismiss this case without prejudice. On May 5, 2003, the presiding judge
entered an order dismissing the case without prejudice.

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Washington Class Actions. On December 20, 2002, a class action lawsuit
was filed against us in United States District Court for the Western District of
Washington. The plaintiffs allege that we conspired to increase the price of
wholesale electricity in Washington in violation of Washington's consumer
protection, fraud and negligence laws. The lawsuit seeks injunctive relief,
treble the amount of damages alleged, restitution of alleged overpayments,
disgorgement of alleged unlawful profits for sales of electricity, costs of suit
and attorneys' fees.

California Attorney General Actions. On March 11, 2002, the California
Attorney General filed a lawsuit against us in Superior Court of the State of
California, San Francisco County. The California Attorney General alleges
various violations of state laws against unfair and unlawful business practices
arising out of transactions in the markets for ancillary services run by the
California Independent System Operator (Cal ISO). The lawsuit seeks injunctive
relief, disgorgement of our alleged unlawful profits for sales of electricity
and civil penalties. We removed this lawsuit to the United States District Court
for the Northern District of California. In March 2003, the court granted our
motion to dismiss this lawsuit on the grounds that the plaintiffs' claims are
barred by federal preemption and the FERC filed rate doctrine.

On March 19, 2002, the California Attorney General filed a complaint
against us with the FERC. The complaint alleges that we, as a seller with
market-based rates, violated our tariffs by not filing with the FERC
transaction-specific information about all of our sales and purchases at
market-based rates. The California Attorney General argued that, as a result,
all past sales should be subject to a refund if they are found to be above just
and reasonable levels. In May 2002, the FERC issued an order that largely denied
the complaint and required only that we file revised transaction reports
regarding prior sales in California spot markets. In September 2002, the
California Attorney General petitioned the United States Court of Appeals for
the Ninth Circuit for review of the FERC orders. The California Attorney
General's petition is under consideration by the court.

On April 15, 2002, the California Attorney General filed a lawsuit
against us in San Francisco County Superior Court. The lawsuit is substantially
similar to the complaint described above filed by the California Attorney
General with the FERC. The lawsuit also alleges that we consistently charged
unjust and unreasonable prices for electricity and that each unjust charge
violated California law. The lawsuit seeks fines of up to $2,500 for each
alleged violation and such other equitable relief as may be appropriate. We
removed this lawsuit to the United States District Court for the Northern
District of California. In March 2003, the court granted our motion to dismiss
this lawsuit on the grounds that the plaintiffs' claims are barred by federal
preemption and the FERC filed rate doctrine.

On April 15, 2002, the California Attorney General and the California
Department of Water Resources (CDWR) filed a lawsuit against us in the United
States District Court for the Northern District of California. The plaintiffs
allege that our acquisition of electric generating facilities from Southern
California Edison in 1998 violated Section 7 of the Clayton Act, which prohibits
mergers or acquisitions that substantially lessen competition. The lawsuit
alleges that the acquisitions gave us market power, which we then exercised to
overcharge California consumers for electricity. The lawsuit seeks injunctive
relief against alleged unfair competition, divestiture of our California
facilities, disgorgement of alleged illegal profits, damages, and civil
penalties for each alleged exercise of illegal market power. In March 2003, the
court dismissed the plaintiffs' claim for damages and Section 7 of the Clayton
Act but declined to dismiss the plaintiffs' injunctive claim for divestiture of
our California facilities.

California Lieutenant Governor Class Action. On November 20, 2002, the
California Lieutenant Governor filed a taxpayer representative lawsuit against
us in Superior Court of the State of California, Los Angeles County on behalf of
purchasers of gas and power in California. The plaintiffs allege that we
manipulated the pricing of gas and power by reporting false prices and
fraudulent trades to the publishers of various price indices. The lawsuit seeks
injunctive relief, disgorgement of profits and funds acquired by the alleged
unlawful conduct.

FERC Complaints. On April 11, 2002, the FERC set for hearing a series
of complaints filed by Nevada Power Company, which seek reformation of certain
forward power contracts with several companies, including two contracts with us
that have since been terminated. In December 2002, the presiding administrative
law judge in these consolidated proceedings issued recommended findings of fact
favorable to our positions and upholding the contracts. Those recommendations
are pending before the FERC for final decision. PacifiCorp Company filed a
similar complaint challenging two 90-day contracts with us. In February 2003,
the presiding administrative law judge issued an initial decision recommending
the dismissal of PacifiCorp Company's complaint and upholding the contracts. The
FERC has stated that it intends to issue final decisions in both complaints in
May 2003.

29

Trading and Marketing Proceedings and Investigations. We are party to
the following proceedings and investigations relating to our trading and
marketing activities, including our round trip trades and certain structured
transactions.

In June 2002, the SEC advised us that it had issued a formal order in
connection with its investigation of our financial reporting, internal controls
and related matters. The investigation is focused on our round trip trades and
certain structured transactions. We 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. The SEC did not
assess any monetary penalties or fines relating to the order.

As part of the Commodity Futures Trading Commission's (CFTC)
industry-wide investigation of round trip trading, the CFTC has subpoenaed
documents, requested information and conducted discovery relating to our natural
gas and power trading activities, including round trip trades and alleged price
manipulation, occurring since January 1999. The CFTC is also looking into the
facts and circumstances surrounding certain events in June 2000 that were the
subject of a settlement with FERC in January 2003 described below. We are
cooperating with the CFTC staff.

On March 26, 2003, the FERC staff issued a report entitled "Final
Report on Price Manipulation in Western Markets," which expanded and finalized
the FERC staff's August 13, 2002 initial report. Certain findings, conclusions
and observations in the FERC staff report, if adopted or otherwise acted on by
the FERC, could have a material adverse effect on us. The report recommends the
institution of proceedings directing certain entities, including us, to show
cause why bids submitted in markets operated by the Cal ISO and California Power
Exchange (Cal PX) from May to October 2000 did not constitute economic
withholding or inflated bidding in violation of the Cal ISO and Cal PX tariffs.
If adopted, such proceedings could require a disgorgement of revenues related to
some sales for the period May to October 2000. The report also recommends the
institution of proceedings directing certain entities, including us, to show
cause why certain behavior identified in a January 6, 2003 report by the Cal
ISO, entitled "Analysis of Trading and Scheduling Strategies Described in the
Enron Memos," did not constitute gaming in violation of the tariffs of the Cal
ISO and Cal PX, and if adopted, such proceedings could require a disgorgement of
revenues from certain transactions from the period January 1, 2000 through June
21, 2001, which the Cal ISO report identified as an amount less than $30.00
potentially attributable to us. We will have an opportunity to provide comments
on these recommendations before formal proceedings are commenced. Finally, the
report recommends that certain entities, including us, demonstrate that we no
longer sell natural gas at wholesale or have instituted certain practices with
regards to reporting natural gas price information, have disciplined employees
that participated in manipulation or attempted manipulation of public price
indices, and are cooperating fully with any government agency investigating our
prior price reporting practices. On April 30, 2003, the FERC issued an order
requiring these entities to demonstrate these items by June 16, 2003.

Also on March 26, 2003, the FERC instituted proceedings directing our
trading company and BP Energy Company (BP) to show cause why each company's
market-based rate authority should not be revoked. These proceedings arose in
connection with certain actions taken by one of our traders and one of BP's
traders relating to sales of electricity at the Palo Verde hub. If FERC were to
prospectively revoke our trading company's market-based rate authority, it could
have a material adverse effect on us. We have responded to the FERC and
contested the FERC's proposed remedy for the alleged conduct.

On January 31, 2003, in connection with the FERC's investigation of
potential manipulation of electricity and natural gas prices in the Western
United States, the FERC approved a stipulation and consent agreement between the
FERC staff and us relating to certain actions taken by some of our traders over
a two-day period in June 2000. Under the agreement, we agreed to pay $14 million
(expensed in the fourth quarter of 2002 and paid in February 2003) directly to
customers of the Cal PX and certain other terms, including a requirement to
abide by a must offer obligation to submit bids for all of our uncommitted,
available capacity from our plants located in California into a California spot
market one additional year following termination of our existing must offer
obligation or until December 31, 2006, whichever is later.

We have received subpoenas and informal requests for information from
the United States Attorney for the Southern District of New York and the
Northern District of California for documents, interviews and other

30

information pertaining to the round trip trades, and our energy trading
activities. We are cooperating with both offices of the United States Attorney.

Shareholder Class Actions. We, as well as certain of our former
officers and directors, have been named as defendants in 11 class action
lawsuits filed on behalf of purchasers of our securities and the securities of
CenterPoint. CenterPoint is also named as a defendant in three of the lawsuits.
Two of the lawsuits name as defendants the underwriters of our IPO, which we
have agreed to indemnify. One of those two lawsuits names our independent
auditors as a defendant. The dates of filing of these lawsuits are as follows:
two lawsuits on May 15, 2002; two lawsuits on May 16, 2002; one lawsuit on May
17, 2002; one lawsuit on May 20, 2002; one lawsuit on May 21, 2002; one lawsuit
on May 23, 2002; one lawsuit on June 19, 2002; one lawsuit on June 20, 2002; and
one lawsuit on July 1, 2002. Ten of the lawsuits were filed in the United States
District Court, Southern District of Texas, Houston Division. One lawsuit was
filed in the United States District Court, Eastern District of Texas, Texarkana
Division and subsequently transferred to the United States District Court,
Southern District of Texas, Houston Division. The lawsuits allege that the
defendants overstated revenues by including transactions involving the purchase
and sale of commodities with the same counterparty at the same price and that we
improperly accounted for certain other transactions. The lawsuits seek monetary
damages and, in one of the lawsuits rescission, on behalf of a supposed class.
In eight of the lawsuits, the class is composed of persons who purchased or
otherwise acquired our securities and/or the securities of CenterPoint during
specified class periods. The three lawsuits that include CenterPoint as a named
defendant were also filed on behalf of purchasers of our securities and/or the
securities of CenterPoint during specified class periods.

Four class action lawsuits were filed on behalf of purchasers of the
securities of CenterPoint. CenterPoint and several of its officers are named as
defendants. The dates of filing of the four lawsuits are as follows: one on May
16, 2002; one on May 21, 2002; one on June 13, 2002; and one on June 17, 2002.
The lawsuits were filed in the United States District Court, Southern District
of Texas, Houston Division. The lawsuits allege that the defendants violated
federal securities laws by issuing false and misleading statements to the
public. The plaintiffs allege that the defendants made false and misleading
statements as part of an alleged scheme to artificially inflate trading volumes
and revenues by including transactions involving the purchase and sale of
commodities with the same counterparty at the same price, to use the spin-off to
avoid exposure to our liabilities and to cause the price of our stock to rise
artificially, among other things. The lawsuits seek monetary damages on behalf
of persons who purchased CenterPoint securities during specified class periods.
The court consolidated all of the lawsuits pending in the United States District
Court, Southern District of Texas, Houston Division and appointed the Boca Raton
Police & Firefighters Retirement System and the Louisiana School Employees
Retirement System to be the lead plaintiffs in these lawsuits. The lead
plaintiffs seek monetary relief purportedly on behalf of purchasers of
CenterPoint common stock from February 3, 2000 to May 13, 2002, purchasers of
our common stock in the open market from May 1, 2001 to May 13, 2002 and
purchasers of our common stock in our IPO or purchasers of common stock that are
traceable to our IPO. The lead plaintiffs allege, among other things, that the
defendants misrepresented our revenues and trading volumes by engaging in round
trip trades and improperly accounted for certain structured transactions as cash
flow hedges, which resulted in earnings from these transactions being accounted
for as future earnings rather than being accounted for as earnings in 2001.

On February 7, 2003, a lawsuit was filed against us in United States
District Court for the Northern District of Illinois, Eastern Division. The
plaintiffs allege that we violated federal securities law, Illinois common law
and the Illinois Consumer Fraud and Deceptive Trade Practices Act. The lawsuit
makes allegations similar to those made in the above-described class action
lawsuits and seeks treble the amount of damages alleged, costs of suit and
attorneys' fees.

ERISA Action. On May 30, 2002, a class action lawsuit was filed in the
United States District Court, Southern District of Texas, Houston Division
against us, certain of our present and former officers and directors,
CenterPoint, certain of the present and former directors and officers of
CenterPoint and certain present and former members of the benefits committee of
CenterPoint on behalf of participants in various employee benefits plans
sponsored by CenterPoint. The lawsuit alleges that the defendants breached their
fiduciary duties to various employee benefits plans sponsored by CenterPoint, in
violation of the Employee Retirement Income Security Act. The plaintiffs allege
that the defendants permitted the plans to purchase or hold securities issued by
CenterPoint when it was imprudent to do so, including after the prices for such
securities became artificially inflated because of alleged securities fraud
engaged in by the defendants. The lawsuit seeks monetary damages for losses
suffered by a class of plan participants whose accounts held CenterPoint
securities or our securities, as well as equitable relief in the form of
restitution.

31

Shareholder Derivative Actions. On May 17, 2002, a derivative lawsuit
was filed against our directors and independent auditors in the 269th Judicial
District, Harris County, Texas. The lawsuit alleges that the defendants breached
their fiduciary duties to us. The shareholder plaintiff alleges that the
defendants caused us to conduct our business in an imprudent and unlawful
manner, including allegedly failing to implement and maintain an adequate
internal accounting control system, engaging in transactions involving the
purchase and sale of commodities with the same counterparty at the same price,
and disseminating materially misleading and inaccurate information regarding our
revenue and trading volume. The lawsuit seeks monetary damages on behalf of us.

On October 25, 2002, a derivative lawsuit was filed against the
directors and officers of CenterPoint. The lawsuit was filed in the United
States District Court for the Southern District of Texas, Houston Division. The
lawsuit alleges breach of fiduciary duty, waste of corporate assets, abuse of
control and gross mismanagement by the defendants causing CenterPoint to
overstate the revenues through round trip and structured transactions and breach
of fiduciary duty in connection with the Distribution and our IPO. The lawsuit
seeks monetary damages on behalf of CenterPoint as well as equitable relief in
the form of a constructive trust on the compensation paid to the defendants. A
special litigation committee appointed by the board of directors of CenterPoint
is investigating similar allegations made in a June 28, 2002 demand letter from
a stockholder of CenterPoint. The letter states that certain shareholders of
CenterPoint are considering filing a derivative suit on behalf of CenterPoint
and demands that CenterPoint take several actions in response to the alleged
round trip trades and structured transactions. The special litigation committee
is investigating the allegations made in the demand letter to determine whether
pursuit of a derivative lawsuit is in the best interest of CenterPoint.

Environmental Matters.

REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see note 5(b)), we became responsible for liabilities
associated with ash disposal site closures and site contamination at the
acquired facilities in Pennsylvania and New Jersey prior to a plant closing,
except for the first $6 million of remediation costs at the Seward Generating
Station. A prior owner retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. As of
March 31, 2003, REMA had liabilities associated with six future ash disposal
site closures and six current site investigations and environmental
remediations. We have recorded our estimate of these environmental liabilities
in the amount of $31 million as of March 31, 2003. We expect approximately $13
million will be paid over the next five years.

Orion Power Environmental Contingencies. In connection with Orion
Power's acquisition of 70 hydro plants in northern and central New York and four
gas-fired or oil-fired plants in New York City, Orion Power assumed the
liability for the estimated cost of environmental remediation at several
properties. Orion Power developed remediation plans for each of these properties
and entered into Consent Orders with the New York State Department of
Environmental Conservation at three New York City sites and one hydro site for
releases of petroleum and other substances by the prior owners. As of March 31,
2003, the undiscounted liability assumed and recorded by us for these assets was
approximately $8 million, which we expect to pay out through 2006.

In connection with the acquisition of Midwest assets by Orion Power,
Orion Power became responsible for the liability associated with the closure of
three ash disposal sites in Pennsylvania. As of March 31, 2003, the liability
assumed and recorded by us for these disposal sites was approximately $11
million, with $1 million to be paid over the next five years.

Other Matters.

We are involved in other legal and environmental proceedings before
various courts and governmental agencies regarding matters arising in the
ordinary course of business, some of which involve substantial amounts. We
believe that the effects on our interim financial statements, if any, from the
disposition of these matters will not have a material adverse effect on our
financial condition, results of operations or cash flows.

(e) CALIFORNIA ENERGY SALES CREDIT AND REFUND PROVISIONS.

During portions of 2000 and 2001, prices for wholesale electricity in
California increased dramatically as a result of a combination of factors,
including higher natural gas prices and emission allowance costs, reduction in
available hydroelectric generation resources, increased demand, decreased net
electric imports and limitations on

32

supply as a result of maintenance and other outages. Although wholesale prices
increased, California's deregulation legislation kept retail rates frozen at 10%
below 1996 levels for two of California's public utilities, Pacific Gas and
Electric (PG&E) and Southern California Edison Company (SCE), until rates were
raised by the California Public Utilities Commission early in 2001. Due to the
disparity between wholesale and retail rates, the credit ratings of PG&E and SCE
fell below investment grade. Additionally, PG&E filed for protection under the
bankruptcy laws in April 2001. As a result, PG&E and SCE were no longer
considered creditworthy, and from January 17, 2001 through March 31, 2003, did
not directly purchase power from third-party suppliers through the Cal ISO to
serve that portion of the power demand that could not be met from their own
supply sources (net short load). Pursuant to emergency legislation enacted by
the California legislature, the CDWR negotiated and purchased power through
short and long-term contracts and through real-time markets operated by the Cal
ISO to serve the net short load requirements of PG&E and SCE. In December 2001,
the CDWR began making payments to the Cal ISO for real-time transactions. In May
2002, the FERC issued an order stating that wholesale suppliers, including us,
should receive interest payments on past due amounts owed by the Cal ISO and the
CDWR. As a result, we recorded $5 million and $9 million of net interest
receivable during 2002 and for the three months ended March 31, 2003,
respectively, as discussed below. The CDWR has now made payment through the Cal
ISO for its real-time energy deliveries subsequent to January 17, 2001, although
the Cal ISO's distribution of the CDWR's payment for the month of January 2001,
and the allocation of interest to past due amounts, are the subjects of motions
that we have filed with the FERC objecting to the Cal ISO's failure to allocate
the January payment and interest solely to post January 17, 2001 transactions.
In addition, we are prosecuting a lawsuit in California to recover the market
value of forward contracts seized by California Governor Gray Davis in violation
of the Federal Power Act. Governor Davis' actions prevented the liquidation of
the contracts by the Cal PX to satisfy the outstanding obligations of SCE and
PG&E to wholesale suppliers, including us. The timing and ultimate resolution of
this claim is uncertain at this time.

California Credit Provision. We were owed total receivables, including
interest, of $120 million (net of estimated refund provision of $191 million)
and $221 million (net of estimated refund provision of $104 million) as of
December 31, 2002 and March 31, 2003, respectively, by the Cal ISO, the Cal PX,
the CDWR, and California Energy Resources Scheduler for energy sales in the
California wholesale market during the fourth quarter of 2000 through March 31,
2003. From April 1, 2003 through May 1, 2003, we have collected $19 million of
these receivable balances.

During 2000 and 2001, we recorded net pre-tax credit provisions against
receivable balances related to energy sales in California of $39 million and $29
million, respectively. As of December 31, 2001, we had a pre-tax credit
provision of $68 million against receivable balances related to energy sales in
the California market. During 2002, $62 million ($33 million during the three
months ended March 31, 2002) of a previously accrued credit provision for energy
sales in California was reversed. The reversal resulted from collections of
outstanding receivables during the period, a determination that credit risk had
been reduced on the remaining outstanding receivables as a result of payments in
2002 to the Cal PX and due to the write-off of receivables as a result of a May
15, 2002 FERC order and related interpretations and a March 26, 2003 FERC order
on proposed findings on refund liability, discussed below. During the three
months ended March 31, 2003, we recorded an additional credit provision of $12
million due to the reversal of refund provisions as discussed below. As of
December 31, 2002 and March 31, 2003, we had a remaining pre-tax credit
provision of $6 million and $18 million, respectively, against these receivable
balances. We will continue to assess the collectability of these receivables
based on further developments.

FERC Refunds. In response to the filing of a number of complaints
challenging the level of wholesale prices in California, the FERC initiated a
staff investigation and issued a number of orders implementing a series of
wholesale market reforms. In these orders, the FERC also instituted refund
proceedings, described below. Prior to proposing a methodology for calculating
refunds in the refund proceeding discussed below, the FERC identified amounts
charged by us for sales in California to the Cal ISO and the Cal PX for the
period January 1, 2001 through June 19, 2001 as being subject to possible
refunds. Accordingly, during 2001, we accrued refunds of $15 million.

The FERC issued an order in July 2001 adopting a refund methodology and
initiating a hearing schedule to determine (a) revised mitigated prices for each
hour from October 2, 2000 through June 20, 2001, (b) the amount owed in refunds
by each electric wholesale supplier according to the methodology and (c) the
amount currently owed to each electric wholesale supplier. The FERC issued an
order on March 26, 2003, adopting in most respects the proposed findings of the
presiding administrative law judge that had been issued in December 2002
following a hearing to apply the refund formula. The most consequential change
involved the adoption of a different methodology for determining the gas price
component of the refund formula. Instead of using California border

33

daily gas indices, the FERC ordered the use of a proxy gas price based on
producing area daily price indices plus the posted transportation costs. In
addition, the order allows generators to petition for a reduction of the refund
calculation upon a submittal to the FERC of their actual gas costs and
subsequent FERC approval. Based on the proposed findings of the administrative
law judge, discussed above, adjusted for the March 2003 FERC decision to revise
the methodology for determining the gas price component of the formula, we
estimate our refund obligation to be between approximately $104 million and $230
million for energy sales in California. The low range of our estimate is based
on a refund calculation using a methodology established by the FERC in late
March 2003 and clarified in April 2003. This methodology calculates in a
reduction in the total FERC refund based on the actual cost paid for gas over
the proposed proxy gas price. The high range of our estimate of the refund
obligation assumes that the refund obligation is not adjusted for the actual
cost paid for gas over the proposed proxy gas price. Our estimate of the range
will be revised further upon subsequent action by the FERC or as additional
information becomes available. We cannot currently predict whether that will
result in an increase or decrease in our high and low points in the range.
During 2002, we recorded reserves for refunds of $176 million ($0 during the
three months ended March 31, 2002) related to energy sales in California. As
discussed above, $15 million was recognized during 2001. During the three months
ended March 31, 2003, we reversed $87 million of previously recorded refund
provisions due to additional clarification received from the FERC and other
information received in April 2003. As of December 31, 2002 and March 31, 2003,
our reserve for refunds related to energy sales in California is $191 million
and $104 million, respectively. The California refunds will likely be offset
against unpaid amounts owed to us for our prior sales in California.

Interest Calculation. In the fourth quarter of 2002, we recorded net
interest income of $5 million based on the December 2002 findings of the
presiding administrative law judge. During the three months ended March 31,
2003, we recorded net interest income of $9 million. The net interest income was
estimated using the low end of the potential refund, the receivable balance
outstanding, and the quarterly interest rates for the applicable time period
designated by the FERC.

(f) RELIANT ENERGY DESERT BASIN CONTINGENCY.

One of our subsidiaries, Reliant Energy Desert Basin, LLC (REDB), sells
power to Salt River Project (SRP) under a long-term power purchase agreement.
Reliant Resources guarantees certain of REDB's obligations under the agreement.
In the event we are downgraded to below investment grade by two major ratings
agencies, SRP can request performance assurance in the form of cash or a letter
of credit from REDB under the agreement or us under the guarantee. The total
amount of performance assurance cannot exceed $150 million. In September 2002,
following our downgrade to below investment grade by two rating agencies, SRP
requested performance assurance from us and REDB in the aggregate amount of $150
million. We informed SRP that the agreement does not stipulate the amount of
performance assurance required in the event of a credit downgrade. We also
communicated to SRP that under prevailing market conditions and after giving
effect to other factors, a letter of credit in the amount of $3 million would
provide commercially reasonable assurance of REDB's ability to perform its
obligations under the agreement. Accordingly, we provided SRP with a $3 million
letter of credit. SRP subsequently notified us that it deemed the amount
inadequate and returned the letter of credit to us. SRP has alleged that we
breached the agreement by failing to provide the requested $150 million letter
of credit. We have communicated to SRP that we remain of the opinion that the
provision of a $3 million letter of credit fulfills the obligation of us and
REDB to provide performance assurance and that SRP would be in breach of the
agreement and liable to REDB for damages if it were to terminate the agreement
based on our refusal to provide performance assurance in the amount of $150
million. As of May 1, 2003, we have not received any form of correspondence from
SRP since 2002 and neither SRP nor we have taken steps to terminate the
agreement.

(g) TOLLING AGREEMENT FOR LIBERTY'S ELECTRIC GENERATING STATION.

The output of Liberty's electric generating station is contracted under
a tolling agreement between LEP and PG&E Energy Trading-Power, L.P. (PGET) for
an initial term through September 2016, with an option by PGET to extend the
initial term for an additional two years. Under the tolling agreement, PGET has
the exclusive right to receive all electric energy, capacity and ancillary
services produced by the Liberty generating station, and PGET must pay for all
fuel used by the Liberty generating station.

The tolling agreement requires PGET to maintain guarantees, issued by
entities having investment grade credit ratings, for its obligations under the
tolling agreement. During 2002, several rating agencies downgraded to
sub-investment grade the debt of the two guarantors of PGET, PG&E National
Energy Group, Inc. and PG&E Gas

34

Transmission Northwest Corp. Due to the fact that PGET did not post replacement
security within the period required under the tolling agreement, the downgrade
constitutes an event of default by PGET under the tolling agreement. The Liberty
credit facility restricts the ability of LEP to terminate the tolling agreement.
There is also a requirement in the Liberty credit facility that Liberty and LEP
enforce all of their respective rights under the tolling agreement. Liberty and
LEP have received a waiver from the lenders under the Liberty credit facility
from the requirement that they enforce all of their respective rights under the
tolling agreement. In return for this waiver, Liberty and LEP have agreed that
for the term of the waiver, they would not be able to make draws on the working
capital facility that is available under the Liberty credit facility. The
current waiver expires on June 30, 2003. There is no assurance that Liberty and
LEP will be able to receive any waiver extension. If Liberty is unable to obtain
an extension to the waiver, then the lenders may claim that Liberty is in breach
and, if said breach is not cured, that there is an event of default under the
Liberty credit facility.

In addition, on August 19, 2002, and September 10, 2002, PGET notified
LEP that it believed LEP had violated the tolling agreement by not following
PGET's instructions relating to the dispatch of the Liberty station during
specified periods. The September 10, 2002 letter also claims that LEP did not
timely provide PGET with certain information to make a necessary FERC filing.
While LEP does not agree with PGET's interpretation of the tolling agreement
regarding the dispatch issue, LEP agreed to (a) compensate PGET approximately
$17,000 for the alleged damages attributable to the claims raised in the August
19, 2002 letter and (b) treat several hours of plant outages as forced outages
for purposes of the tolling agreement, thereby resolving the issues raised in
the August 19 letter (which compensation and treatment are not believed to be
material). The tolling agreement generally provides that covenant-related
defaults must be cured within 30 business days or they will (if material) result
in an event of default, entitling the non-defaulting party to terminate. PGET
has extended this cure period (relating to the September 10, 2002 letter) to
June 9, 2003. LEP has made the necessary FERC filing and is in negotiations with
PGET regarding financial settlement for this issue for approximately $1 million.
Further, LEP also believes that it has settled the monetary impact of any
violation relating to the dispatch issue. While there can be no assurances as to
the outcome of this matter, LEP believes that it will be able to resolve the
issues raised in the September 10, 2002 letter without causing an event of
default under the tolling agreement. However, if LEP is unable to resolve the
issues and PGET declares an event of default, then PGET would be in a position
to terminate the tolling agreement. In addition to the material adverse effect
such a termination would have on Liberty as discussed below, such a termination
would give PGET the right to draw, to the extent it had suffered any damages, on
the $35 million letter of credit posted by Reliant Resources on behalf of LEP
under the tolling agreement.

LEP currently receives a fixed monthly payment from PGET under the
tolling agreement. If the tolling agreement is terminated, (a) LEP would need to
find a power purchaser or tolling customer to replace PGET or sell the energy
and/or capacity in the merchant energy market and (b) the gas transportation
agreement that PGET utilizes in connection with the tolling agreement will
revert to LEP, and LEP will be required to perform the obligations currently
being performed by PGET under the gas transportation agreement, including the
posting of $5 million in credit support.

No assurance can be given that LEP would have sufficient cash flow to
pay all of its expenses or enable Liberty to make interest and scheduled
principal payments under the Liberty credit facility as they become due if the
tolling agreement is terminated. The termination of the tolling agreement may
cause both Liberty and LEP to seek other alternatives, including reorganization
under the bankruptcy laws. We, including Orion Power, would not be in default
under our other current debt agreements if any of these events occur at Liberty.

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.

In December 2002, we evaluated the Liberty station and the related
tolling agreement for impairment. Based on our analyses, there were no
impairments. The fair value of Liberty station was determined based on an income
approach, using future discounted cash flows; a market approach, using
acquisition multiples, including price per MW, based on publicly available data
for recently completed transactions; and a replacement cost approach. If the
tolling agreement is terminated and there is not a waiver from the lenders for
this event of default, it is possible the lender would initiate foreclosure
proceedings against LEP and Liberty. If the lenders foreclose on LEP and
Liberty, we believe we could incur a pre-tax loss of an amount up to our
recorded net book value with the potential of an additional loss due to an
impairment of goodwill allocated to LEP as a result of the foreclosure. Under
the tolling agreement, a non-defaulting party who terminates the tolling
agreement is entitled to calculate its damages in

35

accordance with specified criteria; the non-defaulting party is the only party
entitled to damages. The defaulting party would be entitled to refer such damage
calculation to arbitration. The institution of any arbitration could delay the
receipt of such damages for an extended period of time. In addition, if PGET is
the defaulting party, the payment of damages, if any, could be further delayed
if PGET and one or more of the guarantors of PGET's obligations seeks protection
from creditors under the bankruptcy laws. Such filings also may result in LEP
receiving significantly less in damages than to which it might otherwise be
entitled. In the event of a termination, if PGET is the defaulting party and LEP
is entitled to the payment of damages as a result of the termination, any
amounts recovered from PGET would be handled in accordance with the Liberty
credit facility. The most likely result is that the damages would be paid into
an account that is managed by the lenders under the credit facility and LEP
would not recover any of such damages.

(14) RECEIVABLES FACILITY

In July 2002, we entered into a receivables facility arrangement with a
financial institution to sell an undivided interest in our accounts receivable
and accrued unbilled revenues from residential and small commercial retail
electric customers under which, on an ongoing basis, the financial institution
could invest a maximum of $250 million for its interest in such receivables. In
November 2002, the maximum amount of the receivables facility was reduced to
$200 million. In February 2003, this was further reduced to $125 million (see
below). The receivables facility may be increased on a seasonal basis, subject
to the availability of receivables and approval by the participating financial
institution.

This receivables facility expires in July 2003 and may be renewed at
our option and the option of the financial institution participating in the
facility. If the receivables facility is not renewed on its termination date,
the collections from the receivables purchased will repay the financial
institution's investment and no new receivables will be purchased under the
receivables facility. There can be no assurance that the financial institution
participating in the receivables facility will agree to a renewal.

We received net proceeds in an initial amount of $230 million at the
inception of this receivables facility. The amount of funding available to us
under the receivables facility will fluctuate based on the amount of receivables
available, which in turn, is affected by seasonal changes in demand for
electricity and by the performance of the receivables portfolio. As of December
31, 2002 and March 31, 2003, the amount of funding outstanding under our
receivables facility was $95 million and $84 million, respectively.

Pursuant to the receivables facility, we formed a qualified special
purpose entity (QSPE), as a bankruptcy remote subsidiary. The QSPE was formed
for the sole purpose of buying and selling receivables generated by us. The QSPE
is a separate entity and its assets will be available first and foremost to
satisfy the claims of its creditors. We, irrevocably and without recourse,
transfer receivables to the QSPE. We continue to service the receivables and
receive a fee of 0.5% of cash collected. We received total fees of $3 million
for the three months ended March 31, 2003. We have no servicing assets or
liabilities, because servicing fees are based on actual costs associated with
collection of accounts receivable. The QSPE, in turn, sells an undivided
interest in these receivables to the participating financial institution. We are
not ultimately liable for any failure of payment of the obligors on the
receivables. We have, however, guaranteed the performance obligations of the
sellers and the servicing of the receivables under the related documents.

The two-step transaction described in the above paragraph is accounted
for as a sale of receivables under the provisions of SFAS No. 140, "Accounting
for Transfers and Servicing of Financial Assets and Extinguishments of
Liabilities," and as a result the related receivables are excluded from the
consolidated balance sheet. Cost associated with the sale of receivables, $3
million for the three months ended March 31, 2003, primarily the discount and
loss on sale, is included in other expense in our statement of consolidated
operations. As of December 31, 2002 and March 31, 2003, $277 million and $201
million, respectively, of the outstanding receivables had been sold and the
sales have been reflected as a reduction of accounts receivable in our
consolidated balance sheets. We have notes receivable from the QSPE of
approximately $170 million and $96 million at December 31, 2002 and March 31,
2003, respectively, which are included in our consolidated balance sheets. These
notes are calculated as the amount of receivables sold to the QSPE, less the
interest in the receivables sold by the QSPE to the financial institution, and
the equity investment in the QSPE, which is equal to 3% of the receivables
balance. At December 31, 2002 and March 31, 2003, the equity investment balance
was $8 million and $6 million, respectively. These notes were pledged to the
lenders in the March 2003 refinancing of certain of our credit facilities, see
note 10.

36

The book value of the accounts receivable is offset by the amount of
the allowance for doubtful accounts and customer security deposits. A discount
rate of 5.03% was applied to projected cash collections over a 6-month period.
Our collection experience indicated that 98% of the accounts receivables would
be collected within a 6-month period.

On December 2, 2002, we notified the financial institution under the
receivables facility of two violations of certain compliance ratio tests that
are considered amortization events whereby the financial institution has the
right to liquidate the receivables it owns to collect the total amount
outstanding under the terms of the receivables facility. On February 7, 2003, we
were granted an amendment to our receivables facility and a waiver of these two
compliance ratio violations from the financial institution. As part of the
amendment and waiver, the maximum amount of the receivables facility was reduced
from $200 million to $125 million.

In addition, an amortization event was added that required us to attain
by February 17, 2003 either: (a) a consensual refinancing of certain credit
facilities or (b) another financing commitment. We received waivers of this
amortization event until March 31, 2003; our March 2003 refinancing satisfied
this condition (see note 10).

(15) BANKRUPTCY OF ENRON CORP AND ITS AFFILIATES

During the fourth quarter of 2001, Enron filed a voluntary petition for
bankruptcy. Accordingly, we recorded an $85 million provision, comprised of
provisions against 100% of receivables of $88 million and net non-trading
derivative balances of $52 million, offset by our net trading and marketing
liabilities to Enron of $55 million.

The non-trading derivatives with Enron were designated as cash flow
hedges (see note 8). The unrealized net gain on these derivative instruments
previously reported in other comprehensive income will remain in accumulated
other comprehensive loss and will be reclassified into earnings during the
period in which the originally designated hedged transactions occur. During the
three months ended March 31, 2002 and 2003, $13 million gain and $2 million
loss, respectively, was reclassified into earnings related to these cash flow
hedges.

In early 2002, we commenced an action in the United States District
Court to recover from Enron Canada Corp., the only Enron party to our netting
agreement which is not in bankruptcy, the settlement amount of $78 million,
which resulted from netting amounts owed by and among the five Enron parties and
our applicable subsidiaries. In March 2002, the United States District Court
dismissed our claim and we appealed the decision to the United States Court of
Appeals for the Fifth Circuit (the Fifth Circuit). Oral arguments were heard in
March 2003.

At this time we cannot predict whether our appeal will be successful.
The United States District Court, however, did determine that netting of amounts
owed by and among our parties and the Enron parties was proper. This portion of
the United States District Court's ruling has not been appealed. In other
proceedings initiated by Enron in the Bankruptcy Court for the Southern District
of New York, Enron is alleging that netting agreements, such as the one it
signed with us, are unenforceable. This contention is not currently at issue in
our appeal pending in the Fifth Circuit. In January 2003, Enron filed a
complaint in the Bankruptcy Court of Southern District New York claiming that it
is owed $13 million from us and disputing the enforceability of our netting
agreement. Our answer to the Enron complaint was filed in April 2003, asserting
that our netting agreement with the Enron entities is enforceable as found by
the United States District Court.

(16) DISCONTINUED OPERATIONS - SALE 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. Upon
consummation of the sale, we expect to receive cash proceeds from the sale of
approximately $1.2 billion (Euro 1.1 billion). As additional contingent
consideration for the sale, we will also receive 90% of the dividends and other
distributions in excess, if any, of approximately $120 million (Euro 110
million) paid by NEA B.V. (NEA) to Reliant Energy Power Generation Benelux, N.V.
(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 (Euro 115 million). If the
amount of net cash is less on such date, the purchase price will be reduced
accordingly. The sales price is denominated in Euros; however, we have hedged
our foreign currency exposure of our net investment in our European energy
operations. See below for further discussion of the hedges.

37

We intend to use the cash proceeds from the sale first to prepay the
Euro 600 million bank term loan borrowed by Reliant Energy Capital (Europe),
Inc. (RECE) to finance a portion of the original acquisition costs of our
European energy operations. The maturity date of the credit facility, which
originally was scheduled to mature in March 2003, has been extended, as
described below. If we exercise the option to acquire Texas Genco in 2004, we
intend to use the remaining cash proceeds of approximately $0.5 billion (Euro
0.5 billion) to partially fund the exercise of this option. However, if we elect
not to exercise the option, we must use the remaining cash proceeds to prepay
debt.

The sale is subject to the approval of the Dutch competition authority.
The German competition authority approved the sale on May 5, 2003. We anticipate
that the consummation of the sale will occur in the summer of 2003. No assurance
can be given that we will obtain the approval of the Dutch competition authority
or that such approval can be obtained in a timely manner.

We recognized an estimated loss on disposition of $384 million in the
three months ended March 31, 2003 in connection with the anticipated sale. We do
not anticipate that there will be a Dutch or United States income tax benefit
realized by us as a result of this loss. This loss represents an estimate and
could change based on (a) changes in the foreign currency exchange rate from
March 31, 2003 to the date of sale, (b) changes in intercompany balances from
March 31, 2003 to the date of sale and (c) other various factors. We will
recognize contingent payments, if any, (as discussed above) in earnings upon
receipt. In the first quarter of 2003, we began to report the results of our
European energy operations as discontinued operations in accordance with SFAS
No. 144 and accordingly reclassified amounts for the previous period. For
information regarding goodwill impairments of our European energy segment
recognized in the first and fourth quarters of 2002 of $234 million and $482
million, respectively, see note 7.

Assets and liabilities related to discontinued operations were as
follows:

Revenues and pre-tax income (loss) related to discontinued operations
were as follows:

38

In March 2003, we incrementally hedged our net investment in our
European energy operations to Euro 1.1 billion by purchasing Euro 520 million of
foreign currency options, which expire in June 2003.

In February 2000, one of our subsidiaries, RECE, established a Euro 600
million term loan facility that was to terminate in March 2003. At December 31,
2002 and March 31, 2003, $630 million and $655 million, respectively, under this
facility was outstanding and is included in liabilities of discontinued
operations in our consolidated balance sheets. The facility bore interest at the
inter-bank offered rate for Euros (EURIBOR) plus 1.25%. This facility is secured
by a pledge of the shares of REPGB's indirect holding company. Borrowings under
this facility are non-recourse to Reliant Resources. This facility contains
affirmative and negative covenants, including a negative pledge.

In March 2003, we reached an agreement with our lenders to extend the
maturity date of the Euro 600 million bank term loan facility of RECE,
originally scheduled to mature on March 3, 2003. Based on the terms of the
extension, we will repay this term loan on the first to occur of (a) completion
of the above mentioned sale of our European energy operations to Nuon, (b)
December 31, 2003 and (c) the earlier of the maturity dates of the two REPGB
facilities, which are both July 2003, as they may be extended. If the sale of
our European energy operations does not occur prior to July 2003, we will be
required to repay this term loan in July 2003 unless prior to that date we are
able to obtain an extension of REPGB's credit facilities. If the sale of our
European energy operations does not close prior to the maturity of these
facilities, REPGB anticipates extending these credit facilities.

In order to extend the Euro 600 million facility, we provided the
following additional security to the lenders:

o a guarantee of the facility from Reliant Energy Europe, Inc.;

o security over certain intercompany payables from our European
energy operations (a portion of which will be repaid at
consummation of the sale) and the bank accounts into which
Nuon will deposit the cash proceeds of the sale; and

o a pledge of 65% of the shares in Reliant Energy Europe B.V.,
the holding company of our European energy operations, which
pledge will be released upon the consummation of the sale.

In addition, we agreed to increase the interest rate under this credit
facility to EURIBOR plus a margin of 4.0% per year, 2.0% of which is payable
monthly and 2.0% of which will be paid in the event that the sale of our
European energy operations to Nuon does not occur. We pre-funded interest under
the facility through a security account, initially in an amount of approximately
$18 million (Euro 17 million) and, thereafter, we will replenish this account in
an amount equal to at least two months' interest under the facility. This
extension requires RECE to maintain an interest coverage ratio of not less than
4.50 to 1.00 and provides that capital expenditures may not exceed Euro 41.3
million (approximately $45 million) during the year ending December 31, 2003.

The REPGB credit facilities consist of (a) a Euro 184 million
(approximately $202 million) 364-day revolving credit facility and (b) a
three-year letter of credit facility for $420 million, both scheduled to expire
in July 2003. The revolving credit facility contains an option that allows REPGB
to utilize up to Euro 100 million (approximately $109 million) for letters of
credit. Under the two facilities, there is no recourse to Reliant Resources.

At December 31, 2002 and March 31, 2003, there were no borrowings
outstanding under the 364-day revolving credit facility. At December 31, 2002,
and March 31, 2003, there were $18 and $12 million, respectively, of letters of
credit outstanding under the 364-day revolving credit facility. At December 31,
2002, and March 31, 2003, under the $420 million letter of credit facility,
letters of credit of $355 million and $363 million, respectively, were
outstanding under the facility.

39

Additional outstanding long-term indebtedness of REPGB of $38 million
at December 31, 2002, and March 31, 2003, consisted primarily of medium term
notes and loans maturing through 2006. This debt is unsecured and non-recourse
to Reliant Resources.

With the closing of the sale to Nuon, the REPGB bank facilities and
debt will remain the obligations of REPGB.

(17) REPORTABLE SEGMENTS

We have identified the following reportable segments: retail energy,
wholesale energy and other operations. For descriptions of the financial
reporting segments, see note 1 to our Form 10-K/A. In February 2003, we signed
an agreement to sell our European energy operations and have classified that as
discontinued operations. See note 16 for further discussion. Our determination
of reportable segments considers the strategic operating units under which we
manage sales, allocate resources and assess performance of various products and
services to wholesale or retail customers. Financial information for Orion Power
is included in the segment disclosures only for periods beginning on the
acquisition date. Beginning in the first quarter of 2002, we began to evaluate
segment performance on earnings (loss) before interest expense, interest income
and income taxes (EBIT). EBIT is not defined under GAAP, and should not be
considered in isolation or as a substitute for a measure of performance prepared
in accordance with GAAP and is not indicative of operating income (loss) from
operations as determined under GAAP.

Effective January 1, 2003, we began reporting our ERCOT generation
facilities, which consists of seven power generation units at two facilities
with an aggregate net generation capacity of 805 MW located in Texas, in our
retail energy segment rather than our wholesale energy segment. We include our
ERCOT generation facilities in our retail energy segment for segment reporting
because energy from those assets is primarily used to serve retail energy
segment customers. Reportable segments from prior periods have been reclassified
to conform to the 2003 presentation.

40

Financial data for business segments (excluding items related to our
discontinued operations, other than total assets) are as follows:

* * *

41

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

RESTATEMENT

Subsequent to the issuance of our financial statements for the first
three quarters of 2002, we determined that we had incorrectly calculated the
amount of hedge ineffectiveness for 2001 and the first three quarters of 2002
for hedging instruments entered into prior to the adoption of SFAS No. 133.
These hedging instruments included long-term forward contracts for the sale of
power in the California market through December 2006. The amount of hedge
ineffectiveness for these forward contracts was calculated using the trade date.
However, the proper date for the hedge ineffectiveness calculation is hedge
inception, which for these contracts was deemed to be January 1, 2001,
concurrent with the adoption of SFAS No. 133. This restatement in accounting for
hedge ineffectiveness resulted in a reduction of revenues of $1.1 million ($0.7
million after-tax) for the three months ended March 31, 2002. A summary of the
principal effects of the restatement for the three months ended March 31, 2002
is set forth in note 1 to our interim financial statements. The following
discussion and analysis has been modified for the restatement.

OVERVIEW

We provide electricity and energy services with a focus on the
competitive retail and wholesale segments of the electric power industry in the
United States. We have built a portfolio of electric power generation
facilities, through a combination of acquisitions and development that are not
subject to traditional cost-based regulation; therefore, we can generally sell
electricity at prices determined by the market, subject to regulatory
limitations. We trade and market electricity, natural gas, natural gas
transportation capacity and other energy-related commodities. We also optimize
our physical assets and provide risk management services for our asset
portfolio. In March 2003, we decided to exit our proprietary trading activities
and liquidate, to the extent practicable, our proprietary positions. Although we
are exiting the proprietary trading business, we have existing positions, which
will be closed as economically feasible or in accordance with their terms. We
will continue to engage in hedging activities and commercial transactions
related to our electric generating facilities, pipeline storage positions and
fuel positions of our wholesale energy segment and energy supply costs related
to our retail energy segment.

In this section we discuss our results of operations on a consolidated
basis and on a segment basis for each of our financial reporting segments. We
also discuss our financial condition. Our segments include retail energy,
wholesale energy and other operations. For segment reporting information, see
note 17 to our interim financial statements.

In February 2002, we acquired all of the outstanding shares of common
stock of Orion Power for an aggregate purchase price of $2.9 billion and we
assumed $2.4 billion in debt obligations. For additional information regarding
our acquisition of Orion Power, see note 6 to our interim financial statements.

During the first quarter of 2003, the following factors, among others,
continued to negatively impact our business:

o narrowing of the spark spread (difference between power prices
and natural gas fuel costs) in most regions of the United
States in which we operate generation facilities;

o market contraction;

o reduced liquidity in the United States power markets; and

o our credit ratings continuing to be below investment grade as
rated by each of the major rating agencies.

We expect these weak conditions to persist through 2003. However, in
the next few years we anticipate that supply surpluses will begin to tighten,
regulatory intervention will become more balanced and as a result prices will
improve for electric energy, capacity and ancillary services. This view is
consistent with our fundamental belief that long run market prices must reach
levels sufficient to support an adequate rate of return on the construction of
new generation. However, if in the long term the current weak environment
persists, we could have significant impairments of our property, plant and
equipment and goodwill which, in turn, could have a material adverse effect on
our results of operations.

42

In addition, our operations are impacted by changes in commodities
other than electric energy, in particular by changes in natural gas prices.
During the three months ended March 31, 2003, there continued to be significant
volatility in the natural gas market. As a result, we realized a trading loss
related to certain of our natural gas trading positions of approximately $80
million pre-tax during the three months ended March 31, 2003. Our wholesale
energy segment's results from its unhedged coal-fired generation capacity in the
Mid-Atlantic region are impacted by natural gas prices as electric energy prices
are affected by changes in natural gas prices and coal prices are substantially
uncorrelated to gas prices. In addition, we can optimize the fuel costs of our
dual fuel generating assets by running the most cost-efficient fuel. Our retail
energy segment can also be impacted by changes in natural gas prices. The PUCT's
regulations allow an affiliated retail electric provider to adjust the wholesale
energy supply cost component or "fuel factor," included in its price to beat
based on a percentage change in the forward price of natural gas and purchased
energy. An affiliated retail electric provider may request that its price to
beat fuel factor be adjusted twice a year. We cannot estimate with any certainty
the magnitude and timing of future adjustments required, if any, or the impact
of such adjustments on our headroom (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). For additional information regarding adjustments to our
price to beat fuel factor, see "Management's Discussion and Analysis of
Financial Condition and Results of Operations - EBIT by Business Segment." To
the extent there are future changes in natural gas prices, our results of
operations, financial condition and cash flows will be affected.

In February 2003, we signed an agreement to sell our European energy
operations to Nuon, a Netherlands-based electricity distributor. We recognized
an estimated loss on disposition of $384 million for the three months ended
March 31, 2003 in connection with the anticipated sale. We do not anticipate
that there will be a Dutch or United States income tax benefit realized by us as
a result of this loss. We will recognize contingent payments, if any, in
earnings upon receipt. In the three months ended March 31, 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 16 to our interim
financial statements.

In connection with the resignation of the chief executive officer and
the general counsel in the second quarter of 2003, we will recognize a pre-tax
charge to earnings. We currently estimate that such charge will be approximately
$15 million. This estimate includes the following items: $11 million in cash
payments and $4 million related to the modification of stock-based awards.

CONSOLIDATED RESULTS OF OPERATIONS

The following table provides summary data regarding our consolidated
results of operations for the three months ended March 31, 2002 and 2003:

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

(1) Total revenues reflect trading activities on a net basis.

Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2003.

Net Loss. We reported a $(452) million consolidated net loss, or
$(1.55) loss per share, for the three months ended March 31, 2003 compared to
$(138) million consolidated net loss, or $(0.48) loss per diluted share, for the
three months ended March 31, 2002. The $314 million increase in net loss was
primarily due to:

43

o a $396 million decrease in income/loss from discontinued
operations, which includes an estimated loss on disposition of
$384 million recognized during the three months ended March
31, 2003 due to the anticipated sale of our European energy
operations (see note 16 to our interim financial statements);

o a $111 million decrease in EBIT from our wholesale energy
segment;

o a $68 million increase in interest expense;

o a $23 million decrease in EBIT from our retail energy segment;
and

o a $25 million cumulative effect of accounting change, net of
tax, recorded in 2003 relating to EITF No. 02-03 and the
adoption of SFAS No. 143 and FIN No. 46 in January 2003 (see
note 2 to our interim financial statements).

This increase to the net loss was partially offset by a $234 million
cumulative effect of accounting change, net of tax, recorded in 2002 related to
the adoption of SFAS No. 142 (see note 7 to our interim financial statements).

EBIT. For an explanation of changes in EBIT, see "- EBIT by Business
Segment."

Interest Expense. We incurred $29 million of interest expense during
the three months ended March 31, 2002 compared to $97 million in the same period
of 2003. The $68 million increase in interest expense to third parties in 2003
as compared to 2002 resulted primarily from a $68 million increase in interest
expense to third parties, net of interest expense capitalized on projects,
primarily as a result of higher levels of borrowings related to the acquisition
of Orion Power in February 2002. Included in this increase is $10 million of
financing costs expensed during the three months ended March 31, 2003.

Interest Income. We recognized interest income from third parties of
$14 million for the three months ended March 31, 2003 as compared to $2 million
for the same period in 2002. The increase is primarily due to $9 million of
interest income recognized on our refunds due to us related to energy sales in
California (see note 13(e) to our interim financial statements).

Income Tax Expense. During the three months ended March 31, 2002 and
2003, our effective tax rate was 36.0% and 29.5%, respectively. Our reconciling
items from the federal statutory rate of 35% to the effective tax rate totaled
$1 million for the three months ended March 31, 2002. These items primarily
related to state income taxes. Our reconciling items from the federal statutory
rate of 35% to the effective tax rate totaled $4 million for the three months
ended March 31, 2003. These items primarily related to increases in tax reserves
and revisions in the estimated tax rates partially offset by state income tax
benefits.

Cumulative Effect of Accounting Changes. During the three months ended
March 31, 2002, we recognized a cumulative effect of accounting change of $(234)
million loss, net of tax, related to the adoption of SFAS No. 142. For
discussion of the adoption of SFAS No. 142, see note 7 to our interim financial
statements. During the three months ended March 31, 2003, we recognized a
cumulative effect of accounting change of $19 million gain, net of tax, related
to the adoption of SFAS No. 143, $(43) million loss, net of tax, related to the
adoption EITF No. 02-03, and $(1) million loss, net of tax, related to the
adoption of FIN No. 46. For discussion of the adoption of SFAS No. 143, EITF No.
02-03 and FIN No. 46, see note 2 to our interim financial statements.

EBIT BY BUSINESS SEGMENT

The following tables present operating income (loss) and EBIT for each
of our business segments, which are reconciled on a consolidated basis to our
net loss, for the three months ended March 31, 2002 and 2003. EBIT is the
primary measurement used by our management to evaluate segment performance. EBIT
is not defined under GAAP, should not be considered in isolation or as a
substitute for a measure of performance prepared in accordance with GAAP and is
not indicative of operating income from operations as determined under GAAP.
Items excluded from EBIT are significant components in understanding and
assessing our financial performance. Additionally, our computation of EBIT may
not be comparable to other similarly titled measures computed by other
companies,

44

because all companies do not calculate it in the same fashion. For a
reconciliation of our operating income (loss) to EBIT and EBIT to net income
(loss), see note 17 to our interim financial statements. For a reconciliation of
our operating income (loss) to EBIT by segment, see the related discussion by
segment below.

We historically operated in four business segments: wholesale energy,
retail energy, European energy and other operations. In accordance with SFAS No.
144, our European energy operations are reported as discontinued operations as a
result of the expected sale announced in February 2003. In addition, effective
January 1, 2003, we began reporting our ERCOT generation facilities, which
consists of seven power generation units at two facilities with an aggregate net
generation capacity of 805 MW located in Texas, in our retail energy segment
rather than our wholesale energy segment. We include our ERCOT generation
facilities in our retail energy segment for segment reporting because energy
from those assets is primarily used to serve retail energy segment customers.
Reportable segments from prior periods have been reclassified to conform to the
2003 presentation.

The following tables set forth our operating income (loss) and EBIT by
segment for the three months ended March 31, 2002 and 2003 reconciled to our
consolidated net loss:

RETAIL ENERGY

Our retail energy segment provides electricity products and services to
end-use customers, ranging from residential and small commercial customers to
large commercial, industrial and institutional customers. Our retail energy
segment acquires and manages the electric energy, capacity and ancillary
services associated with supplying these retail customers. For further
information regarding our contract to purchase supply from Texas Genco, see note
4 to our interim financial statements. We began serving approximately 1.7
million electric customers in the Houston metropolitan area when the Texas
market opened to full competition in January 2002. We also began serving
customers in other areas of Texas, principally Dallas/Fort Worth and Corpus
Christi, which we obtained through our marketing efforts. At the end of March
2003, our customer count remained substantially the same as compared to March
2002; however, our retail energy segment lost market share in the Houston market
but added customers in other areas of Texas. During 2002, our retail energy
segment's operational efforts were largely focused on the extensive efforts
necessary to transition customers from the electric utilities to the affiliated
retail electric providers.

We record gross revenue for energy sales and services to residential,
small commercial and non-contracted large commercial, industrial and
institutional retail electric customers under the accrual method and these
revenues generally are recognized upon delivery. Our contracted electricity
sales to large commercial, industrial and institutional customers for contracts
entered into after October 25, 2002 are typically accounted for under the
accrual method and these revenues generally are recognized upon delivery. Prior
to 2003, our retail energy segment's contracted electricity sales to large
commercial, industrial and institutional customers and the related energy supply
contracts for contracts entered into prior to October 25, 2002 were accounted
for under the mark-to-market method of accounting. Under the mark-to-market
method of accounting, these contractual commitments were recorded at fair value
in revenues on a net basis upon contract execution. The net changes in their
fair values were recognized in the statements of consolidated operations as
revenues on a net basis in the period of change through 2002. Effective January
1, 2003, we no longer mark to market in earnings these electricity sales
contracts and a substantial portion of the related energy supply contracts in
connection with the implementation of EITF No. 02-03. The related revenues and
purchased power are recorded on a gross basis in our results of operations (see
note 2).

Due to the implementation of EITF No. 02-03, the results of operations
related to our contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts for contracts
entered into prior to October 25, 2002 are not comparable between the three
months ended March 31, 2002 and 2003. During the three months ended March 31,
2002, our retail energy segment recognized $2 million of losses related to its
contracted electricity sales to large commercial, industrial and institutional
customers and the related energy supply contracts. During the three months ended
March 31, 2003, volumes were delivered under contracted

46

electricity sales to large commercial, industrial and institutional customers
and the related energy supply contracts in which $20 million was previously
recognized in unrealized earnings in prior periods. As of March 31, 2003, our
retail energy segment has unrealized gains that have been previously recorded in
our results of operations of $83 million that will be realized when the
electricity is delivered to our customers ($54 million in the remainder of 2003
and $29 million in 2004 and beyond). These unrealized gains of $83 million are
recorded in non-trading derivative assets/liabilities in our consolidated
balance sheet as of March 31, 2003.

Electricity sales and services related to retail customers not billed
are recognized based upon estimated electricity delivered. At the end of each
month, amounts of energy delivered to customers since the date of the last meter
reading are estimated and the corresponding unbilled revenue is estimated. At
March 31, 2003, the amount of unbilled revenue was $277 million. Included in
that amount is approximately $25 million related to delayed billings, which are
invoices that have not been rendered to customers because of problems obtaining
all the necessary information required to calculate the bill. Problems or delays
in the flow of information between the ERCOT Independent System Operator (ISO),
the transmission and distribution utility and the retail electric providers and
operational problems with our new systems and processes could impact our ability
to accurately estimate the amount not billed at March 31, 2003. For further
information regarding recognition of unbilled revenues, see "Management
Discussion and Analysis of Financial Condition and Results of Operations -
Critical Accounting Estimates" in Item 7 and note 2(d) to our Form 10-K/A.

We depend on the transmission and distribution utilities to read our
customers' electric meters. We are required to rely on the transmission and
distribution utility or, in some cases, the ERCOT ISO, to provide us with our
customers' information regarding electricity usage, including historical usage
patterns, and we may be limited in our ability to confirm the accuracy of the
information. The receipt of inaccurate or delayed information from the
transmission and distribution utilities or the ERCOT ISO could have a material
negative impact on our business, results of operations and cash flows.

We record our transmission and distribution charges using the same
method discussed above for our electricity sales and services to retail
customers. At March 31, 2003, the transmission and distribution charges not
billed by the transmission and distribution utilities to us, which we accrued
during the period, totaled $48 million. Delays or inaccurate billings from the
transmission and distribution utilities could impact our ability to accurately
reflect our transmission and distribution costs.

The ERCOT ISO is responsible for maintaining reliable operations of the
electric power supply system in the ERCOT Region. The ERCOT ISO is also
responsible for handling scheduling and settlement for all electricity volumes
and related fees in the Texas deregulated electricity market. As part of
settlement, the ERCOT ISO communicates the actual volumes compared to the
scheduled volumes. The ERCOT ISO calculates an additional charge or credit by
calculating the difference between the actual and scheduled volumes multiplied
by the market clearing price. The ERCOT ISO also charges customer-serving market
participants fees such as administrative fees and energy and replacement
capacity fees. Most of these fees are determined by the actions in the entire
market. The ERCOT ISO allocates many of these fees to market participants based
on each market participant's share of the total load. Preliminary settlement
information is due from the ERCOT ISO within two months after electricity is
delivered. Final settlement information is due from the ERCOT ISO within twelve
months after electricity is delivered. As a result, we record our estimated
supply costs and related fees using estimated supply volumes and adjust those
costs upon receipt of settlement and consumption information. The ERCOT ISO
settlement process was delayed due to operational problems between the ERCOT
ISO, the transmission and distribution utilities and the retail electric
providers. During the third quarter of 2002, the ERCOT ISO issued final
settlements for the pilot time period of July 31, 2001 to December 31, 2001. The
final settlements for periods after January 1, 2002, have been suspended until a
market synchronization of all customers between the market participants takes
place. The market synchronization will validate which retail electric provider
served each customer, for each day, beginning as of January 1, 2002, which was
the date the market opened to retail competition. This information will be
confirmed by the ERCOT ISO, the retail electric providers and the transmission
and distribution utilities. Once this market synchronization is complete, the
ERCOT ISO will resume the final settlement process beginning with January 1,
2002. The final settlement process is scheduled to resume in May 2003. The delay
in the ERCOT ISO settlement process could impact our ability to accurately
reflect our energy supply costs and related fees.

We believe that the estimates and assumptions utilized for the above
items to recognize revenues and supply costs, as applicable, are reasonable and
represent our best estimates. However, actual results could differ from those
estimates. During the first quarter of 2003, we revised our estimates and
assumptions, as additional information was received, related to prior periods
and accordingly, recognized approximately $21 million in income in our operating
results.

47

We expect to continue to lose residential and small commercial market
share in the Houston market during 2003, as competition increases. We expect to
continue to gain residential and small commercial market share in other areas of
the state. During the first quarter of 2003, our gains in other areas of the
state offset our losses in the Houston area. Our continuing efforts to seek such
gains are likely to require us to increase our spending for marketing and
advertising. We expect to continue to increase our market share of large
commercial, industrial and institutional customers in the ERCOT Region.

During 2002, we filed two requests with the PUCT to increase the price
to beat fuel factor for residential and small commercial customers based on
increases in the price of natural gas. The August 2002 increase was based on an
increase in the natural gas price from $3.11 per MMbtu to $3.73 per MMbtu. The
December 2002 increase was based on a natural gas price of $4.02 per MMbtu. In
March 2003, the PUCT approved our request to increase the price to beat fuel
factor for residential and small commercial customers based on a 23.4% increase
in the price of natural gas from our previous increase in December 2002. The
approved increase was based on natural gas prices of $4.956 per MMbtu. The
increase represented an 8.2% increase in the total bill of a residential
customer using, on average, 12,000 KWh per year. As of May 1, 2003, the
applicable natural gas price benchmark was $5.435 per MMbtu, which represents an
increase of 9.7% in the price of natural gas that had been used to calculate our
previous increase in March 2003. For further information about the price to beat
fuel factor, see our Form 10-K/A.

48

The following table provides summary data, including EBIT, of our
retail energy segment for the three months ended March 31, 2002 and 2003:

Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2003.

EBIT. Our retail energy segment's EBIT decreased $23 million for the
three months ended March 31, 2003 compared to the same period in 2002. The
decrease is primarily due to the following:

o $47 million accrual for payment to CenterPoint, as discussed
below; and

o $36 million increase in costs, as discussed below.

The decrease was offset by $60 million in increased margins (revenues
less fuel and purchased power), as described below.

In January 2002, customers were transferred throughout the months from
the local utility company, and accordingly there was not a full three months of
revenues and related purchased power. Similarly, many costs, such as salaries
and customer related expenses, experienced an increase during the first several
months of 2002 as normal operating levels were reached, resulting in an increase
for the three months ended March 31, 2003 compared to the same period in 2002.
In addition, most of the ERCOT generation units began commercial operations
after the three months ended March 31, 2002, so earnings from full plant
operations were in EBIT during the three months ended March 31, 2003, while
there was only minimal EBIT contributions from the ERCOT generation facilities
during the same period in 2002.

49

Electricity sales volumes during the three months ended March 31, 2003
were relatively flat compared to the same period in 2002, at approximately
12,800 GWh. The increase in sales volumes period-over-period resulting from
transitioning customers during the three months ended March 31, 2002, as
discussed above, coupled with the addition of out-of-territory customers, were
substantially offset by the loss of Houston market customers and sales.

Total Revenues. Total revenues increased $812 million for the three
months ended March 31, 2003 compared to the same period in 2002 primarily due to
the following:

o $429 million of revenues for contracted commercial, industrial
and institutional customers due to a change in the method of
accounting, as discussed above. These revenues and the related
purchased power were recorded net in trading margins during
2002, and are now reported on a gross basis in 2003;

o $203 million of revenues from an increase in the price-to-beat
revenue rate for residential and small commercial customers,
as well as from an increase in large commercial, industrial
and institutional customers' rates that are indexed to the
price of natural gas;

o $91 million of supply management revenues related to the risk
management, hedging, and optimizing of our electric energy
supply; and

o $89 million of increased revenues from our ERCOT generation
facilities, as units began commercial operations after the
three months ended March 31, 2002.

Fuel and Purchased Power. Fuel and purchased power expenses increased
$752 million for the three months ended March 31, 2003 compared to the same
period in 2002 primarily due to the following:

o $429 million of increased purchased power related to the
change in method of recording revenues and purchased power, as
discussed above;

o $245 million of increased purchased power, primarily driven by
gas price increases; and

o $78 million of increased fuel costs for our ERCOT generation
facilities, which units began commercial operations after the
three months ended March 31, 2002.

Margins. Our retail energy segment's margins increased $60 million for
the three months ended March 31, 2003 compared to the same period in 2002
primarily due to the following:

o $33 million from sales to electricity customers, primarily
residential customers and to a lesser extent large commercial,
industrial and institutional customers, and the related supply
costs;

o $16 million from revised estimates for electric sales related
to prior periods, as discussed above; and

o $11 million of increased contributions from our ERCOT
generation facilities.

Due to the implementation of EITF No. 02-03, the results of operations
related to our contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts for contracts
entered into prior to October 25, 2002 are not comparable between the three
months ended March 31, 2002 and 2003. Prior to 2003, our retail energy segment's
contracted electricity sales to large commercial, industrial and institutional
customers and the related energy supply contracts for contracts entered into
prior to October 25, 2002 were accounted for under the mark-to-market method of
accounting. Effective January 1, 2003, we no longer mark to market in earnings a
substantial portion of these contracts and the related energy supply contracts
in connection with the implementation of EITF No. 02-03. For the impact on
margins, see discussion regarding EITF No. 02-03 above.

50

Accrual for Payment to CenterPoint. To the extent that our price to
beat for electric service to residential and small commercial customers in
CenterPoint's Houston service territory during 2002 and 2003 exceeds the market
price of electricity, we may be required to make a payment to CenterPoint in
2004. As of 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. We accrued $128 million during the last half of 2002
and $47 million during the three months ended March 31, 2003, for a total of
$175 million. In the future, we will revise our estimates of this payment as
additional information about the market price of electricity and the market
share that will be served by us and other retail electric providers on January
1, 2004 becomes available and we will adjust the related accrual at that time.
For additional information regarding this payment, see note 13(b) to our interim
financial statements.

Operation and Maintenance and Selling, General and Administrative.
Operation and maintenance expenses and general and administrative expenses
increased $28 million for the three months ended March 31, 2003 compared to the
same period in 2002 primarily due to the following:

o $20 million in employee related costs, customer related costs,
and other administrative costs, primarily due to increasing
costs to reach the normal operational level to serve customers
in the Texas retail market;

o $9 million of increased corporate overhead charges; and

o $4 million in marketing costs primarily due to additional
marketing in areas outside of the Houston market.

These increases were partially offset by a $5 million decrease in gross receipts
tax related to an adjustment in the accrual rate.

Depreciation and Amortization. Depreciation and amortization expense
increased $5 million for the three months ended March 31, 2003 compared to the
same period in 2002 primarily due to depreciation related to the information
systems developed and placed in service to meet the needs of our retail
businesses and depreciation of our ERCOT generation facilities.

Other Loss, net. Other losses increased $3 million for the three months
ended March 31, 2003 compared to the same period in 2002 due to recording losses
on sale of receivables. For additional information on our receivables facility,
see note 14 to our interim financial statements.

WHOLESALE ENERGY

Our wholesale energy segment includes our non-regulated power
generation operations in the United States (excluding ERCOT generation
facilities), which includes acquisition and development of generation
facilities, and our wholesale energy trading, marketing, origination and risk
management operations in North America. The wholesale energy segment's
commercial activities include purchasing fuel to supply existing generation
assets, selling electricity and related services produced by these assets,
dispatching of the generation portfolios, scheduling of power and natural gas
and managing the day-to-day trading and marketing activities.

As of March 31, 2003, we owned or leased electric power generation
facilities with an aggregate net operating generating capacity of 19,083 MW in
the United States. We acquired our first power generation facility in April
1998, and have increased our aggregate net generating capacity since that time
principally through acquisitions, as well as contractual agreements and the
development of new generating projects. As of March 31, 2003, we had 2,461 MW
(2,658 MW, net of 197 MW to be retired upon completion of one facility) of
additional net generating capacity under construction. We expect these
facilities to achieve commercial operation in late 2003 or 2004.

In February 2002, we acquired all of the outstanding shares of common
stock of Orion Power for $2.9 billion and assumed debt obligations of $2.4
billion. Orion Power is an independent electric power generating company with a
diversified portfolio of generating assets, both geographically across the
states of New York, Pennsylvania, Ohio and West Virginia, and by fuel type,
including gas, oil, coal and hydropower. As of February 2002, Orion Power had 81
generating facilities in operation with a total generating capacity of 5,644 MW
and two projects under construction with a total generating capacity of 804 MW,
which were completed in the second quarter of 2002.

Given the downturn in the industry and downgrades of our credit
ratings, in the first half of 2002 we reviewed our trading, marketing, power
origination and risk management services strategies and activities. By the third

51

quarter of 2002, we began decreasing the level of these commercial activities in
order to significantly reduce collateral usage and focus on the highest return
transactions, which are primarily derived from our physical asset positions. In
response to declining prices for electric energy, capacity and ancillary
services across much of the United States, we also significantly reduced
development activities beginning in the second quarter of 2002. Development is
now limited only to the completion of projects already under construction.

As a result of these restructurings, direct general and administrative
costs, which excludes allocations of corporate overhead, are expected to be
lower than 2002 levels in 2003.

Starting in late December 2002, our financial gas trading desk carried
a spread position, which involved a short position for March 2003 natural gas
deliveries and a long position for April 2003 natural gas deliveries. The
position was within our authorized value at risk and positional limits. However,
there was significant and unanticipated volatility in the natural gas market
over a few days in February 2003. As a result, we realized a trading loss of
approximately $80 million pre-tax in the first quarter of 2003 related to these
positions. These positions have been closed.

In March 2003, we decided to exit our proprietary trading activities
and liquidate, to the extent practicable, our proprietary positions. Although we
are exiting the proprietary trading business, we have existing positions, which
will be closed as economically feasible or in accordance with their terms. We
will engage in hedging activities and commercial transactions related to our
electric generating facilities, pipeline storage positions and fuel positions.

It is possible that we may sell one or more of our assets. To date, we
have not reached an agreement to dispose of any generating assets of our
wholesale energy segment nor have we included or assumed any proceeds from
prospective asset sales in our current liquidity plan. Specific plans to dispose
of assets could result in impairment losses in property, plant and equipment.

In December 2002, we evaluated the Liberty station and the related
tolling agreement for impairment. There were no impairments based on our
analyses. However, in the future we could incur a pre-tax loss of an amount up
to our recorded net book value. For information regarding issues and
contingencies related to our Liberty power generation station and the related
tolling agreement, see note 13(g) to our interim financial statements.

52

The following table provides summary data, including EBIT, of our wholesale
energy segment for the three months ended March 31, 2002 and 2003:

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

(1) The results of operations for 2002 include the results of Orion Power
from the date of acquisition (February 19, 2002), while the results for
2003 include a full quarter for Orion Power.

(2) Revenues less fuel and cost of gas sold and purchased power.

(3) Includes physically delivered volumes, physical transactions that are
settled prior to delivery and hedge activity related to our power
generation portfolio.

Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2003.

EBIT. The wholesale energy segment's EBIT decreased by $111 million for
the three months ended March 31, 2003 compared to the same period in 2002. The
decline in EBIT is primarily due to the following:

o reversal in 2002 of a previously accrued credit provision of
$33 million for energy sales in California due to collections
of outstanding receivables during the period coupled with a
determination that credit risk had been reduced on the
remaining outstanding receivables as a result of payments in
2002 to the Cal PX;

o decreases in margins from certain of our power generation
operations;

o decreases in trading margins;

o increases in operation and maintenance expenses;

o increases in depreciation and amortization; and

o decreases in income/loss of equity investments of
unconsolidated subsidiaries.

These decreases were partially offset by a net $75 million reversal in
2003 of previously recorded refund provisions of $87 million offset by an
additional credit provision of $12 million, as discussed below.

53

During the three months ended March 31, 2002 and 2003, the Orion Power
assets contributed $87 million and $120 million, respectively, to margins and
$33 million and $11 million, respectively, to EBIT.

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, increased by $400 million in the three months ended March 31, 2003
compared to the same period in 2002. The major components of this increase are:

o a $206 million increase in revenues contributed by Orion Power
assets primarily as a result of the recognition of a full
quarter's revenues during the three months ended March 31,
2003 compared to the recognition of a partial quarter's
revenues during the same period in 2002 as a result of the
acquisition of Orion Power in February 2002;

o a $120 million increase in revenues in the Mid-Atlantic region
due to increased power prices and increased generation driven
by colder temperatures in the region during the three months
ended March 31, 2003;

o a $103 million increase in the West region primarily as a
result of increased power prices due to higher gas prices in
the region; and

o an $87 million reversal in 2003 of previously recorded refund
provisions due to additional clarification received from the
FERC in April 2003.

These increases in revenues were partially offset by the following:

o a $33 million reversal of a previously accrued credit
provision for energy sales in California which was reversed
during the three months ended March 31, 2002 (as discussed
above);

o a $12 million decrease in revenues due to an additional credit
provision recorded resulting from the reversal of refund
provisions, as discussed above;

o a $31 million decrease in revenues in the Mid-Atlantic region
primarily as a result of the expiration of a large capacity
contract; and

o a $17 million decrease in revenues associated with hedge
ineffectiveness losses primarily attributable to the West
region.

Fuel and Cost of Gas Sold and Purchased Power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power increased by $330
million for the three months ended March 31, 2003 compared to the same period in
2002. The major components of this increase are:

o a $173 million increase in fuel and cost of gas sold and
purchased power of Orion Power assets primarily as a result of
the recognition of a full quarter's results during the three
months ended March 31, 2003, as discussed above;

o a $56 million increase in fuel and cost of gas sold and
purchased power in the Mid-Atlantic region due to increased
generation and higher gas prices; and

o a $130 million increase in fuel and cost of gas sold and
purchased power in the West region primarily as a result of
higher gas prices partially offset by reduced generation.

Trading Margins. Trading margins decreased $119 million during the
three months ended March 31, 2003 as compared to the same period in 2002
primarily due to the impact of natural gas trading activity. As discussed above,
the wholesale energy segment was negatively impacted as a result of significant
and unanticipated volatility in the natural gas markets over a few days in
February 2003. In addition, the reduced market liquidity driven by the
industry's restructuring and the reduction of our trading activities as a result
of our restructuring, as discussed above, had a negative impact on trading
margins.

54

Power Generation Margins. Our wholesale energy segment's power
generation margins increased $70 million for the three months ended March 31,
2003 compared to the same period in 2002. Power generation margins were
positively impacted due to:

o a net $48 million increase in margins in the West region due
to a net $75 million reserve reversal (as discussed above),
which was partially offset by a $27 million decrease in
margins due to lower spark spreads during the three months
ended March 31, 2003 and due to the reduction in hedging
results in 2003 as in 2002 we benefited from hedges entered
into in 2001;

o a $33 million increase in power generation margins in the
Mid-Atlantic region due to an increase in spark spreads
resulting from colder temperatures during the three months
ended March 31, 2003 compared to the same period in 2002 and
increased ancillary services revenues, partially offset by
lower capacity revenues in the Mid-Atlantic region as a result
of the expiration of a large capacity contract in May 2002;
and

o a $33 million increase in power generation margins from Orion
Power assets primarily due to the recognition of a full
quarter's results during the three months ended March 31, 2003
compared to the recognition of a partial quarter's results
during the same period in 2002 as a result of the acquisition
in February 2002.

This favorable variance was partially offset by the following:

o a $33 million reversal of credit provisions during the three
months ended March 31, 2002 (as discussed above); and

o a $17 million decrease in margins associated with hedge
ineffectiveness losses (as discussed above).

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $33 million for the three months ended March
31, 2003 compared to the same period in 2002. This was primarily due to a $34
million increase in operation and maintenance expenses at our Orion Power plants
as a result of the recognition of a full quarter's operation and maintenance
expenses during the three months ended March 31, 2003 as discussed above.

General, Administrative and Development. General, administrative and
development expenses decreased $2 million for the three months ended March 31,
2003 compared to the same period in 2002, primarily due to the following:

o an $8 million decrease in salary and incentive plan expenses
primarily due to reduced head count as a result of our
restructuring discussed above; and

o a $5 million reduction in spending on development projects as
a result of the downturn in the industry.

The decreases were substantially offset by:

o a $5 million increase in corporate overhead allocations;

o a $3 million increase in legal costs in connection with
shareholder litigation charges and other consulting fees; and

o a $1 million increase in general bad debt expense due to the
financial deterioration of counterparties in the wholesale
energy industry.

Depreciation and Amortization. Depreciation and amortization expense
increased by $24 million for the three months ended March 31, 2003 compared to
same period in 2002 primarily as a result of the following:

o a $15 million increase in depreciation and amortization
expense as a result of the recognition of a full quarter's
depreciation and amortization in 2003 at Orion Power as
discussed above;

55

o $3 million in depreciation expense associated with new
information technology systems that were not placed into
service until March 2002; and

o a $2 million increase in depreciation and amortization as a
result of increases in depreciable assets during 2002 in the
West region and higher emissions amortization in the
Mid-Atlantic region due to increased generation.

Income (Loss) of Equity Investments of Unconsolidated Subsidiaries. The
equity income/loss in both periods primarily resulted from an investment in an
electric generation plant in Boulder City, Nevada. The equity income related to
our investment in the plant decreased during the three months ended March 31,
2003 compared to the same period in 2002, primarily due to receipts of $3
million of business interruption and property/casualty insurance settlements in
2002.

OTHER OPERATIONS

Our other operations segment includes the operations of our venture
capital business and unallocated corporate costs.

The following table provides summary data regarding the results of
operations of our other operations segment for the three months ended March 31,
2002 and 2003:

Three Months Ended March 31, 2002 Compared to Three Months Ended March 31, 2003.

Other operation's loss before interest and income taxes remained
constant for the three months ended March 31, 2003 compared to the same period
in 2002.

Operating loss increased $3 million during the three months ended March
31, 2003 compared to the same period in 2002 primarily due to a $2 million
accrual of Texas franchise taxes. The increase in operating loss was offset by a
decrease in other non-operating losses during the three months ended March 31,
2003 compared to the same period in 2002. Included in other losses during the
three months ended March 31, 2002 is a $6 million accrual for investment bank
services and a $3 million impairment of an investment in an internet company.
These items were partially offset by investment income related to the
distribution of equity securities from venture capital investments.

TRADING AND MARKETING AND NON-TRADING OPERATIONS

Trading and Marketing Operations. During 2002, we evaluated our
trading, marketing, power origination and risk management services strategies
and activities. During the second half of 2002, we began to reduce our wholesale
energy segment's trading, marketing and power origination activities due to
liquidity concerns and in order to significantly reduce collateral usage and
focus on the highest return transactions, which primarily relate to our physical
asset positions. In March 2003, we decided to exit our proprietary trading
activities and liquidate, to the extent practicable, our proprietary positions.
Although we are exiting the proprietary trading business, we have

56

existing positions, which will be closed as economically feasible or in
accordance with their terms. We will continue to engage in hedging activities
and commercial transactions related to our electric generating facilities,
pipeline storage positions and fuel positions of our wholesale energy segment
and energy supply costs related to our retail energy segment.

Prior to 2003, our retail energy segment's contracted electricity sales
to large commercial, industrial and institutional customers and the related
energy supply contracts for contracts entered into prior to October 25, 2002
were accounted for under the mark-to-market method of accounting pursuant to
EITF No. 98-10. Under the mark-to-market method of accounting, these contractual
commitments were recorded at fair value in revenues on a net basis upon contract
execution. The net changes in their fair values were recognized in the
statements of consolidated operations as revenues on a net basis in the period
of change through 2002. Effective January 1, 2003, we no longer mark to market
in earnings a substantial portion of these contracts and the related energy
supply contracts in connection with the implementation of EITF No. 02-03. The
related revenues and purchased power are now recorded on a gross basis in our
results of operations.

In our results of operations, trading and marketing activities of our
wholesale energy segment include (a) transactions establishing open positions in
the energy markets, primarily on a short-term basis, (b) transactions intended
to optimize our power generation portfolio, but which do not qualify for hedge
accounting and (c) energy price risk management services to customers primarily
related to natural gas, electric power and other energy-related commodities. We
provide these services by utilizing a variety of derivative instruments (trading
energy derivatives). We account for these transactions under mark-to-market
accounting. For information regarding mark-to-market accounting, see notes 2(t)
and 7 to our Form 10-K/A.

In October 2002, the EITF rescinded EITF No. 98-10. For further
discussion of the impact on our interim financial statements, see "- EBIT by
Business Segment - Retail Energy" and "EBIT by Business Segment - Wholesale
Energy", notes 2(t) and 7 to our Form 10-K/A and note 2 to our interim financial
statements.

For additional information regarding the types of contracts and
activities of our trading and marketing operations, see "Quantitative and
Qualitative Disclosures About Market Risk" in this Form 10-Q, note 8 to our
interim financial statements, note 7 to our Form 10-K/A and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Trading and Marketing Operations" to our Form 10-K/A.

The following table sets forth our consolidated net trading and
marketing assets (liabilities) by segment as of December 31, 2002 and March 31,
2003:

57

The following table sets forth our consolidated realized and unrealized
trading, marketing and risk management services margins for the three months
ended March 31, 2002 and 2003:

Below is an analysis of our net consolidated trading and marketing
assets and liabilities for the three months ended March 31, 2002 and 2003.

During the three months ended March 31, 2002, our retail energy segment
entered into electric sales contracts with large commercial, industrial and
institutional customers ranging from one-half to four years in duration. During
the three months ended March 31, 2002, we recognized total fair value of $20
million for these contracts at the inception dates. We have entered into energy
supply contracts to substantially hedge the economics of these contracts. For
information regarding the valuing of the retail energy segment electric sales
contracts with large commercial, industrial and institutional customers in prior
periods, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Trading and Marketing Operations" to our Form 10-K/A.

During the three months ended March 31, 2002 and 2003, there were no
changes in fair values attributable to changes in valuation techniques and
assumptions.

In response to the Committee of Chief Risk Officers (CCRO) proposal of
industry best practices issued in November 2002, we have voluntarily chosen to
comply with certain disclosure recommendations of the CCRO and have integrated
their best practices into our disclosures, on a prospective basis, as of and for
the three months ended March 31, 2003. One purpose of adopting these disclosures
is to provide additional detail regarding the results of our merchant energy
business activities conducted through our wholesale energy segment. Our retail
energy segment's principal business activity is to serve customers' end-use
energy needs and therefore is not included in these disclosures. In the tables
that follow, certain information is segregated into two categories: proprietary
trading and owned or controlled assets. Proprietary trading activities typically
involve entering into standardized contracts to take a position, capture market
price changes, or put capital at risk. These activities are generally accounted
for under the mark-to-market method of accounting. Owned or controlled assets
activities represent activities associated with assets owned or leased by us and
can be accounted for either under the mark-to-market method of accounting or the
accrual method of accounting.

58

The following table sets forth our trading and marketing assets and
liabilities for our wholesale energy segment as of March 31, 2003 delineated
into the categories of proprietary trading and owned or controlled assets:

The following table sets forth the fair values of the contracts related
to our trading and marketing assets and liabilities as of March 31, 2003 for our
wholesale energy segment delineated into the categories of proprietary trading
and owned or controlled assets:

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

(1) Our retail energy segment's activities are not considered
merchant energy business activities for 2003 and are therefore
excluded from the above table.

For information regarding "prices actively quoted," "prices provided by
other external sources" and "prices based on models and other valuation
methods," see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Trading and Marketing Operations" to our Form 10-K/A.

The fair values in the above table are subject to significant changes
based on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, marketing, power origination and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant parameters impacting the value of our portfolio of contracts include
natural gas and power forward market prices, volatility and credit risk. Market
prices assume a normal functioning market with an adequate number of buyers and
sellers providing market liquidity. Insufficient market liquidity could
significantly affect the values that could be obtained for these contracts, as
well as the costs at which these contracts could be hedged. See "Quantitative
and Qualitative Disclosures About Market Risk" in Item 7A to our Form 10-K/A for
further discussion and measurement of the market exposure in the trading and
marketing businesses and discussion of credit risk management.

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Non-trading Operations. To reduce the risk from market fluctuations in
revenues and the resulting cash flows derived from the sale of electric power,
we may enter into energy derivatives in order to hedge some expected purchases
of electric power, natural gas and other commodities and sales of electric power
(non-trading energy derivatives). The non-trading energy derivative portfolios
are managed to complement the physical transaction portfolio, reducing overall
risks within authorized limits.

We apply hedge accounting for our non-trading energy derivatives
utilized in non-trading activities only if there is high correlation between
price movements in the derivative and the item designated as being hedged. This
correlation, a measure of hedge effectiveness, is measured both at the inception
of the hedge and on an ongoing basis, with an acceptable level of correlation of
at least 80% to 125% for hedge designation. If and when correlation ceases to
exist at an acceptable level, hedge accounting ceases and prospective changes in
fair value are recognized currently in our results of operations.

Interest rate swaps entered into by our wholesale energy segment to
hedge floating rate debt obligations are excluded from our merchant business
activities and therefore are not included in these tables.

The following table sets forth our non-trading assets and liabilities
related to our merchant business activities of our wholesale energy segment as
of March 31, 2003 (in millions):

Current assets ......................................... $ 143
Non-current assets ..................................... 83
----------
Total non-trading derivative assets .................. 226
==========

Current liabilities .................................... (248)
Non-current liabilities ................................ (110)
----------
Total non-trading derivative liabilities ............. (358)
----------
Total net non-trading derivative liabilities ....... $ (132)
==========

The following table sets forth a rollforward of our net non-trading
derivative assets and liabilities relating to our merchant business activities
for our wholesale energy segment for the three months ended March 31, 2003 (in
millions):

Net non-trading derivative liabilities at December 31, 2002 .................. $ (108)
Effective portion of changes in fair value recorded in accumulated other
comprehensive loss ......................................................... (6)
Ineffective portion of changes in fair value ................................. (18)
----------
Net non-trading derivative liabilities at March 31, 2003 ................... $ (132)
==========

Cash flow hedges included in accumulated other comprehensive loss as of
March 31, 2003 are as follows:

The following table sets forth our consolidated accumulated other
comprehensive gain/loss derivative activity for continuing operations, net of
tax, for the three months ended March 31, 2003:

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The following table sets forth the fair values of the contracts related
to our non-trading derivative assets and liabilities for our merchant business
activities for our wholesale energy segment as of March 31, 2003:

See "Trading and Marketing Operations" section above for discussion of
prices.

Credit Risk. Credit risk is inherent in our commercial activities.
Credit risk relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. We have broad credit policies and
parameters set by our risk oversight committee. The credit risk control
organizations prepare daily analyses of credit exposures. We seek to enter into
contracts that permit us to net receivables and payables with a given
counterparty. We also enter into contracts that enable us to obtain collateral
from a counterparty as well as to terminate upon the occurrence of certain
events of default.

It is our policy that all transactions must be within approved
counterparty or customer credit limits. For each business segment, the credit
risk control organization establishes counterparty credit limits. We employ
tiered levels of approval authority for counterparty credit limits, with
authority increasing from the credit risk control organization through senior
management and our risk oversight committee. The credit risk control
organization monitors credit exposure daily. We periodically review the
financial condition of our counterparties.

The following table, which differs from disclosures in our Form 10-K/A
due to the fact that we now include notional amounts related to contracts
classified as "normal" in accordance with SFAS No. 133 and accounts receivable
as proposed by the CCRO, sets forth the distribution by investment grade and
non-investment grade ratings of our trading and marketing assets and non-trading
derivative assets and other notional amounts and accounts receivable, as just
described, as of March 31, 2003, after taking into consideration netting within
each contract and any master netting contracts with counterparties of our
merchant business activities for our wholesale energy segment:

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

(1) Collateral consists of cash and standby letters of credit.

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(2) For unrated counterparties, we perform credit analyses, considering
contractual rights and restrictions, and credit support such as parent
company guarantees to create an internal credit rating.

The following table sets forth the credit exposure by maturity for
total trading and marketing assets and non-trading derivative assets and other
notional amounts and accounts receivable, as described above, as of March 31,
2003 of our merchant business activities for our wholesale energy segment:

(1) Collateral consists of cash and standby letters of credit.

(2) For unrated counterparties, we perform credit analyses, considering
contractual rights and restrictions, and credit support such as parent
company guarantees to create an internal credit rating.

(3) Note that the totals in this table do not agree to the totals in the
table above as this table does not net our credit exposures across
time.

Trading and marketing assets and liabilities and non-trading derivative
assets and liabilities are presented separately in our consolidated balance
sheets. The trading and non-trading derivative asset and trading and non-trading
derivative liability balances are offset separately in our consolidated balance
sheets although in certain cases contracts permit the offset of trading and
non-trading derivative assets and liabilities with a given counterparty. For the
purpose of disclosing credit risk, all assets and liabilities with a given
counterparty were offset if the counterparty has entered into a contract with us
which permits netting.

Other. For additional information about price volatility and our
hedging strategy, see "- Certain Factors Affecting Our Future Earnings - Factors
Affecting the Results of Our Wholesale Energy Operations - Price Volatility,"
and "- Risks Associated with Our Hedging and Risk Management Activities" to our
Form 10-K/A. We seek to monitor and control our trading risk exposures through a
variety of processes and committees. For additional information, see
"Quantitative and Qualitative Disclosures About Market Risk" in Item 7A to our
Form 10-K/A.

FINANCIAL CONDITION

The net cash provided by or used in operating, investing and financing
activities for the three months ended March 31, 2002 and 2003 follows:

Cash Provided by (Used in) Operating Activities

Net cash used in operating activities during the three months ended
March 31, 2003 changed $623 million compared to the same period in 2002. This
decrease was primarily due to $379 million of decreases from working capital and
other changes in assets and liabilities from continuing operations and to a
lesser extent due to $209 million of decreases from cash flows from continuing
operations, excluding changes in working capital and other changes in assets and
liabilities. Additionally, cash flows related to the operations of our
discontinued European energy operations decreased $35 million for the three
months ended March 31, 2003 compared to the same period in 2002.

Net cash provided by/used in operating activities decreased by $379
million from $192 million in net cash inflows in the three months ended March
31, 2002 to $187 million in net cash outflows in the three months ended

62

March 31, 2003 due to changes in working capital and other changes in assets and
liabilities due to the following:

o a $213 million change in margin deposits on energy trading and
hedging activities, primarily due to cash inflows of $217
million in the three months ended March 31, 2002;

o $145 million net cash outflows relating to collateral deposits
for letters of credit relating to energy trading and hedging
activities during three months ended March 31, 2003 (see note
10 to our interim financial statements);

o $130 million of net collateral deposits related to an
operating lease returned to us in the three months ended March
31, 2002;

o $181 million decrease in cash inflows related to restricted
cash for the three months ended March 31, 2003 compared to the
same period in 2002 primarily attributed to REMA (see note
14(a) to our Form 10-K/A) and our Orion Power operations; and

o $29 million paid to purchase interest rate caps during the
three months ended March 31, 2003.

These items were partially offset by a $264 million decrease in net
cash outflows due to a decrease in cash outflows associated with accounts
receivable of $485 million primarily related to our retail energy segment,
offset by a net increase in cash outflows related to accounts payable of $157
million and a decrease in cash inflows related to net intercompany accounts
receivable of $64 million. These items were also partially offset by other
changes in working capital.

Net cash provided by/used in our operations, excluding changes in
working capital and other changes in assets and liabilities decreased by $209
million from $170 million in net cash inflows in the three months ended March
31, 2002 to $39 million in net cash outflows in the three months ended March 31,
2003 primarily due to cash flows provide by/used in our wholesale energy segment
due to a decline in operating results.

Cash Used in Investing Activities

Net cash used in investing activities during the three months ended
March 31, 2003 decreased $2.9 billion compared to the same period in 2002,
primarily due to funding the acquisition of Orion Power for $2.9 billion in 2002
as discussed below.

On February 19, 2002, we acquired all of the outstanding shares of
common stock of Orion Power for an aggregate purchase price of $2.9 billion and
assumed debt obligations of $2.4 billion. As of February 19, 2002, Orion Power's
debt obligations were $2.4 billion ($2.1 billion net of restricted cash pursuant
to debt covenants). We funded the purchase of Orion Power with a $2.9 billion
credit facility and $41 million of cash on hand. For further discussion, see
note 5(a) to our Form 10-K/A and note 6 to our interim financial statements.

Cash Provided by (Used in) Financing Activities

Net cash used in financing activities during the three months ended
March 31, 2003 changed by $3.2 billion compared to the same period in 2002,
primarily due to an increase in short-term borrowings of $2.9 billion used to
fund the acquisition of Orion Power in February 2002 and the $350 million
prepayment of the senior revolving credit facility made in connection with the
refinancing in March 2003 (see note 10 to our interim financial statements). In
addition, during the three months ended March 31, 2003, we incurred financing
costs of $131 million related to the March 2003 refinancing.

CONSOLIDATED FUTURE USES AND SOURCES OF CASH AND CERTAIN FACTORS IMPACTING
FUTURE USES AND SOURCES OF CASH

Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, working
capital needs and collateral requirements. We expect to complete the
construction of new generation facilities that are in progress; however, the
refinanced and new credit facilities entered into in March 2003 restrict the
construction of any new generation facilities in the future. Maintenance of

63

plants will continue to include costs necessary to operate the plants safely,
including necessary environmental expenditures. We will evaluate opportunities
to enter retail electric markets for large commercial, industrial and
institutional customers, in particular, in regions in which we have electric
generating facilities and capacity. Subject to restrictions in our March 2003
credit facilities, we may buy or acquire mass market customers in ERCOT. We
expect our capital requirements to be met with cash flows from operations,
borrowings under our senior secured revolving credit facilities and proceeds
from one or more debt and equity offerings, securitization of assets and other
borrowings. We believe that our current level of cash and borrowing capability,
along with our future anticipated cash flows from operations, will be sufficient
to meet the existing operational and collateral needs of our business for the
next 12 months. Subject to restrictions in our March 2003 credit facilities, if
cash generated from operations is insufficient to satisfy our liquidity
requirements, we may seek to sell assets, obtain additional credit facilities or
other financings and/or issue additional equity or convertible instruments. For
additional discussion regarding our capital commitments, see note 14(f) to our
Form 10-K/A.

Generating Projects. As of March 31, 2003, we had four generating
facilities under construction. We expect to complete three of these facilities
in the second half of 2003 and the fourth facility in 2004. Total estimated cost
of constructing these facilities is $2.3 billion. As of March 31, 2003, we had
incurred $1.8 billion in construction costs, property, plant and equipment and
spare parts inventory on these projects, which was funded from equity and debt.
We were constructing three of these facilities under construction agency
agreements through off-balance sheet special purpose entities. We consolidated
these special purpose entities effective January 1, 2003 upon the adoption of
FIN No. 46. We expect to spend approximately an additional $432 million in order
to complete these facilities. For more information regarding the construction
agency agreements, see note 13(a) to our interim financial statements.

Environmental Expenditures. We anticipate spending up to $132 million
in capital and other special project expenditures from 2003 through 2007 for
environmental compliance, totaling approximately $35 million, $35 million, $14
million, $23 million and $25 million in 2003, 2004, 2005, 2006 and 2007,
respectively. In addition, we expect to spend $22 million for the remainder of
2003 through 2007 for pre-existing conditions and remediations, which are
recorded as liabilities in our consolidated balance sheet as of March 31, 2003.

Texas Genco Option. In connection with the separation of our businesses
from those of CenterPoint, CenterPoint granted us an option to purchase all of
the shares of capital stock of Texas Genco owned by CenterPoint in January 2004.
We will make our decision with respect to whether or not to exercise the option
based on the exercise price of the option, market conditions, available
financing and our due diligence investigation of Texas Genco. If we elect to
exercise our purchase option, our March 2003 credit facilities would require us
to fund the purchase obligation solely with proceeds from permitted asset sales,
including our European energy operations, proceeds from subordinated debt and
equity offerings, a limited recourse acquisition financing and/or borrowings at
Texas Genco (or its intermediate holding company). If we are not able to realize
such proceeds, we do not expect that we will be able to exercise the option. If
we do not exercise the option, we will need to continue to contract with Texas
Genco or others to meet some of our retail supply obligations. For additional
information regarding this option to purchase CenterPoint's interest in Texas
Genco, see note 4(b) to our Form 10-K/A.

Mid-Atlantic Assets Lease Obligation. In August 2000, we entered into
separate sale-leaseback transactions with each of the three owner-lessors for
our applicable interests in three generating stations, which we acquired as part
of the REMA acquisition. For additional discussion of these lease transactions,
see notes 5(b) and 14(a) to our Form 10-K/A.

Other Operating Lease Commitments. For a discussion of other operating
leases, see note 14(a) to our Form 10-K/A.

Other Commodity Commitments. For a discussion of other commodity
commitments, see note 14(f) to our Form 10-K/A.

Payment to CenterPoint. To the extent that our price to beat for
electric service to residential and small commercial customers in CenterPoint's
Houston service territory during 2002 and 2003 exceeds the market price of
electricity, we may be required to make a payment to CenterPoint in 2004. As of
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 13(b) to
our interim financial statements and note 14(e) to our Form 10-K/A.

64

Naming Rights to Houston Sports Complex. In October 2000, we acquired
the naming rights for a football stadium and other convention and entertainment
facilities included in the stadium complex. Starting in 2002 and continuing
through 2032, we pay $10 million each year for annual advertising under this
agreement. For additional information on the naming rights agreement, see note
14(f) to our Form 10-K/A.

Other Future Uses and Sources of Cash and Certain Factors Impacting Future Uses
and Sources of Cash.

During 2002, many factors negatively impacted us. These factors
included weaker pricing for electric energy, capacity and ancillary services,
coupled with a narrowing of the spark spread in the United States; market
contraction, reduced volatility and reduced liquidity in the gas and power
trading markets in the United States and Northwest Europe; downgrades in our
credit ratings to below investment grade by each of the major rating agencies;
various legal and regulatory investigations and proceedings (see note 13(d) to
our interim financial statements); reduced market confidence in our financial
reporting in light of our restatements and amendments; reduced access to capital
and increased demands for collateral in connection with our trading, hedging and
commercial obligations; the decline in market prices of our common stock; and
continued weakness in the United States economy generally. Certain of these
factors are discussed in more detail below.

Future acquisitions and development projects are restricted under our
credit facilities. Although we are required to dedicate a substantial portion of
our cash flows to payments on our debt, we currently expect to be able to
complete the four generation facilities currently under construction, as well as
to meet our currently anticipated capital expenditure and working capital needs
without additional funding; however, we do have the ability to borrow additional
funds, subject to certain restrictions in our March 2003 credit facilities, to
fund our future capital expenditure and working capital needs.

We may need external financing to fund capital expenditures, including
capital expenditures necessary to comply with air emission regulations or other
regulatory requirements. If we are unable to obtain outside financing to meet
our future capital requirements due to restrictions in our March 2003 credit
facilities or on terms that are acceptable to us, our financial condition and
future results of operations could be materially adversely affected. In order to
meet our future capital requirements, we may increase the proportion of debt in
our overall capital structure (subject to restrictions in our credit facilities)
or we may need to issue equity or convertible instruments, thereby diluting the
interests of current shareholders. Increases in our debt levels may further
adversely affect our credit ratings thereby further increasing the cost of our
debt. In addition, the capital constraints currently impacting our industry may
require additional future indebtedness to include terms and/or pricing that is
more restrictive or burdensome than those of our current indebtedness and
refinancings in March 2003. This may negatively impact our ability to operate
our business, or severely restrict or prohibit distributions from our
subsidiaries.

As a result of our March 2003 refinancing, our interest expense will
increase substantially. The exact amount of the increase is difficult to
estimate and will depend on a variety of factors, some of which are not within
our control, such as prevailing interest rates. However, a comparison of the
LIBOR interest rate margins under our Orion acquisition term loan (which was
included in our March 2003 refinancing) and our March 2003 senior secured term
loans illustrates the possible magnitude of the interest expense increase. The
interest rate margin over LIBOR was initially 2% for the Orion acquisition term
loan and is 4% for the March 2003 senior secured term loans, equivalent to an
interest expense difference of $20 million annually for each $1 billion of
principal amount. For additional information concerning our March 2003
refinancing and the facilities that were refinanced, including applicable
principal amounts and interest rates, see note 10 to our interim financial
statements.

65

Our March 2003 credit facilities are payable or the commitments terminate
as follows:

In addition, under our March 2003 credit facilities, certain warrants
issued to our lenders would vest, and we would be required to pay our lenders
certain fees, if we do not, on or before the dates set forth below, repay our
senior secured term loans and/or permanently reduce the commitment under our
senior secured revolving credit facility in the aggregate paydown/reduction
amounts set forth below. The fees set forth below are a percentage of the unpaid
senior secured term loans and the commitment in effect under the senior secured
revolving credit facility, in each case as of the date indicated. The warrants
set forth below are exercisable for shares of our common stock.

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

(1) These warrants vested upon closing of our March 2003 credit facilities.

(2) These warrants vest only if we fail to satisfy the indicated aggregate
paydown/reduction amount on or before the indicated date.

The exercise prices of the warrants are based on average market prices
of our common stock during specified periods in proximity to the refinancing
date. 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.

Our ability to arrange debt and equity financing and our cost of
capital are dependent on the following factors, without limitation:

o general economic and capital market conditions;

o acceptable credit ratings;

o credit availability and access to liquidity from banks and
access to the capital markets;

o the success of our retail energy and wholesale energy
segments' operations;

o market expectations regarding the price to beat and regulation
of our retail energy segment's business in Texas;

o investor, supplier and customer confidence in us, our
competitors and peer companies and our wholesale power
markets;

o market expectations regarding our future earnings and probable
cash flows;

o market perceptions of our ability to access capital markets on
reasonable terms;

o provisions of relevant tax and securities laws;

o impact of lawsuits, investigations and other proceedings;

66

o successful completion of the four generation facilities
currently under construction;

o market expectations of whether or not we are likely to incur
additional debt in order to exercise the Texas Genco option;
and

o successful execution of our planned sale of our European
energy operations.

Our March 2003 credit facilities restrict our ability to take specific
actions without the consent of our lenders, even if such actions may be in our
best interest. Subject to certain exceptions designed to allow for the execution
of our business plans in the ordinary course, these restrictions limit our
ability to, among other things:

o incur additional liens or make additional negative pledges on
our assets;

o merge, consolidate or sell our assets;

o issue additional debt or engage in sale and leaseback
transactions;

o pay dividends, repurchase capital stock or prepay other debt;

o make investments or acquisitions;

o engage in construction or development activities in respect of
power plants;

o enter into transactions with affiliates, except on an arm's
length basis;

o make capital expenditures;

o materially change our business;

o amend our debt and other material agreements in certain
respects;

o issue and sell subsidiary capital stock; and

o engage in certain types of trading activities.

Refinancings of Credit Facilities in March 2003.

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 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 the closing of the Texas Genco acquisition if we elect to exercise
our option or December 15, 2004. For further discussion of this refinancing, see
note 10 to our interim financial statements.

Credit Facilities, Bonds and Notes.

As of March 31, 2003, we had $9.3 billion in committed credit
facilities, bonds and notes of which $768 million was unused. As of March 31,
2003, letters of credit outstanding under these facilities aggregated $682
million and borrowings aggregated $7.8 billion. As of March 31, 2003, $175
million of our committed credit facilities are to expire by March 31, 2004. For
a discussion of the refinancing and amendments of certain of these committed
credit facilities in March 2003, see note 10 to our interim financial
statements.

67

Currently, we are satisfying our capital requirements and other
commitments primarily with cash from operations, cash on hand and borrowings
available under our credit facilities. The following table summarizes our credit
capacity, cash and cash equivalents and current restricted cash at March 31,
2003:

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

(1) As discussed in notes 10 and 13(g) to our interim financial statements,
$5 million of the unused capacity relates to Liberty's working capital
facility and for the term of the waiver from the lenders, Liberty has
agreed it will not make draws on the working capital facility.

(2) Current restricted cash includes cash at certain subsidiaries that is
restricted by financing agreements, but is available to the applicable
subsidiary to use to satisfy certain of its obligations.

Restricted Cash.

All of our operations are conducted by our subsidiaries. Our cash flow
and our ability to service parent-level indebtedness when due is dependent upon
our receipt of cash dividends, distributions or other transfers from our
subsidiaries. The terms of some of our subsidiaries' indebtedness restrict their
ability to pay dividends or make restricted payments to us in some
circumstances. For information regarding restricted cash and the related credit
facilities, see notes 2(l) and 9(a) to our Form 10-K/A.

Credit Ratings.

As of May 1, 2003 our unsecured credit ratings are as follows:

We expect to approach the rating agencies in the near future to seek
ratings of our March 2003 credit facilities and an update to the ratings for our
senior unsecured obligations. We are not able to estimate what these ratings
will be.

As of May 1, 2003, the REMA lease certificates were rated B by Standard
& Poor's and B3 by Moody's. The ratings remain on "CreditWatch Developing" and
"review for possible downgrade", respectively. As of May 1, 2003, the Moody's
senior unsecured debt rating for Orion Power was B3. The rating remains on
"review for possible downgrade." Standard & Poor's senior unsecured debt and
corporate ratings for Orion Power were CCC+ and B, respectively. These ratings
remain on "CreditWatch Developing."

We cannot assure that these ratings will remain in effect for any given
period of time or that one or more of these ratings will not be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities and may be revised or
withdrawn at any time by the rating agencies. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to access capital on acceptable terms.

We have been adversely impacted by our previous downgrade to
sub-investment grade in connection with certain commercial agreements and
certain bank facilities. The commercial arrangements primarily include: (a)
commercial contracts and/or guarantees related to our wholesale and retail
trading, marketing, risk management and

68

hedging activities and (b) surety bonds and contractual obligations related to
the development and construction or refurbishment of power plants and related
facilities. Certain bank facilities contain provisions whereby our interest rate
margins are affected by our credit ratings. Due to the various downgrades, we
have incurred additional interest expense.

In most cases, the consequences of rating downgrades are limited to the
requirement by our counterparties that we provide credit support to them in the
form of a pledge of cash collateral, a letter of credit or other similar credit
support. In addition, certain of our retail electricity contracts with large
commercial, industrial and institutional customers in the retail energy segment
permit the customers to terminate their contracts once our unsecured debt
ratings fall below investment grade or if our ratings are withdrawn entirely by
a rating agency. As of May 1, 2003, no retail contracts have been terminated
pursuant to these terms. In light of the credit rating downgrades, we are
working with our various commercial counterparties to minimize the disruption to
our normal commercial activities and to reduce the magnitude of the collateral
we must post in support of our obligations to such counterparties.

In connection with our domestic commercial operations, as of May 1,
2003, we have posted cash collateral of $335 million and letters of credit of
$240 million from Reliant Resources' facilities. Of these letters of credit, $15
million are issued under a cash-secured, revolving letter of credit facility
initiated on January 29, 2003, see note 10 to our interim financial statements.
In addition, we have posted cash collateral related to commercial operations of
$9 million and letters of credit of $27 million from Orion Power subsidiary
facilities. In support of financings, we have issued additional letters of
credit of $305 million from Reliant Resources' facilities and $67 million from
subsidiary facilities. Based on current commodity prices, we estimate that as of
May 1, 2003, we could be required to post additional collateral of up to $447
million related to our domestic operations. This estimate could increase based
on changes to commodity prices. As of May 1, 2003, we had $353 million in
unrestricted cash and cash equivalents and $578 million available under
committed corporate facilities. Factors which could lead to an increase in our
actual posting of collateral include adverse changes in our industry or negative
reactions to additional credit rating downgrades or the secured nature of the
March 2003 credit facilities.

We believe that our current level of cash and borrowing capability,
along with our future anticipated cash flows from operations, will be sufficient
to meet the liquidity needs of our business for the next twelve months. Under
certain unfavorable commodity price scenarios, however, it is possible that we
could experience inadequate liquidity.

In addition, we have been involved in certain commercial activities
(including long-term sales of electric energy or capacity from our generating
facilities) that prospectively may not be feasible due to our current credit and
liquidity situation, among other factors. The credit downgrades have also
resulted in more limited access to creditworthy counterparties with which to
transact and the need to make commercial concessions with counterparties as an
inducement for them to do business with us. Given these factors, we have reduced
the level of our trading, marketing and hedging activities, which may result in
a potential reduction and greater volatility in future earnings.

69

Other Sources and Uses of Cash and Factors Impacting Cash.

Sale 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. Upon consummation of the sale, we expect to receive
cash proceeds from the sale of approximately $1.2 billion (Euro 1.1 billion). We
intend to use the cash proceeds from the sale first to prepay the Euro 600
million bank term loan borrowed by RECE to finance a portion of the original
acquisition costs of our European energy operations. The maturity date of the
credit facility, which originally was scheduled to mature in March 2003, has
been extended (see note 16 to our interim financial statements). If we exercise
the option to acquire Texas Genco in 2004, we intend to use the remaining cash
proceeds of approximately $0.5 billion (Euro 0.5 billion) to partially fund the
exercise of this option. However, if we elect not to exercise the option, we
must use the remaining cash proceeds to prepay debt. The Dutch competition
authority approval is needed for the sale to occur. No assurance can be given
that we will obtain the necessary approval or that it will be obtained in a
timely manner. For further discussion of the sale, see note 16 to our interim
financial statements.

Generating Capacity Auction Line of Credit. On October 1, 2002, our
retail energy segment, through a subsidiary, entered into a master power
purchasing contract with Texas Genco covering, among other things, our purchases
of capacity and/or energy from Texas Genco's generating facilities. In
connection with the March 2003 refinancing, this contract has been amended to
grant Texas Genco a security interest in the accounts receivable and related
assets of certain retail energy segment subsidiaries, the priority of which is
subject to certain permitted prior financing arrangements, and the junior liens
granted to the lenders under the March 2003 refinancing. In addition, many of
the covenant restrictions contained in the contract were removed in the
amendment.

California Trade Receivables and the FERC Refunds. As of March 31,
2003, we were owed total receivables, including interest, of $221 million (net
of estimated refund provision) by the Cal ISO, the Cal PX, the CDWR and
California Energy Resources Scheduler for energy sales in the California
wholesale market during the fourth quarter of 2000 through March 31, 2003. As of
March 31, 2003, we had an $18 million pre-tax credit provision against these
receivable balances. From April 1, 2003 through May 1, 2003, we have collected
$19 million of these receivable balances. For additional information regarding
these receivables and uncertainties in the California wholesale market, see note
13(e) to our interim financial statements.

Counterparty Credit Risk. For a discussion of our counterparty credit
risk, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Trading and Marketing Operations."

Receivables Facility Covenant Violation. For discussion of a covenant
violation under the receivables facility, see note 14 to our interim financial
statements.

Liberty Electric Generating Station Contingency. The output of the
Liberty Station is contracted under a tolling agreement between LEP, a
wholly-owned indirect subsidiary of Orion Power, and PGET for a term of
approximately 14 years, with an option to extend at the end of the term. Liberty
and LEP have received a waiver from the lenders under the Liberty credit
facility from the requirement that they enforce all of their respective rights
under the tolling agreement. In return for this waiver, Liberty and LEP have
agreed that for the term of the waiver, they would not be able to make draws on
the working capital facility that is available under the Liberty credit
facility. The current waiver expires on June 30, 2003. There is no assurance
that Liberty and LEP will be able to receive any waiver extension. For
information regarding this tolling agreement, issues related to the financing of
the Liberty Station and other related contingencies, including foreclosure
concerns, see note 13(g) to our interim financial statements.

Reliant Energy Desert Basin Contingency. REDB sells capacity to SRP
under a long-term power purchase agreement. We guarantee certain of REDB's
obligations under the power purchase agreement. As a result of our credit
downgrade to below investment grade by two major ratings agencies, SRP has
requested performance assurance in the form of cash or a letter of credit from
REDB under the power purchase agreement and from Reliant Resources under the
guarantee. Under the power purchase agreement and guarantee, the total amount of
performance assurance cannot exceed $150 million. For information regarding
REDB's obligations, our related guarantee and other related contingencies, see
note 13(f) to our interim financial statements.

70

Other Items. For other items that may affect our future cash flows from
operations, see our Form 10-K/A.

OFF-BALANCE SHEET TRANSACTIONS

Construction Agency Agreements. In 2001, we, through several of our
subsidiaries, entered into operative documents with special purpose entities to
facilitate the development, construction, financing and leasing of three power
generation projects. As of December 31, 2002, we did not consolidate the results
of the special purpose entities in our consolidated financial statements.
Effective January 1, 2003, upon the adoption of FIN No. 46, we began
consolidating these special purpose entities. For information regarding these
transactions and the refinancing in March 2003, see notes 10 and 13(a) to our
interim financial statements.

Receivables Facility Agreement. In July 2002, we entered into a
receivables facility arrangement with a financial institution to sell an
undivided interest in accounts receivable from residential and small commercial
retail electric customers under which, on an ongoing basis, the financial
institution will invest a maximum of $125 million for its interest in such
receivables. Pursuant to this receivables facility, we formed a QSPE as a
bankruptcy remote subsidiary. For additional information regarding this
transaction, see note 14 to our interim financial statements.

REMA Sales/Leaseback Transactions. In August 2000, we entered into
separate sale/leaseback transactions with each of the three owner-lessors for
our interests in three generating stations acquired in the REMA acquisition. For
additional discussion of these lease transactions, see note 14(a) to our Form
10-K/A.

NEW ACCOUNTING PRONOUNCEMENTS, SIGNIFICANT ACCOUNTING POLICIES AND
CRITICAL ACCOUNTING ESTIMATES

NEW ACCOUNTING PRONOUNCEMENTS

For discussion regarding new accounting pronouncements that impact us,
see note 2 to our interim financial statements.

SIGNIFICANT ACCOUNTING POLICIES

For discussion regarding our significant accounting policies, see note
2 to our Form 10-K/A.

CRITICAL ACCOUNTING ESTIMATES

For discussion regarding our critical accounting estimates, see our
Form 10-K/A.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISK

We are exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
our consolidated financial statements. Most of the revenues, results of
operations and cash flows from our business activities are impacted by market
risks. Categories of market risks include exposures primarily related to
commodity prices through trading and marketing activities and non-trading
activities and interest rates.

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 and commercial transactions
related to our electric generating facilities, pipeline storage positions and
fuel positions of our wholesale energy segment and energy supply costs related
to our retail energy segment.

Given our current credit and liquidity situation and other factors, we
have reduced the level of our marketing and hedging activities, which could
result in greater volatility in future earnings. Additionally, the reduction in
market liquidity may impair the effectiveness of our risk management procedures
and hedging strategies. These and other factors may adversely impact our results
of operations, financial condition and cash flows. For further discussion of our
current liquidity situation and related impacts, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations - Financial
Condition" in this Form 10-Q.

71

We seek to monitor and control our trading risk exposures through a
variety of processes and committees. For additional information, see
"Quantitative and Qualitative Disclosures About Market Risk - Risk Management
Structure" in Item 7A to our Form 10-K/A.

TRADING MARKET RISK

We primarily assess the risk of our trading and marketing positions
using a value at risk method, in order to maintain our total exposure within
authorized limits. Value at risk is the potential loss in value of trading
positions due to adverse market movements over a defined time period within a
specified confidence level. We utilize the parametric variance/covariance method
with delta/gamma approximation to calculate value at risk, which relies on
statistical relationships to describe how changes in commodity and commodity
derivatives prices can affect a portfolio of instruments with different
characteristics and market exposures. The delta/gamma approximation captures
most of the effects of option price risk in the portfolio.

The following table presents the daily value at risk for substantially
all of our trading and marketing positions for the three months ended March 31,
2002 and 2003 based on a 95% confidence level and primarily a one day holding
period for natural gas and petroleum products and holding periods of 1 to 20
days based on the risk profile of the portfolio for power products:

The following chart sets forth the daily value at risk for
substantially all of our trading energy contracts for 2002 and the three months
ended March 31, 2003 (in millions):

[GRAPH]

02-Jan-02 26.676463 1st Qtr '02
03-Jan-02 24.183479
04-Jan-02 22.375085
07-Jan-02 20.874790
08-Jan-02 20.389015
09-Jan-02 20.113118
10-Jan-02 20.706310
11-Jan-02 19.643538
14-Jan-02 19.054364
15-Jan-02 18.666571
16-Jan-02 17.029784
17-Jan-02 16.611236
18-Jan-02 16.001698
22-Jan-02 15.523630
23-Jan-02 15.288009
24-Jan-02 14.019594
25-Jan-02 15.665395
28-Jan-02 15.537976
29-Jan-02 15.980875
30-Jan-02 14.813176
31-Jan-02 16.049377
01-Feb-02 16.124895
04-Feb-02 16.447596
05-Feb-02 16.656026
06-Feb-02 15.981168
07-Feb-02 16.244402
08-Feb-02 15.950182
11-Feb-02 16.345235
12-Feb-02 17.081628
13-Feb-02 16.620573
14-Feb-02 16.960932
15-Feb-02 15.962251
19-Feb-02 14.835315
20-Feb-02 16.331560
21-Feb-02 15.737517
22-Feb-02 15.697600
25-Feb-02 15.884714
26-Feb-02 15.887319
27-Feb-02 15.708853
28-Feb-02 16.467322
01-Mar-02 16.592633
04-Mar-02 16.376445
05-Mar-02 16.806287
06-Mar-02 16.998659
07-Mar-02 17.717750
08-Mar-02 17.724912
11-Mar-02 17.273979
12-Mar-02 18.281390
13-Mar-02 20.323490
14-Mar-02 20.417681
15-Mar-02 22.933827
18-Mar-02 23.399913
19-Mar-02 20.688638
20-Mar-02 20.129720
21-Mar-02 21.020971
22-Mar-02 25.269167
25-Mar-02 23.228581
26-Mar-02 17.096848
27-Mar-02 19.100329
28-Mar-02 21.832720
01-Apr-02 21.051432 2nd Qtr '02
02-Apr-02 20.676584
03-Apr-02 21.337720
04-Apr-02 22.628859
05-Apr-02 21.530983
08-Apr-02 19.340756
09-Apr-02 19.088772
10-Apr-02 17.453627
11-Apr-02 17.284762
12-Apr-02 15.830253
15-Apr-02 15.759115
16-Apr-02 16.658741
17-Apr-02 16.228374
18-Apr-02 18.093093
19-Apr-02 15.180074
22-Apr-02 15.599693
23-Apr-02 18.496613
24-Apr-02 17.003877
25-Apr-02 15.300660
26-Apr-02 14.168602
29-Apr-02 19.011957
30-Apr-02 20.492216
01-May-02 28.631690
02-May-02 27.479368
03-May-02 21.847182
06-May-02 20.649981
07-May-02 21.612589
08-May-02 17.620122
09-May-02 16.206207
10-May-02 15.986801
13-May-02 16.535656
14-May-02 16.420909
15-May-02 18.236031
16-May-02 16.986908
17-May-02 16.315261
20-May-02 14.851919
21-May-02 15.922760
22-May-02 14.505834
23-May-02 14.641230
24-May-02 14.705981
27-May-02 14.705981
28-May-02 13.356193
29-May-02 13.822162
30-May-02 13.824232
31-May-02 13.467221
03-Jun-02 13.521729
04-Jun-02 13.429241
05-Jun-02 13.934472
06-Jun-02 14.283001
07-Jun-02 14.322935
10-Jun-02 13.249175
11-Jun-02 12.255051
12-Jun-02 12.249443
13-Jun-02 13.842798
14-Jun-02 13.572789
17-Jun-02 15.831342
18-Jun-02 15.699607
19-Jun-02 15.766643
20-Jun-02 15.605657
21-Jun-02 15.871673
24-Jun-02 15.698299
25-Jun-02 15.813871
26-Jun-02 15.777534
27-Jun-02 18.657763
28-Jun-02 19.310591
01-Jul-02 17.845688 3rd Qtr '02
02-Jul-02 20.881125
03-Jul-02 18.208877
08-Jul-02 18.463888
09-Jul-02 17.941777
10-Jul-02 17.881900
11-Jul-02 18.284067
12-Jul-02 17.281151
15-Jul-02 16.925226
16-Jul-02 17.909412
17-Jul-02 17.706488
18-Jul-02 17.701477
19-Jul-02 18.135451
22-Jul-02 17.754845
23-Jul-02 17.598463
24-Jul-02 17.922393
25-Jul-02 17.243224
26-Jul-02 17.165637
29-Jul-02 19.274172
30-Jul-02 18.842591
31-Jul-02 18.585233
01-Aug-02 18.141710
02-Aug-02 17.526211
05-Aug-02 15.310580
06-Aug-02 14.583524
07-Aug-02 14.810409
08-Aug-02 14.452090
09-Aug-02 17.565959
12-Aug-02 17.185761
13-Aug-02 17.992094
14-Aug-02 17.214079
15-Aug-02 17.218585
16-Aug-02 17.007816
19-Aug-02 16.519377
20-Aug-02 16.317792
21-Aug-02 16.363601
22-Aug-02 16.341898
26-Aug-02 16.366858
27-Aug-02 16.413519
28-Aug-02 15.926125
29-Aug-02 16.201293
30-Aug-02 17.101937
03-Sep-02 17.150755
04-Sep-02 16.562920
05-Sep-02 19.305027
06-Sep-02 19.402914
09-Sep-02 19.861933
10-Sep-02 19.586210
11-Sep-02 20.373849
12-Sep-02 19.613558
13-Sep-02 18.915578
16-Sep-02 19.892541
17-Sep-02 18.720839
18-Sep-02 17.781622
19-Sep-02 17.927942
20-Sep-02 17.388962
23-Sep-02 16.827296
24-Sep-02 16.486522
25-Sep-02 18.250878
26-Sep-02 17.248238
27-Sep-02 17.906490
30-Sep-02 16.416469
01-Oct-02 17.282030 4th Qtr '02
02-Oct-02 16.460289
03-Oct-02 17.439790
04-Oct-02 18.988561
07-Oct-02 19.253919
08-Oct-02 18.253868
09-Oct-02 17.680351
10-Oct-02 16.405394
11-Oct-02 15.474757
14-Oct-02 13.475569
15-Oct-02 15.021409
16-Oct-02 15.733008
17-Oct-02 14.630044
18-Oct-02 14.612656
21-Oct-02 14.344752
22-Oct-02 14.252179
23-Oct-02 14.576717
24-Oct-02 14.165244
25-Oct-02 13.694244
28-Oct-02 12.409130
29-Oct-02 12.599202
30-Oct-02 13.209448
31-Oct-02 13.263924
01-Nov-02 12.835306
04-Nov-02 12.639991
05-Nov-02 12.353904
06-Nov-02 12.635204
07-Nov-02 10.814411
11-Nov-02 11.086840
12-Nov-02 11.028671
13-Nov-02 10.603895
14-Nov-02 10.090517
15-Nov-02 10.390872
18-Nov-02 10.282267
19-Nov-02 11.928633
20-Nov-02 12.587072
21-Nov-02 12.431696
22-Nov-02 11.931329
25-Nov-02 11.607350
26-Nov-02 12.492052
27-Nov-02 11.674227
02-Dec-02 12.647935
03-Dec-02 10.877963
04-Dec-02 11.031449
05-Dec-02 10.728842
06-Dec-02 11.194168
09-Dec-02 11.188438
10-Dec-02 11.045463
12-Dec-02 13.014498
13-Dec-02 14.659574
16-Dec-02 16.970943
17-Dec-02 17.114697
18-Dec-02 17.750687
19-Dec-02 20.161740
20-Dec-02 19.450170
23-Dec-02 18.739486
26-Dec-02 18.516200
27-Dec-02 17.543454
30-Dec-02 17.104278
31-Dec-02 17.497605
02-Jan-03 7.654723 1st Qtr '03
03-Jan-03 10.683250
06-Jan-03 10.005378
07-Jan-03 7.934425
08-Jan-03 7.648760
09-Jan-03 6.527508
10-Jan-03 6.597464
13-Jan-03 7.943082
14-Jan-03 8.218462
15-Jan-03 8.261003
16-Jan-03 9.035497
17-Jan-03 8.367825
20-Jan-03 8.617217
21-Jan-03 8.622302
22-Jan-03 8.721972
23-Jan-03 8.485828
24-Jan-03 8.480923
27-Jan-03 8.371762
28-Jan-03 8.601506
29-Jan-03 8.322424
30-Jan-03 8.378693
31-Jan-03 7.954905
03-Feb-03 7.902610
04-Feb-03 7.744612
05-Feb-03 7.615945
06-Feb-03 7.768556
07-Feb-03 8.276072
10-Feb-03 8.309436
11-Feb-03 7.784863
12-Feb-03 7.064942
13-Feb-03 6.726549
14-Feb-03 6.406174
18-Feb-03 5.798544
19-Feb-03 7.141499
20-Feb-03 6.982162
21-Feb-03 7.192427
24-Feb-03 6.649992
25-Feb-03 14.173641
26-Feb-03 24.286814
27-Feb-03 35.419761
28-Feb-03 26.952549
03-Mar-03 27.223976
04-Mar-03 21.570271
05-Mar-03 16.016121
06-Mar-03 14.622353
07-Mar-03 15.155995
10-Mar-03 14.429342
11-Mar-03 13.966493
12-Mar-03 14.902683
13-Mar-03 13.870525
14-Mar-03 14.136402
17-Mar-03 13.849757
18-Mar-03 12.855575
19-Mar-03 12.198487
20-Mar-03 11.983648
21-Mar-03 11.820056
24-Mar-03 11.912188
25-Mar-03 10.845397
26-Mar-03 10.889862
28-Mar-03 10.817717
31-Mar-03 10.347316

During the three months ended March 31, 2003, average value at risk
exposure was lower compared to the full year in 2002 due to certain power
marketing activities in ERCOT related to our retail energy segment no longer
being accounted for on a mark-to-market method of accounting. Lower overall
trading volumes during the three months ended March 31, 2003 due to the decline
in proprietary trading also contributed to a reduction in value at risk. The
increase in value at risk during February 2003 was due to volatility in the
natural gas market.

72

We have included the following value at risk calculations in response
to the CCRO best practices issued in November 2002 with respect to our trading
and marketing contracts based on the assumptions proposed by the CCRO
disclosures as denoted below for the three months ended March 31, 2003 (in
millions):

NON-TRADING MARKET RISK

We assess the risk of our non-trading derivatives using a sensitivity
analysis method.

Commodity Price Risk. Derivative instruments, which we use as economic
hedges, create exposure to commodity prices, which, in turn, offset the
commodity exposure inherent in our businesses. The stand-alone commodity risk
created by these instruments, without regard to the offsetting effect of the
underlying exposure these instruments are intended to hedge, is described below.
The sensitivity analysis performed on our non-trading energy derivatives
measures the potential loss in earnings based on a hypothetical 10% movement in
energy prices. A decrease of 10% in the market prices of energy commodities from
their March 31, 2003 levels would have decreased the fair value of our
non-trading energy derivatives by $63 million.

The following table sets forth our power generation operations hedging
information estimated over the next three years as of March 31, 2003:

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

(1) Estimated plant output hedged represents the portion of MWhs of future
net generating capacity of our power generation facilities to be sold
under existing contracts.

(2) Estimated plant fuel requirements hedged represents the portion of
estimated future fuel requirements of our power generation facilities
based on MMbtu equivalents and net generating capacity to be purchased
under existing contracts.

(3) Trading and non-trading activities related to our power generation
facilities (owned or leased) are included in the calculations.

Interest Rate Risk. We have issued long-term debt and have obligations
under bank facilities that subject us to the risk of loss associated with
movements in market interest rates.

Our floating-rate obligations aggregated $7.2 billion at March 31,
2003, excluding the book value of the warrants outstanding of $15 million. If
the floating interest rates were to increase by 10% from March 31, 2003 rates,
our interest expense would increase by a total of $2.8 million each month in
which such increase continued.

At March 31, 2003, we had issued fixed-rate debt to third parties
aggregating $557 million, excluding Liberty's fixed-rate debt of $165 million.
As of March 31, 2003, the fair values of these debt instruments, excluding
Liberty's fixed rate debt, were $442 million. These instruments are fixed-rate
and, therefore, do not expose us to the risk of loss in earnings due to changes
in market interest rates. However, the fair value of these instruments,
excluding Liberty's fixed-rate debt, would increase by $29 million if interest
rates were to decline by 10% from their rates at March 31, 2003.

As of March 31, 2003, we have interest rate swap contracts with an
aggregate notional amount of $1.1 billion that fix the interest rate applicable
to floating rate short-term debt and floating rate long-term debt. These swaps

73

could be terminated at a cost of $126 million at March 31, 2003. These
derivative instruments qualify for hedge accounting under SFAS No. 133 and the
periodic settlements are recognized as an adjustment to interest expense in the
results of operations over the term of the related agreement. A decrease of 10%
in the March 31, 2003 level of interest rates would increase the cost of
terminating the interest rate swaps by $8 million. For information regarding the
accounting for these interest rate derivative instruments, see notes 8 and 10 to
our interim financial statements.

During January 2003, we purchased three-month LIBOR interest rate caps
to hedge our future floating rate risk associated with various credit
facilities. We have hedged $4.0 billion for the period from July 1 to December
31, 2003, $3.0 billion for 2004 and $1.5 billion for 2005. The interest rate
caps had a market value of $12 million at March 31, 2003. These derivative
instruments qualify for hedge accounting under SFAS No. 133. A decrease of 10%
in the March 31, 2003 level of interest rates would cause the market value of
the interest rate caps to decline by $3 million. For information regarding the
accounting for these interest rate derivative instruments, see notes 8 and 10 to
our interim financial statements.

ITEM 4. CONTROLS AND PROCEDURES

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our chief executive officer and chief financial officer have evaluated
the effectiveness of our disclosure controls and procedures (as such term is
defined in Rules 13a-14(c) and 15d-14(c) under the Securities Exchange Act of
1934) as of a date, the evaluation date, within 90 days prior to the filing date
of our Form 10-Q. Based on such evaluation, such officers have concluded that,
as of the evaluation date, our disclosure controls and procedures are effective
in alerting them on a timely basis to material information required to be
included in our reports filed or submitted under the Securities Exchange Act of
1934.

CHANGES IN INTERNAL CONTROLS

Since the evaluation date, there have not been any significant changes
in our internal controls or in other factors that could significantly affect
such controls.

74

PART II.
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For a description of legal proceedings affecting us, see note 13 to our
interim financial statements.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.

In connection with our March 2003 refinancing, we issued to the lenders
20,373,326 warrants to acquire shares of our common stock. The exercise prices
of the warrants are based on average market prices of our common stock during
specified periods in proximity to the refinancing date. Of 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. 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. We received no separate cash or other consideration for the issuance of
the warrants. The issuance of the warrants was not registered with the SEC in
reliance upon Regulation D promulgated under the Securities Act of 1933.

ITEM 5. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

(a) Exhibits.

See Index of Exhibits, which includes the management contracts or
compensatory plans or arrangements required to be filed as exhibits to this Form
10-Q by Item 601 of Regulation S-K.

(b) Reports on Form 8-K.

o Current Report on Form 8-K dated January 3, 2003, as filed with the SEC
on January 3, 2003 (Items 7 and 9).

o Current Report on Form 8-K dated January 7, 2003, as filed with the SEC
on January 10, 2003 (Items 5 and 7).

o Current Report on Form 8-K dated January 30, 2003, as filed with the
SEC on January 30, 2003 (Items 7 and 9).

o Current Report on Form 8-K dated January 30, 2003, as filed with the
SEC on February 3, 2003 (Items 5 and 7).

o Current Report on Form 8-K dated February 18, 2003, as filed with the
SEC on February 24, 2003 (Items 5 and 7).

o Current Report on Form 8-K dated March 7, 2003, as filed with the SEC
on March 17, 2003 (Items 5 and 7).

o Current Report on Form 8-K dated March 24, 2003, as filed with the SEC
on March 24, 2003 (Items 5 and 7).

o Current Report on Form 8-K dated March 26, 2003, as filed with the SEC
on March 28, 2003 (Items 5 and 7).

75

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the Registrant has duly caused this Quarterly Report on
Form 10-Q to be signed on its behalf by the undersigned, thereunto duly
authorized.

RELIANT RESOURCES, INC.
(Registrant)

By: /s/ Thomas C. Livengood
-------------------------------
Thomas C. Livengood
Vice President and Controller
(Principal Accounting Officer)
May 13, 2003

76

CERTIFICATIONS

I, Joel V. Staff, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Reliant
Resources, Inc.;

2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Quarterly Report;

3. Based on my knowledge, the financial statements, and other financial
information included in this Quarterly Report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the Registrant as of, and for, the periods presented in
this Quarterly Report;

4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant
and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Quarterly Report is being prepared;

(b) evaluated the effectiveness of the Registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Quarterly Report (the "Evaluation Date"); and

(c) presented in this Quarterly Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The Registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the Registrant's auditors and the
audit committee of Registrant's board of directors (or persons
performing the equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the Registrant's
ability to record, process, summarize and report financial data
and have identified for the Registrant's auditors any material
weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the Registrant's
internal controls; and

6. The Registrant's other certifying officers and I have indicated in this
Quarterly Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent evaluation,
including any corrective actions with regard to significant
deficiencies and material weaknesses.

Date: May 13, 2003 /s/ Joel V. Staff
------------------------------
Joel V. Staff
Chairman and
Chief Executive Officer

77

CERTIFICATIONS

I, Mark M. Jacobs, certify that:

1. I have reviewed this Quarterly Report on Form 10-Q of Reliant
Resources, Inc.;

2. Based on my knowledge, this Quarterly Report does not contain any
untrue statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this Quarterly Report;

3. Based on my knowledge, the financial statements, and other financial
information included in this Quarterly Report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the Registrant as of, and for, the periods presented in
this Quarterly Report;

4. The Registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant
and we have:

(a) designed such disclosure controls and procedures to ensure that
material information relating to the Registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
Quarterly Report is being prepared;

(b) evaluated the effectiveness of the Registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this Quarterly Report (the "Evaluation Date"); and

(c) presented in this Quarterly Report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The Registrant's other certifying officers and I have disclosed, based
on our most recent evaluation, to the Registrant's auditors and the
audit committee of Registrant's board of directors (or persons
performing the equivalent function):

(a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the Registrant's
ability to record, process, summarize and report financial data
and have identified for the Registrant's auditors any material
weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the Registrant's
internal controls; and

6. The Registrant's other certifying officers and I have indicated in
this Quarterly Report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: May 13, 2003 /s/ Mark M. Jacobs
----------------------------
Mark M. Jacobs
Executive Vice President and
Chief Financial Officer

78

INDEX OF EXHIBITS

Exhibits not incorporated by reference to a prior filing are designated
by a cross (+); all exhibits not so designated are incorporated herein by
reference to a prior filing as indicated. Exhibits designated by an asterisk (*)
are management contracts or compensatory plans or arrangements required to be
filed as exhibits to this Form 10-Q by Item 601(b)(10)(iii) of Regulation S-K.