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 JUNE 30, 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 Identification No.)
organization)

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 August 11, 2003, Reliant Resources, Inc. had 294,337,364 shares of common
stock outstanding, excluding 5,466,636 shares held by the Registrant as treasury
stock.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTERLY PERIOD ENDED JUNE 30, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Statements of Operations (unaudited)
Three and Six Months Ended June 30, 2002 (as restated) and 2003.........................................1

Consolidated Balance Sheets (unaudited)
December 31, 2002 and June 30, 2003 ....................................................................2

Consolidated Statements of Cash Flows (unaudited)
Six Months Ended June 30, 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..................56

Item 3. Quantitative and Qualitative Disclosures About Market Risk.............................................88

Item 4. Controls and Procedures................................................................................91

PART II. OTHER INFORMATION

Item 1. Legal Proceedings......................................................................................92

Item 2. Changes in Securities and Use of Proceeds..............................................................92

Item 6. Exhibits, Financial Statement Schedules and Reports on Form 8-K........................................92

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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, "Management's Discussion and
Analysis of Financial Condition and Results of Operations - Risk Factors" in
Item 7 of our Form 10-K/A filed on May 1, 2003 and "Management's Discussion and
Analysis of Financial Condition and Results of Operations" for the three months
ended March 31, 2002 and 2003 in our Current Report on Form 8-K filed on July
23, 2003.

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PART I.
FINANCIAL INFORMATION

RELIANT RESOURCES, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF 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
CONSOLIDATED STATEMENTS OF 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 in conjunction with our consolidated financial
statements and notes in our Current Report on Form 8-K filed on June 30, 2003
(Form 8-K).

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 8-K.

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 $4.2 million and
$5.3 million ($2.7 million and $3.4 million after-tax, respectively) for the
three and six months ended June 30, 2002, respectively.

The consolidated statements of operations and cash flows for the three and
six months ended June 30, 2002 have been restated from amounts previously
reported to correctly account for the amount of hedge ineffectiveness in the
first and second quarters of 2002. The restatement had no impact on previously
reported consolidated total operating, investing and financing cash flows for
the six months ended June 30, 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 and six months ended June
30, 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 required by SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS
No. 142), 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.

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 consolidated statements of 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
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

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amounts from the prior periods have been reclassified to conform to the 2003
presentation of financial statements. These reclassifications do not affect
earnings.

The consolidated statements of 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 and six months ended June
30, 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 and other operations. The retail energy segment includes our
retail electric operations and associated supply activities. This segment
provides customized electricity and related energy services to large commercial,
industrial and institutional customers in Texas and, to a lesser extent, in New
Jersey. We also provide 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 includes our non-ERCOT
portfolio of electric power generation facilities and related fuel delivery and
storage asset positions. The wholesale energy segment procures fuel and markets
energy and energy services to optimize its asset portfolio. The other operations
segment primarily includes unallocated general corporate expenses and
non-operating investments. See note 18 regarding the sale of our European energy
operations and the classification as discontinued operations.

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 June 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
required 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 consolidated statement of operations for
the six months ended June 30, 2003. Included in the gain is $16 million, net of
tax of $7 million, related to our European energy operations, which are now
reported as discontinued operations.

The impact of 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 adopted on
January 1, 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):

Balance at January 1, 2003 ............. $ 11
Accretion expense ...................... 1
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Balance at June 30, 2003 ............... $ 12
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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. One change from the previous standard is that under SFAS
No. 144, assets disposed of or held for sale that meet the definition to be 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

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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 18). Also, in accordance with SFAS No. 144,
our Desert Basin plant operations will be reflected as discontinued operations
beginning in the third quarter of 2003 (see note 19).

SFAS No. 145. In April 2002, the FASB issued SFAS No. 145, "Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current
requirement that gains and losses on debt extinguishment must be classified as
extraordinary items in the statement of operations. Instead, such gains and
losses will be classified as extraordinary items only if they are deemed to be
unusual and infrequent. SFAS No. 145 also requires sale-leaseback accounting for
certain lease modifications that have economic effects that are similar to
sale-leaseback transactions. The changes related to debt extinguishment will be
effective for fiscal years beginning after May 15, 2002 (which we began to apply
effective January 1, 2003) and the changes related to lease accounting are
effective for transactions occurring after May 15, 2002 (which we began to apply
at that time).

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 announced that it plans 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 with the exercise price
equal to or greater than 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 income (loss) and per share amounts would
have approximated the following pro forma results for the three and six months
ended June 30, 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:

For further information regarding our stock-based compensation plans and
our assumptions used to compute pro forma amounts, see note 12 to our Form 8-K.

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 the
prospective guidance in this statement will have on our consolidated financial
statements.

SFAS No. 150. In May 2003, the FASB issued SFAS No. 150, "Accounting for
Certain Financial Instruments with Characteristics of Both Liabilities and
Equity" (SFAS No. 150). This statement requires that an issuer classify a
financial instrument that is within its scope as a liability (or an asset in
some circumstances) because that financial instrument embodies an obligation of
the issuer. SFAS No. 150 is generally effective for financial instruments
entered into or modified after May 31, 2003 and otherwise is effective for us
beginning July 1, 2003. The adoption of SFAS No. 150 will not have a material
impact 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, for guarantees of obligations
of unconsolidated entities, 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 had 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 as of and for the three
and six months ended June 30, 2003 as the fair value of guarantees entered into
after December 31, 2002 was nominal on the date in which the guarantee was
entered. See note 13(c).

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

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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 for
variable interest entities created after January 31, 2003, and for variable
interest entities in which an enterprise obtains an interest after that date.
For enterprises that acquired variable interests prior to February 1, 2003, the
effective date is for fiscal years or interim periods beginning after June 15,
2003. FIN No. 46 requires entities to either (a) record the effects
prospectively with a cumulative effect adjustment as of the date on which FIN
No. 46 is first applied or (b) restate previously issued financial statements
for the years with a cumulative effect adjustment as of the beginning of the
first year being restated. We adopted FIN No. 46 on January 1, 2003. Results for
the three and six months ended June 30, 2003, include the cumulative effect of
accounting change of $1 million loss, net of tax, effective January 1, 2003
related to the prospective adoption of FIN No. 46. See note 13(a).

As of December 31, 2002, we had variable interests in three power
generation projects that were being constructed by off-balance sheet special
purpose entities under construction agency agreements, which pursuant to this
guidance required 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 notes 10 and 13(a).

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 was 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 report all energy trading and marketing activities on a
net basis in the consolidated statements of 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 and six months
ended June 30, 2002 as follows:

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(1) These amounts do not reflect the adjustments due to the restatement as
discussed in note 1.

(2) Some amounts from the previous period have been reclassified to conform to
the presentation of our consolidated statements of operations for the three
and six months ended June 30, 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 was
effective for us for the first quarter of 2003. We recorded a cumulative effect
of a change in accounting principle of $42 million loss, net of tax of $22
million, or $0.14 per diluted share, effective January 1, 2003, related to EITF
No. 02-03 for the six months ended June 30, 2003. During the three months ended
June 30, 2003, we recorded an adjustment to our cumulative effect of accounting
changes of $862,000 gain, net of tax. The 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

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in January 2003, we began applying the "normal" purchase and sale exception of
SFAS No. 133 to a substantial portion of 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 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
consolidated statements of 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 electricity sales 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. 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 and six months ended June 30, 2002 and 2003. During
the three and six months ended June 30, 2002, our retail energy segment
realized $12 million and $14 million, respectively, of previously unrealized net
losses related to its contracted electricity sales to large commercial,
industrial and institutional customers and the related energy supply contracts.
During the three and six months ended June 30, 2003, volumes were delivered
under contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts for which $14
million and $31 million, respectively, was previously recognized as unrealized
earnings in prior periods. As of June 30, 2003, our retail energy segment has
unrealized gains that have been previously recorded in our results of operations
of $62 million that will be realized when the electricity is delivered to our
customers ($35 million in the remainder of 2003 and $27 million in 2004 and
beyond). These unrealized gains of $62 million are recorded in non-trading
derivative assets/liabilities in our consolidated balance sheet as of June 30,
2003 and the related contracts are accounted for as cash flow hedges or "normal"
sales contracts under SFAS No. 133.

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 and six months ended June 30, 2002, we recorded $26 million and $46
million, respectively, of fair value at the contract inception related to
trading and marketing activities. For the three and six months ended June 30,
2003, we did not recognize any gains at inception. Inception gains are recorded
only when 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 and six months ended June 30, 2002, were $5 million and $10 million,
respectively, 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 and six months
ended June 30, 2002, we incurred $8 million and $16 million, respectively, of
rent expense to CenterPoint. Net interest income related to various net
receivables representing transactions between us and CenterPoint or its
subsidiaries was $1 million and $4 million, respectively, during the three and
six months ended June 30, 2002.

12

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 consolidated
statements of operations. Purchases of electric generation energy and capacity
and electric transmission services from CenterPoint and its subsidiaries were
$674 million and $854 million, respectively, for the three and six months ended
June 30, 2002. During the three and six months ended June 30, 2002, the net
purchases and sales and services from/to CenterPoint and its subsidiaries
related to our trading and marketing operations totaled $216 million and $145
million, respectively. In addition, during the three and six months ended June
30, 2002, other sales and services to CenterPoint and its subsidiaries totaled
$13 million. Sales and purchases to/from CenterPoint subsequent to the
Distribution are not reported as affiliated transactions.

We have 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 8-K. As of June 30, 2003, we had
purchased entitlements to capacity of Texas Genco averaging 6,390 megawatts (MW)
per month in 2003, 715 MW per month in 2004 and 298 MW per month in 2005. Our
anticipated capacity payments related to these capacity entitlements are $214
million for the remainder of 2003, $148 million for 2004 and $57 million for
2005.

During the three months ended June 30, 2002 and 2003, CenterPoint made no
equity contributions to us. During the six months ended June 30, 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. Under its agreement with us, Texas
Genco must auction all of its capacity that remains subsequent to the capacity
auctions mandated under PUCT rules and after certain other adjustments. We have
the option to purchase 50% of such remaining capacity at the prices established
in such auctions. We also have the right to participate directly in such
auctions, without any restrictions on our level of participation. 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 granted Texas Genco a security interest in the accounts receivable and
related assets of certain of our subsidiaries and removed many of the
restrictive covenants contained in the agreement. The liens on the accounts
receivable and related assets are junior to certain permitted prior financing
arrangements and senior to the liens granted to the lenders under the March
2003 credit facilities. In July 2003, the agreement was further amended to
facilitate the transfer of the junior lien in the accounts receivable and the
related assets to the collateral trustee to ratably secure the senior secured
notes and the March 2003 credit facilities.

In January 2003, CenterPoint distributed approximately 19% of the common
stock of Texas Genco to CenterPoint shareholders. CenterPoint has granted us an
option to purchase all of the remaining shares of common stock of Texas Genco
held by CenterPoint. The option must be exercised between January 10, 2004 and
January 24, 2004. 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. 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 ending January 9, 2004, plus a control premium, up to a
maximum of 10%, to the extent a control premium is included in the valuation
determination made by the PUCT. The exercise price is also subject to

13

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. In the event that we exercise the option,
we have the right to rescind our exercise within 45 days if we are unable to
secure financing for the purchase of the Texas Genco shares on reasonable terms.
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, upon exercise of the Texas Genco
option, assume CenterPoint's obligations in exchange for a payment to us by
CenterPoint of an amount equal to the principal, plus accrued interest. See note
10 for discussion of our Texas Genco option and the related impacts from our
various credit facilities and notes.

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,
settlement and communication with the independent system operator. The fees we
charge for these services are designed to allow us to recover our fully
allocated direct and indirect costs and reimbursement of out-of-pocket expenses.
Expenses associated with capital investment in systems and software that benefit
both the operation of Texas Genco's facilities and our facilities in other
regions are allocated on an installed MW basis. The term of this agreement will
end on the first to occur of (a) the closing date of our possible 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 tables summarize 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

14

804 MW of capacity under construction. During 2002, both projects under
construction 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, after receiving 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. See note 7 for
a discussion of possible impairments of our wholesale energy segment's goodwill.

Our results of operations include the results of Orion Power for the period
beginning February 19, 2002. The following tables present selected financial
information and unaudited pro forma information for the six months ended June
30, 2002, as if the acquisition had occurred on January 1, 2002.

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 fair 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 information
presented above reflects 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 charged
to results of operations in periods in which the recorded value of goodwill and
certain intangibles with indefinite lives exceeds their fair values. We adopted
the provisions of the statement effective January 1, 2002, and discontinued
amortizing goodwill into our results of operations.

As of March 31, 2002, we completed our assessment of intangible assets and
no intangible assets with indefinite lives were identified, except for $1
million of air emissions regulatory allowances. 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.

15

During the third quarter of 2002, we completed the transitional goodwill
impairment test required by SFAS No. 142, including the review of goodwill for
impairment as of January 1, 2002. A goodwill 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 exceeds the 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 our
transitional 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 (which activity was subsequently discontinued in its
entirety in the third quarter of 2002). 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.

SFAS No. 142 requires goodwill to be tested annually and between annual
tests if events occur or circumstances change that would "more likely than not"
reduce the fair value of a reporting unit below its carrying amount. Our annual
test for indications of goodwill impairment is currently performed 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 18). 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 such impairment test. Our annual impairment test
determined that the full amount of our European energy segment's net goodwill of
$482 million was impaired and such impairment was recorded in the fourth quarter
of 2002. For additional information regarding this transaction and its impacts,
see note 18.

Our annual impairment test identified no other impairments of goodwill for
our other reporting units. This annual goodwill impairment test indicated that
the fair value of our wholesale energy reporting unit exceeded its carrying
value by approximately five percent.

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

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

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 similar mechanisms in
regions where they currently do not exist.

The internal cash flow analyses used in our November 1, 2002 impairment
analysis for our wholesale energy reporting unit was over a period of 15 years
with an assumed terminal value for the value of our operations at the end of the
analysis of an EBITDA (earnings from continuing operations before depreciation
and amortization,

16

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

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

Evaluation of Goodwill Related to our Wholesale Energy Segment. On July 9,
2003, we entered into a definitive agreement to sell our 588-megawatt Desert
Basin plant (see note 19). This anticipated sale of our Desert Basin plant
operations requires us, in accordance with SFAS No. 142, to allocate a portion
of the goodwill in the wholesale energy reporting unit to the Desert Basin plant
operations on a relative fair value basis as of July 2003 in order to compute
the gain or loss on disposal. SFAS No. 142 also requires us to test the
recoverability of goodwill in our remaining wholesale energy reporting unit as
of July 2003. After the allocation of goodwill to the Desert Basin plant
operations, our wholesale energy segment's remaining goodwill is estimated to be
approximately $1.4 billion, which is being tested for impairment effective July
2003. The assessment of goodwill requires developing an updated estimate of the
fair value of our wholesale energy reporting unit, which is expected to be
completed by the end of the third quarter of 2003.

In response to continued depressed prices for electric energy, capacity and
ancillary services across much of the United States and our current judgments
regarding the state of the wholesale electricity markets, we are in the process
of evaluating our short-term and long-term strategies and activities. During the
first quarter of 2003, we decided to exit our proprietary trading activities. We
are presently evaluating, and may soon implement, (a) further reductions in
commercial, operational and support groups to reduce costs, (b) further changes
in our market strategies, (c) mothballing or retiring certain power generation
facilities, (d) deferring and/or materially reducing maintenance expenditures at
power generation facilities and (e) divesting of certain assets. Also, we are
evaluating the method of projecting future cash flows from our wholesale energy
segment operations. In connection with this effort, our future cash flow
projections and plans may be significantly revised.

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

Our July 2003 impairment analysis will reconsider the assumptions discussed
above and others, including: estimates of future market prices for power and
fuel, valuation of plant and equipment, growth, regulation of wholesale power
markets, market structure, competition and many other factors as of the
determination date. The resulting impairment analysis is highly dependent on
these underlying assumptions.

In addition, if our wholesale energy market outlook and views change
further in future periods and the current weak environment is prolonged or if
current conditions decline further, we could have impairments of our property,
plant and equipment in future periods which, in turn, could have a material
adverse effect on our results of operations.

(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

17

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 and six months ended June 30,
2002 and 2003, we did not enter into any fair value hedges and as of December
31, 2002 and June 30, 2003, we had no fair value hedges. For a discussion of our
hedge of foreign currency exposure of our anticipated net proceeds from the sale
of our European energy operations, see note 18.

Cash Flow Hedges. During the three months ended June 30, 2002, 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(b)), was a gain of $8 million. During the three months
ended June 30, 2003, the gain or loss related to ineffectiveness for these cash
flow hedges was immaterial. During the six months ended June 30, 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, was a gain of $7 million and a loss of $20 million,
respectively. For the three and six months ended June 30, 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 recognize 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 and six months ended June 30, 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 consolidated statements of 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 derivative transactions. As of June 30, 2003, we expect $55
million of gains netted in accumulated other comprehensive loss to be
reclassified into net income (loss) during the period from July 1, 2003 to June
30, 2004.

(9) EQUITY INVESTMENTS

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 are as follows:

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

During the three months ended June 30, 2002 and 2003, the net distributions
were $0 and $1 million, respectively, from these investments. During the six
months ended June 30, 2002 and 2003, the net distributions were $2 million and
$2 million, respectively, from these investments.

18

As of June 30, 2003 the companies, in which we have an equity investment,
carry debt that is currently estimated to be $138 million ($69 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:

19

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

The following table presents our debt outstanding to third parties as of
December 31, 2002 and June 30, 2003:

- ----------

(1) The weighted average interest rate is for borrowings outstanding as of
December 31, 2002 or June 30, 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) In July 2003, with the net proceeds of our issuance of senior secured
notes, we prepaid $1.056 billion of a senior secured term loan. See below
for further discussion.

(4) In connection with the 5.00% convertible senior subordinated notes issued
in June 2003, an additional $50 million was subsequently issued and funded
in July 2003, for a total outstanding balance of $275 million. See below
for further discussion.

(5) 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.

(6) 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 $2 million and $2 million for valuation
adjustments for debt and $7 million and $5 million for valuation
adjustments for interest rate swaps, respectively, for the three months
ended June 30, 2002 and 2003, respectively. Included in interest expense is
amortization of $3 million and $4 million for valuation adjustments for
debt and $10 million and $12 million for valuation adjustments for interest
rate swaps, respectively, for the six months ended June 30, 2002 and 2003,
respectively. These valuation adjustments are being amortized over the
respective remaining terms of the related financial instruments.

(7) The fair value of the warrants issued in March 2003 of $15 million ($13
million unamortized as of June 30, 2003) 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.
Such restrictions are on the net assets of Orion Capital, Liberty Electric PA,
LLC (Liberty) and Reliant Energy Channelview L.P. (Channelview). Orion MidWest
and Orion NY are indirect wholly-owned subsidiaries of Orion Capital.

20

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

The following table provides a summary of the amounts owed and amounts
available as of June 30, 2003 under our various committed credit facilities,
bonds and notes:

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

(1) In July 2003, with the net proceeds of our issuance of senior secured
notes, we prepaid $1.056 billion of a senior secured term loan, satisfying
the March 2006 principal amortization requirement.

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

(3) The senior priority revolver facility expires on the earlier of our
possible acquisition of the common stock of Texas Genco or December 15,
2004.

(4) In connection with the 5.00% convertible senior subordinated notes issued
in June 2003, an additional $50 million was subsequently issued and funded
in July 2003, for a total commitment of $275 million. See below for further
discussion.

(5) As discussed below and in note 13(f), this amount is currently not
available to Liberty.

As of June 30, 2003, committed credit facilities and notes aggregating $676
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 bank 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 March 2003 credit
facilities mature in March 2007. The $300 million senior priority revolving
credit facility matures on the earlier of our possible acquisition of the common
stock of Texas Genco or December 15, 2004 and is secured with a first lien on
substantially all of our contractually and legally available assets. The senior
secured 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.

We must use the proceeds of any loans under the senior priority revolving
credit facility solely to secure or prepay our ongoing commercial and trading
obligations and not for other general corporate or working capital purposes. We
must use the proceeds of any loans under the senior secured revolving credit
facility solely for working capital and other general corporate purposes. We are
not permitted to use the proceeds from loans under any of these facilities to
acquire Texas Genco.

The loans under the refinanced credit facilities bear interest at 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. However, with the net proceeds of our
issuance of senior secured notes on July 1, 2003, we have satisfied the May 2004
and May 2005 permanent reduction amounts and therefore will not be required to
pay the above-described fees on either

21

such date. We must prepay the refinanced facilities with net 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).
However, with the net proceeds of our issuance of senior secured notes on July
1, 2003, we have made prepayments on the refinanced facilities sufficient to
satisfy the May 2006 principal payment requirement. Our March 2003 credit
facilities include restrictions on 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 (two of which were completed in
July 2003), the preservation and optimization of all of our existing investments
in the retail energy and wholesale energy businesses, the ability to provide
credit support for our commercial obligations and the possible acquisition of
the common stock of 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 certain 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 an 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. Our failure to comply with these
covenants could result in an event of default that, if not cured or waived,
could result in our being required to repay these borrowings before their
scheduled due dates.

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

In connection with our July 2003 issuance of senior secured notes,
described below, we entered into an amendment to our March 2003 credit
facilities to, among other things, permit the sharing of collateral with those
notes and certain future note offerings and increase our flexibility to purchase
CenterPoint's interest in Texas Genco. The amendment allows us to negotiate a
purchase of CenterPoint's interest in the common stock of Texas Genco outside
the option and also extends the deadline for agreeing to make the purchase until
September 15, 2004. The amendment also revises the collateral mechanics to
replace the collateral agent with a collateral trustee for the benefit of the
banks and the secured bondholders, including the holders of the senior secured
notes, revises the mandatory prepayment provisions so that the senior secured
notes may share pro rata with the banks any net proceeds from asset sales
required to be paid to the banks and separates the Orion Power limited guarantee
from the credit agreement so it can ratably guarantee the bank debt and the
senior secured notes.

Convertible Senior Subordinated Notes. In June 2003, we issued $225 million
aggregate principal amount of convertible senior subordinated notes in a private
placement to qualified institutional buyers. On July 2, 2003, we issued an
additional $50 million as a result of the underwriters' exercise of their option
to purchase additional notes. We received net proceeds from the issuances, after
deducting the initial purchasers' discount and estimated out-of-pocket expenses,
of $266 million. Our March 2003 credit facilities permit us to place cash
proceeds from certain asset sales and offerings of junior securities in a
restricted escrow account for the possible acquisition of the common stock of
Texas Genco, and the net proceeds of the notes were placed in such an escrow
account (and are recorded as long-term restricted cash in our consolidated
balance sheet). The notes bear interest at 5.00% per annum, payable
semi-annually on February 15 and August 15, and mature August 15, 2010. The
first interest payment will be made on August 15, 2003. The notes are
convertible into shares of our common stock at a conversion price of
approximately $9.54 per share, subject to adjustment in certain circumstances.
We may redeem the notes, in whole or in part, at any time on or after August 20,
2008, if the last reported sale price of our common stock is at least 125% of
the conversion price then in effect for a specified period of time.

22

Senior Secured Notes. On July 1, 2003, we issued $550 million 9.25% senior
secured notes due July 15, 2010 and $550 million 9.50% senior secured notes due
July 15, 2013 in a private placement to qualified institutional buyers and
received net proceeds, after deducting the initial purchasers' discount and
estimated out-of-pocket expenses, of $1.056 billion. We used the net proceeds of
the issuance to prepay $1.056 billion of a senior secured term loan under our
refinanced credit facilities. With certain limited exceptions, the senior
secured notes are secured by the same collateral which secures our refinanced
credit facilities. The collateral is held by a collateral trustee under a
collateral trust agreement for the ratable benefit of all holders of the credit
agreement debt, senior secured note holders and future senior secured note
holders. The senior secured notes are also guaranteed by all of our subsidiaries
that guarantee our refinanced credit facilities, except for certain subsidiaries
of Orion Power and certain other subsidiaries. See note 16 for further
discussion of the guarantors, the limited guarantor and the non-guarantors.
Interest is payable semi-annually on January 15 and July 15. The first interest
payments will be made on January 15, 2004. We are not required to make any
mandatory redemption or sinking fund payments with respect to the senior secured
notes. The senior secured notes indentures contain covenants which bind us and
our subsidiaries that include, among others, restrictions on (a) the payment of
dividends, (b) the incurrence of indebtedness and the issuance of preferred
stock, (c) investments, (d) asset sales, (e) liens, (f) transactions with
affiliates, (g) our ability to amend the subordination provisions of our
convertible senior subordinated notes, (h) engaging in unrelated businesses and
(i) sale and leaseback transactions. These covenants are not expected to
materially restrict our ability to conduct our business.

Financing Costs. Through June 30, 2003, we have incurred approximately $206
million in financing costs (which includes $15 million to be paid in March 2007)
related to our 2003 refinancings and June and July 2003 debt issuances. We
capitalized $170 million and expensed $36 million (of which $12 million was
expensed in the fourth quarter of 2002 and $1 million and $24 million was
expensed during the three and six months ended June 30, 2003, respectively) in
fees and other costs related to our refinancing efforts and debt issuances.
During July 2003, as a result of issuing the senior secured notes and the
prepayment of a senior secured term loan of the March 2003 refinancing totaling
$1.056 billion, we wrote-off $31 million of previously deferred financing costs
related to the March 2003 refinancing. As of December 31, 2002 and June 30,
2003, we had $68 million and $233 million, respectively, of net deferred
financing costs classified in other long-term assets in our consolidated balance
sheets.

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 to interest expense using
the effective interest rate method over the life of the senior notes. For the
three months ended June 30, 2002 and the period February 20, 2002 to June 30,
2002, $2 million and $3 million, respectively, was amortized to interest expense
for the senior notes. For the three and six months ended June 30, 2003, $2
million and $4 million, respectively, 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's limited guarantee of the
refinanced credit facilities, the senior priority revolving credit facility and
the senior secured notes effectively utilized the dividend capacity available on
March 28, 2003 under the Orion Power senior notes indenture.

Orion NY and Orion MidWest 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

23

obligations under the amended and restated Orion NY credit agreement.
Substantially all of the assets of Orion MidWest and its subsidiary are pledged,
via a second lien, as collateral for this guarantee. The amended and restated
Orion MidWest credit facility is, in turn, secured by a first lien on
substantially all of the assets of Orion MidWest and its subsidiary. Orion NY
and its subsidiaries are guarantors of the Orion MidWest obligations under the
amended and restated Orion MidWest credit agreement. A substantial portion of
the assets of Orion NY and its subsidiaries (excluding certain plants) are
pledged, via a second lien, as collateral for this guarantee. Both the Orion
MidWest and Orion NY credit facilities contain affirmative and negative
covenants, including negative pledges, that must be met by each borrower under
its respective facility to borrow funds or obtain letters of credit, and which
require Orion MidWest and Orion NY to maintain a combined debt service coverage
ratio of 1.5 to 1.0. These covenants are not anticipated to materially restrict
either borrower's ability to borrow funds or obtain letters of credit under its
respective credit facility. The facilities also provide for any available cash
at one borrower to be made available to the other borrower to meet shortfalls in
the other borrower's ability to make certain payments, including operating
costs. This is effected through distributions of such available cash to Orion
Capital, a direct subsidiary of Orion Power formed in connection with the
refinancing. Orion Capital, as indirect owner of each of Orion MidWest and Orion
NY, can then contribute such cash to the other borrower. The ability of the
borrowers to make dividends, loans and advances to Orion Power for interest
payments or otherwise is subject to certain requirements (described below) that
may restrict such dividends, loans and advances.

As of December 31, 2002 and June 30, 2003, Orion MidWest had $969 million
and $949 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 $12 million in letters of credit were also outstanding under
the Orion MidWest credit facility as of December 31, 2002 and June 30, 2003,
respectively. As of December 31, 2002 and June 30, 2003, Orion NY had $351
million and $343 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 or June 30, 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 June 30, 2003, restricted cash under the Orion MidWest and the Orion NY
credit facilities was $55 million and $75 million, respectively, and $23 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
outstanding loans at Orion MidWest and Orion NY. No distributions may be made
under any circumstances after October 28, 2004 until the earlier of maturity or
retirement. Orion MidWest's and Orion NY's obligations under the respective
facilities are non-recourse to Reliant Resources.

Orion MidWest and Orion NY are collectively required to have repaid at
least $109 million of their term loans by December 31, 2003. This $109 million
is inclusive of scheduled and unscheduled principal payments. As of June 30,
2003, we have classified as current $74 million (including scheduled principal
payments), which is the balance of the $109 million, which must be repaid by
December 31, 2003. On August 5, 2003, Orion MidWest and Orion NY repaid $31
million of these term loans, further reducing the amount to be repaid to $43
million.

Liberty Credit Agreement. In July 2000, Liberty Electric Power, LLC (LEP)
and Liberty, indirect wholly-owned subsidiaries of Orion Power, entered into a
syndicated facility that provided 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; (d) a debt service reserve letter of credit facility of $17 million and
(e) an equity bridge loan of up to $41 million. The outstanding borrowings
related to the Liberty credit agreement are non-recourse to Reliant Resources.

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

24

As of June 30, 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 June 30, 2003, Liberty had $99 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 June 30, 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(f)). 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 June 30, 2003, restricted cash under the Liberty credit
agreement totaled $27 million and $33 million, respectively.

For additional information regarding the Liberty credit agreement and
related issues and concerns, see note 13(f). Given that Liberty is currently in
default under the credit agreement, we have classified the debt as a current
liability. We, including Orion Power, are not in default under our other current
debt agreements due to the credit agreement default 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 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). In addition, in March 2003, in connection with our refinancing of
our credit facilities, the entity which owns the plant became one of our
wholly-owned subsidiaries. Three series of tax-exempt secured 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 June 30, 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
June 30, 2003, the bonds bore interest of 1.06%. 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 Lease Support. Reliant Energy Mid-Atlantic Power Holdings, LLC and its
subsidiaries' (REMA) lease obligations are currently supported by the cash
proceeds resulting from the draw on three letters of credit issued under three
separate unsecured letter of credit facilities. See note 14(a) to our Form 8-K
for a discussion of REMA's lease obligations. REMA did not renew or replace the
letter of credit facilities, which were scheduled to expire in August 2003. The
letters of credit were drawn on by the beneficiary on August 1, 2003. The
drawing does not constitute a default under any of REMA's obligations and
constitutes the making of a term loan to REMA by the banks that had issued the
letters of credit pursuant to provisions that had been contemplated in the
original letter of credit facilities at their inception. The principal amount of
the term loan is $42 million and is payable in six equal semi-annual
installments beginning on January 2, 2004, the next lease payment date. The term
loan accrues interest at the rate of LIBOR plus 3%. REMA is obligated to provide
credit support for its lease obligations, in the form of letters of credit or
cash collateral, equal to an amount representing the greater of (a) the next six
months' scheduled rental payments under the related lease or (b) 50% of the
scheduled rental payments due in the next twelve months under the related lease.
Under the letter of credit facilities, REMA paid a letter of credit fee based on
its assigned credit rating. As of June 30, 2003, the fee equaled 2.75% of the
total amount of the outstanding letters of credit. As of December 31, 2002 and
June 30, 2003, there were $38 million and $50 million, respectively, in letters
of credit outstanding under the facilities. While the letter of credit
facilities were, and the resulting term loan is, non-recourse to Reliant
Resources, REMA's subsidiaries guarantee REMA's obligations under the
facilities.

Reliant Energy Channelview L.P. In 1999, 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

25

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 June 30, 2003,
Channelview had $366 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 scheduled maturities from 2003 to 2024. The
revolving working capital facility matures in 2007.

As of June 30, 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 $255
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 for such loans 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 for such loans 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 June 30, 2003,
restricted cash under the credit agreement totaled $13 million.

(b) INTEREST RATE DERIVATIVE INSTRUMENTS AND WARRANTS.

As discussed above in (a), we issued to the lenders 20,373,326 warrants to
acquire shares of our common stock. As discussed above, with the net proceeds of
our issuance of senior secured notes on July 1, 2003, we have satisfied the May
2005 permanent reduction amount and therefore the applicable 6,268,716 warrants
described above have been cancelled. The 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.
For the three months ended June 30, 2003, we amortized $2 million to interest
expense and the unamortized balance was $13 million as of June 30, 2003.

In connection with the Orion Power acquisition, the existing interest rate
swaps for the Orion MidWest credit facility and the Orion NY credit facility
were bifurcated into a debt component and a derivative component. The fair
values of the debt components, approximately $59 million for the Orion MidWest
credit facility and $31 million for the Orion NY credit facility, were based on
our incremental borrowing rates at the acquisition date for similar types of
borrowing arrangements. The value of the debt component will be amortized to
interest expense as interest rate swap payments are made. For the three months
ended June 30, 2002, the value of the debt component was amortized by $5 million
and $2 million for Orion MidWest and Orion NY, respectively. For the period from
February 20, 2002 through June 30, 2002, the value of the debt component was
amortized by $7 million and $3 million for Orion MidWest and Orion NY,
respectively. For the three months ended June 30, 2003, the value of the debt
component was amortized by $4 million and $1 million for Orion MidWest and Orion
NY, respectively. For the six months ended June 30, 2003, the value of the debt
component was amortized by $9 million and $3 million for Orion MidWest and Orion
NY, respectively. See note 8 for information regarding our derivative financial
instruments.

26

Certain of our subsidiaries, including those as discussed above, are party
to interest rate swap contracts with an aggregate notional amount of $1.1
billion and $850 million as of December 31, 2002 and June 30, 2003,
respectively, that fix the interest rate applicable to floating rate long-term
debt. As of June 30, 2003, floating rate LIBOR-based interest payments are
exchanged for weighted fixed rate interest payments of 6.88%. 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 consolidated statements
of 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 then expected 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 June 30, 2003, the unamortized balance of such loss
was $38 million.

During January 2003, we purchased three-month LIBOR interest rate caps for
$29 million to hedge our future floating rate risk associated with various
credit facilities. The notional amounts of the interest rate caps are $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. During the three months ended March 31, 2003, these
interest rate caps qualified as cash flow hedges of LIBOR-based anticipated
borrowings under SFAS No. 133; changes in fair market value during this period
were recorded to other comprehensive income (loss) and any ineffectiveness was
recorded to interest expense. Hedge ineffectiveness during the three months
ended March 31, 2003, resulted in the recording of $2 million in interest
expense on these interest rate caps. Effective March 31, 2003, these interest
rate caps no longer qualified for hedge accounting under SFAS No. 133,
accordingly, any future change in the fair market value will be recorded to net
income (loss). During the three months ended June 30, 2003, we recorded $9
million in interest expense due to an unrealized loss in fair value in the
interest rate caps. The unrealized net loss on these derivative instruments
previously reported in other comprehensive loss of $15 million (pre-tax) through
March 31, 2003 will remain in accumulated other comprehensive loss and will be
reclassified into earnings during the period in which the originally designated
hedged transactions occur.

(11) STOCKHOLDERS' EQUITY

(a) TREASURY STOCK ISSUANCES AND TRANSFERS.

We issued no shares of treasury stock to employees under our employee stock
purchase plan during the three months ended June 30, 2002 and 2003. We issued
550,781 and 717,931 shares of treasury stock to employees under our employee
stock purchase plan during the six months ended June 30, 2002 and 2003,
respectively. During the three and six months ended June 30, 2002, we
transferred 308,936 shares of treasury stock to our savings plan. During the
three and six months ended June 30, 2003, we transferred 0 and 725,877 shares,
respectively, of treasury stock to our savings plans. In addition, during the
three and six months ended June 30, 2003, we transferred 162,386 and 245,099
shares, respectively, of treasury stock under our long-term incentive plans.
During July 2003, we transferred 1,992,845 shares of treasury stock to employees
under our employee stock purchase plan.

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(12) EARNINGS PER SHARE

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

For the three and six months ended June 30, 2002, the computation of
diluted EPS excludes purchase options for 7,966,882 shares of common stock that
have an exercise price (ranging from $14.23 to $34.03 per share) greater than
the per share average market price ($11.97 and $12.82) for the respective
periods and would thus be anti-dilutive if exercised.

For the three and six months ended June 30, 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 917,273 and
351,732 shares, restricted stock of 916,290 and 916,290 shares and employee
stock purchase plan rights of 296,281 and 296,281 shares for the three and six
months ended June 30, 2003, respectively. The computation of diluted EPS
excludes incremental shares from assumed conversions of 1,834,189 and 917,095
shares for the three and six months ended June 30, 2003, respectively, relating
to the issuance of our 5.00% convertible senior subordinated notes in June 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(b)) as we incurred a loss from
continuing operations. The incremental shares from assumed conversions exclude
purchase options for 17,697,122 and 18,299,237 shares of common stock that have
an exercise price (ranging from $6.19 to $34.03 per share) greater than the
average market price ($5.72 and $4.86) for the respective periods and would thus
be anti-dilutive if exercised.

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(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
8-K 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 is required by the Texas electric restructuring law,
unless the PUCT determines that, on or prior to January 1, 2004, 40% or more of
the amount of electric power that was consumed in 2000 by residential or small
commercial customers, as applicable, within 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 a 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 recognize the total obligation over the period we recognize
the related revenues based upon the lesser of (a) 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 and (b) the
maximum cap of $150 per customer, as described above. 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 June
30, 2003. Through March 31, 2003, we had 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. As of July 31,
2003, we had not met the 40% test based on our records. 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 guaranteed, in the event CenterPoint becomes insolvent, certain
non-qualified benefits of CenterPoint's and its subsidiaries' existing retirees
at the Distribution. The maximum potential amount of future payments under this
guarantee is $56 million as of June 30, 2003. There are no assets held as
collateral. There is no liability recorded on our consolidated balance sheet as
of June 30, 2003 for this guarantee. 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 and guarantee
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

29

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 these indemnifications and guarantees,
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, 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
and we have agreed to such indemnification.

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.

Legal Matters.

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 (a) two lawsuits filed in the Superior Court of the State of
California, San Mateo County filed on April 23, 2002 and May 15, 2002; (b) two
lawsuits filed in the Superior Court of the State of California, San Francisco
County on May 14, 2002 and May 24, 2002; (c) two lawsuits filed in the Superior
Court of the State of California, Alameda County on May 21, 2002; (d) one
lawsuit filed in the Superior Court of the State of California, San Joaquin
County on May 10, 2002; and (e) one lawsuit filed in the Superior Court of the
State of California, Los Angeles County on October 18, 2002. These eight
lawsuits were removed to 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. These eight lawsuits were later
consolidated and transferred to the United States District Court for the
Southern District of California. On May 20, 2003, the judge denied the
plaintiff's motion to remand these cases back to state court. The defendants
filed a motion to dismiss all the cases based on federal preemption and the
filed rate doctrine. The motion was argued July 31, 2003 but no ruling has been
made. Additionally, on July 15, 2002, the Snohomish County Public Utility
District (PUD) filed a class action lawsuit against us in the United States
District Court for the Central District of California, which was later
transferred to the Unites States District Court for the Southern District of
California. In January 2003, the court granted our motion to dismiss the
Snohomish County PUD lawsuit on the grounds that the plaintiffs'

30

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. On May 9, 2003, another class action lawsuit was filed against us in the
Superior Court for the State of California, San Diego 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. We removed both cases, one of which was removed to the Federal District
Court for the Southern District of California, and the other was removed to
United States District Court for the Central District of California. The
plaintiffs in both cases have moved to remand the cases back to state court. The
plaintiffs in the San Diego case have also filed a petition with the Federal
Judicial Panel on Multidistrict Litigation to transfer the case to the Federal
District Court of Nevada. One of the other defendants in both cases filed a
petition with the Federal Judicial Panel on Multidistrict Litigation to transfer
both cases to a judge from the Federal Court for the Southern District of New
York. Neither the remand nor the transfer motions have been heard.

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 and violations
of the California antitrust laws 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. On May 27, 2003, we removed the
case to the Federal Court for the Southern District of California. The
plaintiffs have moved to remand the case back to state court. We have filed a
petition with the Federal Judicial Panel on Multidistrict Litigation to transfer
the case to the Federal District Court for the Northern District of California
where related cases are already pending, and the judge is not a class member.
Neither the remand motion nor the motion to transfer has been heard.

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
District of Oregon. 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.

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. On June 2, 2003, the presiding judge entered an order
dismissing the case without prejudice.

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. The California
Attorney General has appealed to the United States Court of Appeals for the
Ninth Circuit for review of the District Court's dismissal order. The appeal is
pending.

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

31

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. The California Attorney General has appealed to
the United States Court of Appeals for the Ninth Circuit for review of the
District Court's dismissal order. The appeal is pending.

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 under Section 7 of the Clayton
Act but declined to dismiss the plaintiffs' injunctive claim for divestiture of
our California facilities. Under the current scheduling order, discovery has
commenced but the case will not be tried before October 2004.

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. On July 8, 2003, the presiding judge granted the defendants'
demurrer, ruling that the filed rate doctrine and preemption barred plaintiffs'
power and gas claims and that civil penalties and restitution remedies were not
available to the plaintiffs, but also granting leave for the plaintiffs to
replead their case to attempt to state a viable cause of action. The plaintiffs
have filed a motion for coordination in the Superior Court of the State of
California, County of San Diego, to seek transfer for coordination with gas
antitrust cases pending in that court. The motion has not yet been heard.

Montana Attorney General Action. On June 30, 2003, the Montana Attorney
General, on behalf of the people of the State of Montana, and Flathead Electric
Cooperative filed a lawsuit against us and other participants in the gas and
electricity wholesale markets in the First Judicial District Court of Montana,
County of Lewis and Clark. In July 2003, one of the other defendants removed the
case to federal court in Montana. The plaintiffs allege that, along with that of
other defendants, we conspired to restrain trade, fix and manipulate the price
for electricity and natural gas in violation of various provisions of Montana's
Unfair Trade Practices and Consumer Protection Act, statutory fraud and common
law. The lawsuit seeks injunctive relief, treble the amount of damages alleged,
costs of suit and attorneys' fees.

Sierra Pacific Resources and Nevada Power Co. On July 3, 2003, Sierra
Pacific Resources and Nevada Power Company amended an existing lawsuit filed in
the Federal District Court for Nevada to add us as a defendant. The plaintiffs
allege that the defendants conspired to drive up the price of natural gas in
violation of various state and federal laws. The lawsuit seeks compensatory and
treble the amount of damages alleged, restitution of alleged overpayments,
disgorgement of alleged unlawful profits for sales of natural gas, cost of suit
and attorneys' fees.

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

32

FERC Complaints. On June 26, 2003, the FERC denied a series of complaints
filed by Nevada Power Company, which sought reformation of certain forward power
contracts with several companies, including two contracts with us that have
since been terminated. Also, on June 26, 2003, the FERC denied a similar
complaint brought by PacifiCorp Company, which challenged two 90-day contracts
with us. On July 9, 2003, PacifiCorp Company filed an appeal of the FERC's June
28, 2002 order on the question of the legal standard to be applied in reviewing
the issue of whether the contracts should be reformed.

Texas Commercial Energy. On July 7, 2003, Texas Commercial Energy filed a
lawsuit against us and several other participants in the ERCOT power market in
the Corpus Christi Federal District Court for the Southern District of Texas.
The plaintiff, a retail electricity provider in the ERCOT market, alleges that
the defendants conspired to illegally manipulate and artificially increase the
price of electricity through price fixing and predatory pricing in violation of
state and federal antitrust laws, fraud, negligent misrepresentation, breach of
fiduciary duty, defamation and disparagement to its business reputation, breach
of contract, civil conspiracy and negligence, along with other claims not
alleged against us. The lawsuit seeks alleged damages in excess of $500 million,
exemplary damages, treble damages, interest, costs of suit and attorneys' fees.

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 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. We understand that
the SEC is continuing to investigate certain of our former employees.

As part of the Commodity Futures Trading Commission's (CFTC) industry-wide
investigation of round trip trading and price reporting, the CFTC has subpoenaed
documents, requested information and conducted discovery relating to our natural
gas and power trading activities, including round trip trades, price reporting
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 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.

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 recommended the
institution of various proceedings to resolve allegations of manipulation and to
determine whether the FERC should require a disgorgement of revenues related to
certain trading activity and bidding practices for the period May to October
2000. Finally, the report recommends that certain entities, including us,
demonstrate that they 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. We responded to this order with an explanation that we
have suspended voluntary reporting of gas price information and that none of our
employees intentionally provided false information designed to manipulate price
indices. On July 29, 2003, the FERC issued an order stating that we have met the
requirements of the April 30, 2003 order.

33

Also on March 26, 2003, the FERC instituted proceedings directing our
trading and marketing company, Reliant Energy Services, Inc. (RES) 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 employees and one of BP's employees 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 July 18, 2003, the FERC issued a consent
order to BP that required BP to pay $3 million and to pass its electricity sales
through FERC review for the next six months, among other things. BP's settlement
with the FERC may increase the pressure on the FERC to act with respect to RES'
market-based rate authority. However, there can be no assurance that the FERC
will handle RES' proceeding in the same manner and may conclude that, despite
the BP settlement, revocation of market-based rate authority would be
appropriate.

Acting on recommendations in the March 26, 2003 staff report, the FERC on
June 25, 2003 initiated an investigation of bids greater than $250/MWh during
the period from May 1, 2000 through October 2, 2000 to determine if any such
bids were the result of improper market conduct. On July 2, 2003, the FERC staff
issued a set of data requests in connection with the investigation. We are
cooperating fully with the FERC staff and responded to the data requests on July
24, 2003. Also on March 26, 2003, the FERC directed its staff to conduct an
investigation into whether there was physical withholding of generation in the
California market. We have responded to a data request and the investigation is
ongoing. On June 25, 2003, the FERC initiated a proceeding against us and
numerous other wholesale market participants to determine whether certain
trading activities identified in reports entitled "Analysis of Trading and
Scheduling Strategies Described in the Enron Memos" filed by the Cal ISO
violated certain market protocols and are subject to disgorgement of profits
earned on such activities. We will defend against all allegations of improper
activities. The FERC held a Plenary Conference on July 24, 2003 to discuss
procedural issues for evidentiary hearings and the possibility of settlement
negotiations.

We have received subpoenas and informal requests for information from the
United States Attorney for the Southern District of New York and the Northern
District of California for documents, interviews and other information
pertaining to the round trip trades, and our former energy trading activities.
We have produced information to both offices of the United States Attorney. We
have not received any additional requests for information or interviews from the
United States Attorney for the Southern District of New York since the fall of
2002. On July 24, 2003, the United States Attorney for the Northern District of
California sent us subpoenas for testimony from a number of our current
employees. We are cooperating with both offices of the United States Attorney.

We have and will continue to evaluate and pursue possible ways of resolving
through settlement the various California-related lawsuits, investigations and
regulatory proceedings that are pending against or involve us. For example, as
discussed above, we have previously settled certain issues with the SEC and the
FERC. We are unable at this time to predict whether efforts to achieve
additional settlements will be successful.

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.

34

Four class action lawsuits were filed on behalf of purchasers of the
securities of CenterPoint. Along with us and several of our officers,
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
and were consolidated on August 1, 2002. The consolidated lawsuit alleges 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 and CenterPoint's 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
March 28, 2003, the defendants filed a motion to dismiss certain of the claims
asserted by the plaintiffs in the consolidated lawsuits. The court has not ruled
on the motion.

On February 7, 2003, a lawsuit was filed against CenterPoint and certain of
our former and current employees in United States District Court for the
Northern District of Illinois, Eastern Division. The plaintiffs allege
violations of 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. On June
30, 2003, the Court granted the plaintiffs' motion to amend their complaint and
denied the defendants' motion to dismiss as moot. The plaintiffs filed an
amended complaint on July 9, 2003, in which they have eliminated their claim for
negligent misrepresentation and have plead the allegations underlying their
claims in greater detail. On July 25, 2003, the defendants filed an amended
motion to dismiss.

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. On May 7, 2003, our and CenterPoint's defendants, including the
officers and directors, filed a motion to dismiss all of the plaintiffs' claims.
The court has not ruled on the motion.

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

35

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. On June 18, 2003, CenterPoint's
board of directors determined, by way of a resolution, that these proposed
actions are not in the best interests of CenterPoint.

Environmental Matters.

REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see note 5(b) to our Form 8-K), 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 June 30, 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 $29 million as of June 30, 2003. We expect approximately $12
million will be paid over the next five years.

Orion Power Environmental Contingencies. In connection with Orion Power's
acquisition of 70 hydro plants and four gas-fired or oil-fired plants in New
York, Orion Power assumed the liability for the 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 a
Memorandum of Understanding with Niagara Mohawk for one hydro site for releases
of petroleum and other substances by the prior owners. As of June 30, 2003, the
liability assumed and recorded by us for these assets was approximately $7
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 June 30, 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.

New Source Review Matters. The Environmental Protection Agency (EPA) has
requested information from six of our coal-fired facilities, as well as two of
our Orion Power facilities, related to work activities conducted at the sites
that may be associated with various permitting requirements of the Clean Air
Act. We have responded to the EPA's requests for information. In addition to the
EPA's requests for information, the New Jersey Department of Environmental
Protection (NJDEP) recently requested a copy of all correspondence relating to
the EPA requests for information for one of the six stations. The EPA has
responded to us that they have received the NJDEP request for information and
that it will provide the information requested by the NJDEP.

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 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

36

through June 30, 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 $1 million and $10 million of net interest receivable during 2002 and for
the three and six months ended June 30, 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 a
party to a lawsuit in California, filed on July 20, 2001 in the Superior Court
of the State of California for Los Angeles County, 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 $205 million (net of estimated refund provision of $103 million) as of
December 31, 2002 and June 30, 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 June 30,
2003.

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 ($5 million and $38 million
during the three and six months ended June 30, 2002, respectively) 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 and six months ended June
30, 2003, we recorded an additional credit provision of $1 million and $13
million, respectively, due to the reversal of refund provisions as discussed
below. As of December 31, 2002 and June 30, 2003, we had a remaining pre-tax
credit provision of $6 million and $19 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 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 file for a reduction of their refund liability if their
actual gas costs exceeded the allowed gas costs under the gas price used in the
FERC's refund formula. 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 $103 million and $231 million
for energy sales in California. The low range

37

of our estimate is based on a refund calculation using a methodology established
by the FERC in late March 2003 and clarified in the second quarter of 2003. This
methodology calculates 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 ($34
million during the three and six months ended June 30, 2002, respectively)
related to energy sales in California. As discussed above, $15 million was
recognized during 2001. During the three and six months ended June 30, 2003, we
reversed $1 million and $88 million, respectively, of previously recorded refund
provisions due to additional clarification received from the FERC and other
information received in the second quarter of 2003. As of December 31, 2002 and
June 30, 2003, our reserve for refunds related to energy sales in California is
$191 million and $103 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 and six months ended June
30, 2003, we recorded net interest income of $1 million and $10 million,
respectively. 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) TOLLING AGREEMENT FOR LIBERTY'S ELECTRIC GENERATING STATION.

The output of our Liberty electric generating station was contracted under
a long-term 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 had the exclusive right to receive all electric energy, capacity
and ancillary services produced by the Liberty generating station, and PGET was
required to pay for all fuel used by the Liberty generating station.

The tolling agreement required 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. (NEG) and PG&E Gas Transmission Northwest Corp. (GTN). In
addition, on July 8, 2003, PGET and NEG filed for reorganization under Chapter
11 of the United States Bankruptcy Code; however, GTN did not file. The
bankruptcy filing constituted an event of default under the Liberty credit
facility, which has not been waived by the lenders. As a result, the lenders are
entitled to control the disbursement of funds by LEP and Liberty. The lenders
are also entitled to accelerate the debt and/or foreclose.

Also, on July 8, 2003, PGET filed a motion with the bankruptcy court to
reject the tolling agreement, which, if approved by the court, would deem the
agreement terminated as of July 8, 2003. Liberty did not oppose this motion and
the bankruptcy court entered an order (the Rejection Order) granting the motion
on August 7, 2003. Pursuant to the tolling agreement, on July 30, 2003, LEP
provided a special invoice to PGET requesting a termination payment in the
amount of $177 million, such amount representing LEP's calculation of its loss
due to early termination in accordance with specific criteria. However, under
the tolling agreement, PGET has the right to refer the loss calculation to
arbitration, which could delay the receipt of such damages for an extended
period. LEP intends to make prompt demand of the termination payment under its
guarantee with GTN (the guarantee, together with NEG's guarantee, is limited in
amount to $140 million) and file the necessary claims for damages with the
bankruptcy court against PGET and NEG. However, there can be no assurance that
GTN would promptly pay any award or how much, if anything, could be recovered
from PGET or NEG. Any amounts recovered from PGET, NEG and/or GTN would be
handled in accordance with the Liberty credit facility. The most likely result
is that the damages would be used to prepay Liberty debt or paid into an account
that is managed by the lenders under the credit facility.

The tolling agreement provided for a fixed monthly payment to LEP. As a
result of the rejection of the tolling agreement, LEP will need to find a power
purchaser or tolling customer to replace PGET or sell the energy and/or capacity
in the merchant energy market. Liberty is currently negotiating with its lenders
an arrangement to allow LEP to sell capacity and energy in the merchant energy
market. In addition, in connection with the rejection of the tolling agreement,
and in accordance with the Rejection Order, LEP is working with PGET to cause
the transfer of the gas transportation agreements that PGET utilizes in
connection with the tolling agreement to LEP, and,

38

following such transfer, LEP will be required to perform the obligations
currently being performed by PGET under the gas transportation agreements,
including the payment of a monthly transportation charge. As drafted, the gas
transportation agreements contemplate their transfer from PGET to LEP upon a
termination of the tolling agreement. Once the gas transportation agreements
have been transferred to LEP, LEP's payment obligation thereunder will be
supported by a $5 million guarantee of Orion Power Development Company, Inc.
(OPD), which is a wholly-owned subsidiary of Orion Power and the parent company
of LEP and Liberty. If LEP fails to make payment under the transportation
agreements, the transportation company may make a claim against OPD under this
guarantee. Also, if LEP fails to maintain minimum creditworthiness as required
under the gas tariff governing these transportation agreements on file with the
FERC, LEP may be required to post additional collateral. However, OPD is not
obligated to post any additional collateral.

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

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 generating 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 did not agree with PGET's interpretation of the tolling agreement
regarding the dispatch issue, LEP and PGET settled these matters on May 19,
2003, for $2 million.

In December 2002, we evaluated the Liberty generating station and the
related tolling agreement for impairment. Based on our analyses, there were no
impairments. The fair value of the Liberty generating 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 lenders foreclose on LEP and Liberty, we believe we could incur
a pre-tax loss of an amount up to our recorded net book value with the potential
of an additional loss due to an impairment of goodwill allocated to LEP as a
result of the foreclosure.

As of June 30, 2003, the combined net book value of LEP and Liberty was
$365 million, excluding the non-recourse debt obligations of $264 million. We
will evaluate the Liberty generating station and the related tolling agreement
for impairment during the third quarter of 2003.

(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 and in
May 2003, it was increased to $200 million. 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 on September 30, 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 June 30, 2003, the amount of funding outstanding under our
receivables facility was $95 million and $200 million, respectively.

39

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 and $6
million for the three and six months ended June 30, 2003, respectively. We have
no servicing assets or liabilities, because servicing fees are based on
estimated 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 sheets. Costs associated with the sale of receivables, $4 million and $8
million for the three and six months ended June 30, 2003, respectively,
primarily the discount and loss on sale, are included in other expenses in our
consolidated statements of operations. As of December 31, 2002 and June 30,
2003, $277 million and $406 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
(including unpaid interest) from the QSPE of approximately $170 million and $183
million at December 31, 2002 and June 30, 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. The failure of the obligors to make
payment on the receivables could result in our notes receivable from the QSPE
not being fully realized. At December 31, 2002 and June 30, 2003, the equity
investment balance was $8 million and $12 million, respectively. These notes
receivable were pledged to the lenders in the March 2003 refinancing of certain
of our credit facilities, see note 10.

The book value of the accounts and notes receivable is offset by the amount
of the allowance for doubtful accounts and customer security deposits. A
discount rate of 5.78% 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.

(15) BANKRUPTCY OF ENRON CORP. AND ITS AFFILIATES

During the fourth quarter of 2001, Enron Corp. filed a voluntary petition
for bankruptcy. Accordingly, we recorded an $85 million provision, comprised of
provisions against 100% of Enron Corp.'s and its affiliates' (Enron) 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 (loss) 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 June 30, 2002 and 2003, $14 million gain and $4 million loss,
respectively, was reclassified into earnings related to these cash flow hedges.
During the six months ended June 30, 2002 and 2003, $26 million gain and $6
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,

40

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) SUPPLEMENTAL GUARANTOR INFORMATION

For the $1.1 billion senior secured notes issued in July 2003, our
wholly-owned subsidiaries are either (a) full and unconditional guarantors,
jointly and severally, (b) limited guarantors or (c) non-guarantors.

The primary guarantors of these senior secured notes are: Reliant Energy
Aurora, LP; Reliant Energy California Holdings, LLC; Reliant Energy Electric
Solutions, LLC; Reliant Energy Northeast Holdings, Inc.; Reliant Energy Power
Generation, Inc.; Reliant Energy Retail Holdings, LLC; Reliant Energy Retail
Services, LLC; Reliant Energy Services, Inc.; Reliant Energy Shelby County II,
LP and Reliant Energy Solutions, LLC.

Orion Power Holdings, Inc. is the only limited guarantor of these senior
secured notes and its guarantee is limited to approximately $1.1 billion. Orion
Power Holdings, Inc. and its subsidiaries were acquired in February 2002.

The primary non-guarantors of these senior secured notes are: Astoria
Generating Company, LP; Erie Boulevard Hydropower, L.P.; Liberty Electric PA,
LLC; Liberty Electric Power, LLC; Orion Power Capital, LLC; Orion Power MidWest,
LP; Orion Power MidWest LP, LLC; Orion Power New York, LP; Orion Power New York
LP, LLC; Reliant Energy Capital (Europe), Inc.; Reliant Energy Channelview L.P.;
Reliant Energy Europe, Inc.; Reliant Energy Trading & Marketing, B.V.; Reliant
Energy Mid-Atlantic Power Holdings, LLC; Reliant Energy New Jersey Holdings,
LLC; Reliant Energy Power Generation Benelux, N.V. and Reliant Energy B.V. All
subsidiaries of Orion Power are non-guarantors.

41

The following condensed consolidating financial information presents
supplemental information for the indicated groups as of December 31, 2002 and
June 30, 2003 and for the three and six months ended June 30, 2002 and 2003:

Condensed Consolidating Statements of Operations.

- ----------

(1) These amounts relate to either (a) eliminations recorded in the normal
consolidation process or (b) reclassifications recorded due to differences
in classifications at the subsidiary levels compared to the consolidated
level.

(2) Investments in and distributions from subsidiaries, net and Reliant
Resources' advances to and distributions from its wholly-owned
subsidiaries, net are classified as investing activities for Reliant
Resources and its wholly-owned subsidiaries.

(3) Changes in notes with affiliated companies, net are classified as financing
activities for Reliant Resources' wholly-owned subsidiaries.

(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 8-K. In February 2003, we signed an
agreement to sell our European energy operations and have classified that as
discontinued operations. See note 18 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 consist of ten power generation units completed or under
various stages of construction at seven facilities with an aggregate net
generation capacity of 805 MW located in Texas, 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.

49

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

(18) DISCONTINUED OPERATIONS - SALE OF OUR EUROPEAN ENERGY OPERATIONS

In February 2003, we signed an agreement to sell our European energy
operations to n.v. Nuon (Nuon), a Netherlands-based electricity distributor,
through the sale of our shares in Reliant Energy Europe B.V. (RE BV), a holding
company for these operations. The sale is subject to regulatory approval by the
Dutch and German competition authorities. The German competition authority
approved the sale in May 2003. Approval by the Dutch competition authority is
pending and is further discussed below. Upon consummation of the sale, we expect
to receive cash proceeds of approximately $1.3 billion (Euro 1.1 billion). We
calculated the United States dollar amounts assuming an exchange rate of 1.1511
US dollar to the Euro, which was the exchange rate in effect on June 30, 2003,
while the December 31, 2002 balances were calculated using an exchange rate of
1.0492 US dollar to the Euro. In June 2003, we hedged our anticipated net
proceeds from the sale of our European energy operations by purchasing Euro 526
million of foreign currency options, which expire in August 2003.

The purchase price payable at closing assumes that our European energy
operations will have, on the closing date, net cash (as defined in the agreement
to include, among other things, cash collateral) of at least $132 million (Euro
115 million). If the amount of net cash is less on the closing date, the
purchase price will be reduced accordingly. Based on current estimates, we
believe we will have more than Euro 115 million of net cash at closing.

51

However, since the amount of net cash fluctuates based on operational needs,
there can be no assurance as to the amount of net cash on the closing date.

As additional contingent consideration for the sale, we are also entitled
to receive from Nuon 90% of any cash payments in excess of approximately $127
million (Euro 110 million) paid by NEA B.V (NEA) to Reliant Energy Power
Generation Benelux, N.V. (REPGB), the operating subsidiary of RE BV, after
February 2003. REPGB has an equity investment in NEA, the former coordinating
body for the Dutch electricity sector. NEA is in the process of liquidating
various stranded cost contract liabilities incurred by it during the period
prior to the liberalization of the Dutch energy market. Given uncertainties
associated with this liquidation, there can be no assurance as to the amount, if
any, or timing of potential consideration resulting from cash payments by NEA.

We intend to use the cash proceeds from the sale first to pay transaction
costs and 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 is December 31, 2003. If we elect to acquire the common stock of
Texas Genco in 2004, we intend to use the remaining cash proceeds of
approximately $0.6 billion (Euro 0.5 billion) to partially fund such
acquisition, subject to the limitations in our March 2003 credit facilities.
However, if we elect not to acquire Texas Genco, we must use the remaining cash
proceeds to prepay debt.

The sale remains subject to regulatory approval of the Dutch competition
authority (the NMa). Based on our understanding of applicable regulatory
precedents and the status of the NMa's investigation, we expect that NMa
approval and closing would occur in the third or early fourth quarter of 2003.
However, as in the case of any regulatory process, we can make no guarantee that
we will obtain the approval of the NMa or that such approval can be obtained in
a timely manner. Unless regulatory approval is received by November 28, 2003,
our agreement with Nuon to sell our European energy operations terminates unless
otherwise extended by mutual agreement of the parties.

Under the Dutch Competition Act, regulatory review of an acquisition occurs
in two-phases. During the first phase, the NMa investigates the effects on
competition that result from the transaction. Upon the NMa's completion of the
first phase investigation, the NMa can either approve the transaction or require
a second phase review in which it typically investigates further specific
elements or effects of the transaction. In both the first phase and a potential
second phase, the parties are required to provide information and respond to
questions from the NMa. The first phase lasts four weeks and the second phase
can last up to 13 weeks, with time running as long as there are no information
requests or responses to questions outstanding. In Dutch regulatory practice,
the NMa can impose conditions to regulatory approval only in the context of the
second phase review process.

With Nuon, we initiated a first phase review of the proposed sale
transaction with the NMa on April 3, 2003 with the filing of an application. To
date, the parties have provided certain information to and responded to certain
questions of the NMa related to the transaction, as required, that assist the
NMa in completing its review. As of July 31, 2003, the NMa's investigation
remains in the first phase with 11 days remaining (the regulatory time period
can be suspended during periods when there are outstanding information
requests). If the NMa requires a second phase review, we anticipate a request
for additional information to address specific elements or effects of the
transaction identified by the NMa in the first phase.

In connection with the anticipated sale, we recognized an estimated loss
on disposition of $340 million during the six months ended June 30, 2003 ($384
million loss recorded during the three months ended March 31, 2003 and $44
million gain recorded during the three months ended June 30, 2003). The gain
recognized during the three months ended June 30, 2003, is primarily due to the
change in the foreign currency exchange rate from March 31 to June 30, 2003. We
do not currently 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 June 30, 2003 to the date of sale, (b) changes in intercompany
balances from June 30, 2003 to the date of sale and (c) various other factors.
We will recognize contingent payments, if any, (as discussed above) in earnings
upon receipt. During the first quarter of 2003, we began to report the results
of our European energy operations as discontinued operations in accordance with
SFAS No. 144 and accordingly, reclassified prior period amounts. For 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.

52

Assets and liabilities related to discontinued operations were as follows:

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

In February 2000, one of our subsidiaries, RECE, established a Euro 600
million term loan facility. At December 31, 2002 and June 30, 2003, $630 million
and $691 million, respectively, under this facility was outstanding and is
included in liabilities of discontinued operations in our consolidated balance
sheets. 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.

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. 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 and (b) December 31, 2003. In the event the sale of our European energy
operations were to be terminated, we would be required to reach an agreement
with our lenders on continuing the facilities on or prior to the earlier of 60
days after such termination or the maturity date mentioned above.

In order to extend the Euro 600 million facility in March 2003, we provided
the following additional security to the lenders:

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

53

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 RE BV, 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. 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 million (approximately
$48 million) during the year ending December 31, 2003.

REPGB has credit facilities that consist of (a) a Euro 150 million
(approximately $173 million) (reduced from Euro 184 million in June 2003)
revolving credit facility and (b) a letter of credit facility for $400 million
(reduced from $420 million in June 2003). Under the two facilities, there is no
recourse to Reliant Resources.

The revolving credit facility matures on December 31, 2003. It contains an
option that allows REPGB to utilize up to Euro 100 million (approximately $115
million) for letters of credit. At December 31, 2002 and June 30, 2003, there
were no borrowings outstanding under the revolving credit facility. At December
31, 2002 and June 30, 2003 there were Euro 17 million ($18 million) and Euro 27
million ($31 million), respectively, of letters of credit outstanding under the
revolving credit facility. The $400 million letter of credit facility matures on
January 5, 2004. At December 31, 2002 and June 30, 2003, letters of credit of
$355 million and $363 million, respectively, were outstanding under the
facility. In the event the sale of our European energy operations were to be
terminated, we would be required to reach an agreement with our lenders on
continuing the facilities on or prior to the earlier of 60 days after such
termination or the respective maturity dates mentioned.

Additional outstanding long-term indebtedness, including any current
portions, of REPGB of $38 million at December 31, 2002 and $40 million at June
30, 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 credit facilities and
long-term indebtedness will remain the obligations of REPGB.

(19) SALE OF DESERT BASIN PLANT OPERATIONS

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

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

54

approximately $5 million and $6 million, respectively. See note 7 for further
discussion of the potential goodwill impairment of our wholesale energy
reporting unit.

* * *

55

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 $4.2 million and $5.3 million ($2.7
million and $3.4 million after-tax, respectively) for the three and six months
ended June 30, 2002, respectively. A summary of the principal effects of the
restatement for the three and six months ended June 30, 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. With respect to the retail segment of the industry, we provide
customized electricity and related energy services to large commercial,
industrial and institutional customers in Texas and, to a lesser extent, in New
Jersey. We also provide standardized electricity and related services to
residential and small commercial customers in Texas. Within the wholesale
segment of the industry, we own and/or operate a substantial number of electric
power generating units dispersed broadly across the United States. These units
are not subject to traditional cost-based regulation; therefore, we can
generally sell electricity at prices determined by the market, subject to
regulatory limitations. We market electric energy, capacity and ancillary
services and procure and, in some instances, resell natural gas, coal, fuel oil,
natural gas transportation capacity and other energy-related commodities to
optimize our physical assets and provide risk management services for our asset
portfolio.

In March 2003, we decided to exit our proprietary trading activities and
liquidate, to the extent practicable, our proprietary positions. Although we
have exited our proprietary trading activities, we have legacy positions, which
will be closed as economically feasible or in accordance with their terms. We
will continue to engage in marketing and hedging activities related to our
electric generating facilities, pipeline transportation capacity positions,
pipeline storage positions and fuel positions 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 2002 and the six months ended June 30, 2003, the following factors,
among others, continued to negatively impact our business:

o weaker pricing for electric energy, capacity and ancillary services;

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

56

o downgrades in our credit ratings to below investment grade in 2002.

In response to continued depressed prices for electric energy, capacity and
ancillary services across much of the United States and our current judgments
regarding the state of the wholesale electricity markets, we are in the process
of evaluating our short-term and long-term strategies and activities. We are
presently evaluating, and may soon implement, (a) further reductions in
commercial, operational and support groups to reduce costs (as discussed below),
(b) further changes in our market strategies, (c) mothballing or retiring
certain power generation facilities, (d) deferring and/or materially reducing
maintenance expenditures at power generation facilities and (e) divesting of
certain assets. Also, we are evaluating the method of projecting future cash
flows from our wholesale energy segment operations. In connection with this
effort, our future cash flow projections and plans may be significantly revised.

Historically, we anticipated that long run market prices would eventually
return to levels sufficient to support an adequate rate of return on the
construction of new power generation, which we believed would be required to
meet increased demand for power. This view is currently being challenged in
certain markets as market rules unfold that provide more favorable returns to
new capacity entering the market than is provided to existing capacity.

We are in the process of testing our wholesale energy segment's goodwill
for impairment effective July 2003. See note 7 to our interim financial
statements for a discussion of this goodwill impairment analysis. The assessment
of goodwill requires developing an updated estimate of the fair value of our
wholesale energy reporting unit, which is expected to be completed by the end of
the third quarter of 2003. If the assumptions and estimates underlying our July
2003 goodwill impairment evaluation for our wholesale energy reporting unit
differ adversely from the assumptions previously used due to changes in our
wholesale energy market outlook, strategies and activities, it is possible that
goodwill might be impaired and any such impairment would be reflected in the
third quarter of 2003. In addition, if our wholesale energy market outlook and
views change further in future periods and the current weak environment is
prolonged or if current conditions decline further, we could have impairments of
our property, plant and equipment in future periods which, in turn, could have a
material adverse effect on our results of operations.

In addition, our operations are impacted by changes in commodities other
than electric energy, in particular by changes in natural gas prices. During the
first quarter of 2003, there was significant volatility in the natural gas
market. As a result and prior to exiting proprietary trading activities, 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 coal-fired generation
capacity 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 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 transmission and distribution utility rates
approved by the PUCT and (b) the price paid for electricity to serve price to
beat customers). In July 2003, our second and final request for 2003 was
approved by the PUCT to increase the price to beat fuel factor based on a 23.1%
increase in the price of natural gas. 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 June 2003, we launched a review of our internal cost structure with a
focus primarily on our non-plant related expenses. In the course of the review,
we identified approximately $140 million of annualized savings opportunities,
the majority of which we expect to implement by the end of 2003. Due to the
expected timing of realizing these savings, and the expected recognition in 2003
of approximately $15 million of employee severance costs and other
implementation costs associated with our cost-reduction efforts, we do not
expect the impact of these savings opportunities to be realized until 2004. In
addition to the review of our internal cost structure, we have also launched a
review of our wholesale business strategy, portfolio and operations and
maintenances practices and hope to identify additional cost savings, both
expense and capital, through this effort.

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

57

results of operations, financial condition and cash flows. As a result of the
June and July 2003 issuances of convertible senior subordinated notes and senior
secured notes (see note 10 to our interim financial statements), our interest
expense will increase substantially. In addition, as a result of the July 2003
issuance of senior secured notes, we will expense approximately $31 million of
deferred financing costs incurred in connection with the March 2003 refinancing
associated with the indebtedness prepaid with the net proceeds from the issuance
of senior secured notes. For a discussion of the impact of our refinancing in
March 2003 and the June and July 2003 issuances, see the "Financial Condition"
section.

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 $340 million during the six months ended
June 30, 2003 ($384 million loss recorded during the three months ended March
31, 2003 and $44 million gain recorded during the three months ended June 30,
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. During the first quarter of 2003, we began to report the results of our
European energy operations as discontinued operations in accordance with SFAS
No. 144 and accordingly, reclassified prior period amounts. For further
discussion of the sale, see note 18 to our interim financial statements.

On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant, located in Casa Grande, Arizona, to SRP of
Phoenix for $289 million. The transaction is subject to regulatory approvals,
including the FERC, and certain third-party consents and approvals. The
transaction is expected to close by the end of 2003. We will recognize a loss on
the disposition of our Desert Basin plant operations in the third quarter of
2003 and in connection with the classification of Desert Basin as "held for
sale," we will report the assets and liabilities to be sold as discontinued
operations effective July 2003. For further information regarding the sale of
our Desert Plant operations and the impact on our results of operations, see
note 19 to our interim financial statements.

CONSOLIDATED RESULTS OF OPERATIONS

The following tables provide summary data regarding our consolidated
results of operations for the three and six months ended June 30, 2002 and 2003:

- ----------

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

Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2003.

Net Income (Loss). We reported $176 million consolidated net income, or
$0.60 earnings per diluted share, for the three months ended June 30, 2002
compared to $(6) million consolidated net loss, or $(0.02) loss per share, for
the three months ended June 30, 2003. The $182 million decrease from net income
to net loss was primarily due to:

o a $101 million decrease in EBIT from our retail energy segment;

o a $57 million increase in interest expense to third parties;

o a $51 million decrease in EBIT from our wholesale energy segment; and

58

o a $33 million decrease in income from discontinued operations, which
includes an estimated gain on disposition of $44 million recognized
during the three months ended June 30, 2003 due to the anticipated
sale of our European energy operations (see note 18 to our interim
financial statements).

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

Interest Expense. We incurred $57 million of interest expense to third
parties during the three months ended June 30, 2002 compared to $114 million in
the same period of 2003. The $57 million increase in interest expense in 2003 as
compared to 2002 resulted primarily from (a) an increase in interest expense to
third parties, net of interest expense capitalized on projects, primarily as a
result of higher levels of borrowings and higher interest rates, (b) an increase
in amortization of deferred financing costs due to the March 2003 refinancing
and (c) a $9 million loss related to the change in fair value of interest rate
caps (see note 10(b) to our interim financial statements). Included in this
increase is $15 million of financing costs amortized during the three months
ended June 30, 2003.

Income Tax Expense. During the three months ended June 30, 2002 and 2003,
our effective tax rate was 32.8% and 27.1%, respectively. Our reconciling items
from the federal statutory rate of 35% to the effective tax rate totaled $4
million for the three months ended June 30, 2002. These items primarily related
to the utilization of Canadian net operating loss carryovers. Our reconciling
items from the federal statutory rate of 35% to the effective tax rate totaled
$3 million for the three months ended June 30, 2003. These items primarily
related to tax reserves and valuation allowances related to Canadian operating
losses partially offset by state income tax benefits.

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2003

Net Income (Loss). We reported $38 million consolidated net income, or
$0.13 earnings per diluted share, for the six months ended June 30, 2002
compared to $(458) million consolidated net loss, or $(1.57) loss per share, for
the six months ended June 30, 2003. The $496 million decrease from net income to
net loss was primarily due to:

o a $429 million decrease in income from discontinued operations, which
includes an estimated loss on disposition of $340 million recognized
during the six months ended June 30, 2003 due to the anticipated sale
of our European energy operations (see note 18 to our interim
financial statements);

o a $164 million decrease in EBIT from our wholesale energy segment;

o a $125 million increase in interest expense to third parties; and

o a $124 million decrease in EBIT from our retail energy segment.

These changes were partially offset by:

o a $234 million cumulative effect of an accounting change related to
the adoption of SFAS No. 142 on January 1, 2002 for our European
energy operations (see note 7 to our interim financial statements);
and

o a $15 million increase in interest income from third parties.

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

Interest Expense. We incurred $86 million of interest expense to third
parties during the six months ended June 30, 2002 compared to $211 million in
the same period of 2003. The $125 million increase in interest expense in 2003
as compared to 2002 resulted primarily from the same factors impacting interest
expense during the three months ended June 30, 2002 and 2003, as discussed
above. Included in this increase is $26 million of financing costs expensed and
amortized during the six months ended June 30, 2003.

Interest Income. We recognized interest income from third parties of $4
million for the six months ended June 30, 2002 as compared to $19 million for
the same period in 2003. The increase is primarily due to interest income of $10
million recognized on receivables related to energy sales in California (see
note 13(e) to our interim financial statements) and excess cash invested on a
short-term basis.

Income Tax Expense. During the six months ended June 30, 2002 and 2003, our
effective tax rate was 34.1% and 28.7%, respectively. Our reconciling items from
the federal statutory rate of 35% to the effective tax rate

59

totaled $3 million for the six months ended June 30, 2002. These items primarily
related to the utilization of Canadian net operating loss carryovers partially
offset by state income taxes. Our reconciling items from the federal statutory
rate of 35% to the effective tax rate totaled $7 million for the six months
ended June 30, 2003. These items primarily related to increases in tax reserves,
revisions in the estimated tax rates, valuation allowances related to Canadian
operating losses and revisions of estimates for taxes accrued in prior periods,
partially offset by state income tax benefits.

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
income (loss), for the three and six months ended June 30, 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, 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
consist of ten power generation units completed or under various stages of
construction at seven facilities with an aggregate net generation capacity of
805 MW located in Texas, 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 and six months ended June 30, 2002 and 2003 reconciled to
our consolidated net income (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, which were obtained through our marketing
efforts. We are taking steps to provide electricity and related products and
services to large commercial, industrial and institutional customers in certain
other states. In New Jersey, we are registered as an "electric power supplier"
and in Pennsylvania, we are registered as an "electric generation supplier." We
have contracts to deliver electricity in New Jersey, effective August 1, 2003.
At the end of June 2003, our customer count, as measured by number of metered
locations, had increased approximately four percent as compared to June 2002;
however, our retail energy segment lost market share in the Houston market but
added customers in other areas of Texas.

We record gross revenue for energy sales and services to residential, small
commercial and non-contracted large commercial, industrial and institutional
retail electric customers primarily 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 consolidated statements of 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
electricity sales contracts and 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 to our interim financial statements).

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 2002 and 2003.
During the three and six months ended June 30, 2002, our retail energy segment
realized $12 million and $14 million, respectively, of previously unrealized net
losses related to its contracted electricity sales to large commercial,
industrial and institutional customers and the related energy supply contracts.
During the three and six months ended June 30, 2003, volumes

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were delivered under contracted electricity sales to large commercial,
industrial and institutional customers and the related energy supply contracts
in which $14 million and $31 million, respectively, was previously recognized in
unrealized earnings in prior periods. As of June 30, 2003, our retail energy
segment has unrealized gains that have been previously recorded in our results
of operations of $62 million that will be realized when the electricity is
delivered to our customers ($35 million in the remainder of 2003 and $27 million
in 2004 and beyond). These unrealized gains of $62 million are recorded in
non-trading derivative assets/liabilities in our consolidated balance sheet as
of June 30, 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
June 30, 2003, the amount of unbilled revenue was $363 million. Included in that
amount is approximately $14 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 June 30, 2003. For further
information regarding recognition of unbilled revenues, see "Management
Discussion and Analysis of Financial Condition and Results of Operations -
Critical Accounting Estimates" and note 2(d) to our Form 8-K.

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
June 30, 2003, the estimated transmission and distribution charges not billed by
the transmission and distribution utilities to us, which we accrued during the
period, totaled $11 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 for balancing energy service. The ERCOT ISO also
charges customer-serving market participants fees such as administrative fees,
reliability must run contract fees, out of merit energy fees and out of merit
capacity fees. Most of these fees are incurred when the ERCOT ISO procures these
services to maintain the reliability of the electrical system and are not
controllable by us. The ERCOT ISO allocates these and other 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. Delays in the ERCOT ISO settlement process could impact our ability
to accurately reflect our energy supply costs and related fees.

The ERCOT ISO volume 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, were
suspended to begin a market synchronization of all customers between the market
participants. 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. In May 2003, the
ERCOT ISO resumed the final settlement process beginning with January 1, 2002.
The ERCOT ISO has been submitting final volume settlements to us, primarily for
the January through May 2002 time period. These volume settlements indicate that
our customers utilized greater volumes than our records indicate. We have

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disputed these volume differences and the ERCOT ISO has denied these disputes.
We have taken steps to initiate the alternate dispute resolution process
included in the ERCOT ISO's protocols to resolve these differences.

The ERCOT ISO fees related to resolving local congestion have increased
substantially during the past six months. Efforts are ongoing to establish the
causes of the fee increases and to correct the market design or systems, if
necessary. In addition, we may be billed a disproportionate share of these total
fees if the ERCOT ISO's records indicate that our volumes delivered were greater
than the volumes our records indicate.

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 2003, we revised our estimates and assumptions, as additional
information was received, related to 2002 and accordingly, recognized $9 million
of income in our operating results during the six months ended June 30, 2003
related to 2002. During the three months ended June 30, 2003, we recognized $37
million of losses in our operating results related to prior periods due to
revised estimates and assumptions based on new information received from the
ERCOT ISO. These amounts are based on the latest information we have to date and
as additional information becomes available, we will continue to recognize
income and/or losses in future periods related to our historical results of
operations.

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 six months ended June 30, 2003, our gains in other areas
of the state more than 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. We
also expect to continue to see a reduction in margin attributable to certain
large commercial, industrial and institutional customers who have not signed
contracts, as these customers sign contracts with us or other competitors at
more favorable rates. When the market opened to competition, large commercial,
industrial and institutional customers who did not sign contracts were assigned
to be served by the affiliated residential electric provider at a designated
rate. This designated rate may be higher than the rate available in the
competitive market.

During 2002, we filed two requests with the PUCT to increase the price to
beat fuel factor for residential and small commercial customers based on
increases in the price of natural gas and purchased energy, as allowed by law.
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.

We have likewise filed two price to beat fuel factor increase requests in
2003. 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.

Our second and final fuel factor request for 2003 was filed in June 2003
and was based upon a 23.1% increase in the price of natural gas from our
previous increase in March 2003. Our requested increase was based on natural gas
prices of $6.100/MMbtu. The request was approved by the PUCT on July 25, 2003
and represents an increase of 9.2% in the total bill of a residential customer
using, on average, 12,000 KWh per year. For further information about the price
to beat fuel factor, see our Form 8-K.

On June 26, 2003, CenterPoint requested immediate elimination of the
transmission and distribution utility's excess mitigation credits (EMC). EMC
are credits against the transmission and distribution utility's nonbypassable
charges to retail electric providers providing service in CenterPoint's
territory. On August 6, 2003, the staff of the PUCT filed a recommendation that
the PUCT dismiss CenterPoint's petition because it does not comport with the
procedure set out in the statute for addressing the issues raised. It is not
known at this time what the ultimate outcome from this proceeding will be and
whether the PUCT will grant, deny or take other action with respect to
CenterPoint's petition. If CenterPoint's request is granted and there is no
corresponding increase in the price to beat rate, there could be a material
adverse impact on our financial condition, results of operations and cash flows.

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The following table provides summary data, including EBIT, of our retail
energy segment for the three and six months ended June 30, 2002 and 2003:

- ----------

(1) Revenues less fuel and purchased power.

Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2003.

EBIT. Our retail energy segment's EBIT decreased $101 million during the
three months ended June 30, 2003 compared to the same period in 2002. The
decrease is primarily due to the following:

o $64 million in decreased margins (revenues less fuel and purchased
power), as described below; and

o a $31 million increase in operation and maintenance and selling,
general and administrative expenses, as discussed below.

Total Revenues. Total revenues increased $637 million during the three
months ended June 30, 2003 compared to the same period in 2002 primarily due to
the following:

65

o $332 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 and
revised estimates for electric sales;

o $301 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; and

o $71 million of increased revenues from our ERCOT generation
facilities, as units began commercial operations in June 2002.

The increase was partially offset by a decrease of $67 million of supply
management revenues related to the risk management, hedging and optimizing of
our electric energy supply.

Fuel and Purchased Power. Fuel and purchased power expenses increased $701
million during the three months ended June 30, 2003 compared to the same period
in 2002 primarily due to the following:

o $343 million of increased purchased power, primarily driven by gas
price increases, revised estimates for purchased power and $27 million
of increased load related fees from the ERCOT ISO;

o $301 million of increased purchased power related to the change in
method of recording revenues and purchased power, as discussed above;
and

o $57 million of increased fuel costs from our ERCOT generation
facilities, as units began commercial operations in June 2002.

Margins. Our retail energy segment's margins decreased $64 million during
the three months ended June 30, 2003 compared to the same period in 2002
primarily due to the following:

o $37 million of losses resulting from revised estimates for electric
sales and supply costs related to prior periods, as discussed above;

o $27 million of increased load related fees from the ERCOT ISO (as
discussed above); and

o $14 million of increased supply costs, primarily driven by gas price
increases and lower supply management revenues, partially offset with
increased revenue rates.

The decrease was offset by $14 million of increased margins from our ERCOT
generation facilities.

Operation and Maintenance and Selling, General and Administrative.
Operation and maintenance expenses and general and administrative expenses
increased $31 million during the three months ended June 30, 2003 compared to
the same period in 2002 primarily due to the following:

o $12 million of increased corporate overhead charges;

o $8 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 $6 million in marketing costs primarily due to additional marketing in
areas outside of the Houston market; and

o $5 million in increased operating costs related to the startup of the
ERCOT generation facilities.

Depreciation and Amortization. Depreciation and amortization expense
increased $4 million during the three months ended June 30, 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.

66

Other Loss, net. Other losses increased $2 million during the three months
ended June 30, 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.

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2003.

EBIT. Our retail energy segment's EBIT decreased $124 million during the
six months ended June 30, 2003 compared to the same period in 2002. The decrease
is primarily due to the following:

o $59 million of increases in operation and maintenance and selling,
general and administrative expenses, as discussed below;

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

o a $5 million decrease in margins, as described below.

Total Revenues. Total revenues increased $1.4 billion during the six months
ended June 30, 2003 compared to the same period in 2002 primarily due to the
following:

o $730 million of revenues for contracted commercial, industrial and
institutional customers due to a change in the method of accounting,
as discussed above;

o $425 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 and
revised estimates for electric sales;

o $160 million of increased revenues from our ERCOT generation
facilities, as units began commercial operations in June 2002; and

o $134 million increase in supply management revenues related to the
risk management, hedging and optimizing of our electric energy supply.

Fuel and Purchased Power. Fuel and purchased power expenses increased $1.5
billion during the six months ended June 30, 2003 compared to the same period in
2002 primarily due to the following:

o $730 million of increased purchased power related to the change in
method of recording revenues and purchased power, as discussed above;

o $589 million of increased purchased power, primarily driven by gas
price increases, revised estimates for purchased power and $38 million
of increased load related fees from the ERCOT ISO; and

o $135 million of increased fuel costs for our ERCOT generation
facilities, which units began commercial operations in June 2002.

Margins. Our retail energy segment's margins decreased $5 million during
the six months ended June 30, 2003 compared to the same period in 2002 primarily
due to increased load related fees from the ERCOT ISO of $38 million (as
discussed above).

The decrease was partially offset by:

o $25 million of increased margins from our ERCOT generation facilities;

o $4 million due to increased revenue rates, partially offset with
increased supply costs, primarily driven by gas price increases and
lower supply management revenues; and

o $4 million of income from revised estimates for electric sales and
supply costs related to prior periods, as discussed above.

67

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 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.

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 June 30, 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
accrual 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 $59 million during the six months ended June 30, 2003 compared to the
same period in 2002 primarily due to the following:

o $25 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 $22 million of increased corporate overhead charges;

o $11 million in marketing costs primarily due to additional marketing
in areas outside of the Houston market; and

o $6 million in increased operating costs related to the startup of the
ERCOT generation facilities.

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 $8 million during the six months ended June 30, 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 $5 million during the six months
ended June 30, 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-ERCOT portfolio of electric
power generation facilities and related fuel delivery and storage asset
positions. We own and/or operate a substantial number of electric power
generating units dispersed broadly across the United States. These units are not
subject to traditional cost-based regulation; therefore, we can generally sell
electricity at prices determined by the market, subject to regulatory
limitations. We market electric energy, capacity and ancillary services and
procure and, in some instances, resell natural gas, coal, fuel oil, natural gas
transportation capacity and other energy-related commodities to optimize our
physical assets and provide risk management services for our asset portfolio. We
are also completing the construction of gas and waste-coal fired generating
facilities, the last of which is due to be completed in 2004.

As of June 30, 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

68

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 June 30, 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. Two of these facilities
(for a total of 1,595 MW) were completed in July 2003 and are now available for
commercial operation. We expect the remaining facilities to achieve commercial
operation in the fourth quarter of 2003 to 2004. Effective January 1, 2003, upon
adoption of FIN No. 46, we consolidated special purpose entities which are
constructing 1,920 MW of net generating capacity (2,117 MW, net of 197 MW to be
retired upon completion of one facility) which are included in the above
amounts, see note 13(a) to our interim financial statements. As discussed above,
we are presently evaluating mothballing or retiring certain power generation
facilities.

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

Given the downturn in the industry and downgrades of our credit ratings, in
the first half of 2002 we reviewed our trading, marketing, power origination and
risk management services strategies and activities. By the third quarter of
2002, we began decreasing the level of these commercial activities in order to
significantly reduce collateral usage. In response to declining prices for
electric energy, capacity and ancillary services across much of the United
States, we also significantly reduced development activities beginning in the
second quarter of 2002. Development is now limited only to the completion of
projects already under construction. The restructuring of all of our associated
commercial, development and support groups resulted in $17 million of severance
costs in 2002 (recorded during the three months ended September 30, 2002).

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

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
have exited our proprietary trading activities, we have legacy positions, which
will be closed as economically feasible or in accordance with their terms. We
will continue to engage in marketing and hedging activities related to our
electric generating facilities, pipeline transportation capacity positions,
pipeline storage positions and fuel positions.

On July 9, 2003, we entered into a definitive agreement to sell our Desert
Basin plant operations. Additionally, it is possible that we may sell other
assets, although to date, we have not reached an agreement to dispose of any
other generating assets of our wholesale energy segment nor have we included or
assumed any proceeds from prospective asset sales other than our Desert Basin
plant operations, in our current liquidity plan. Specific plans to dispose of
assets could result in impairment losses in property, plant and equipment and
goodwill. See note 19 to our interim financial statements for a discussion on
the sale of the Desert Basin plant operations.

We are currently in default under our Liberty credit facility and the
counter-party to our tolling agreement (which has been rejected) at our Liberty
generating station has filed for reorganization under Chapter 11 of the United
States Bankruptcy code. 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 to be allocated. We will evaluate the Liberty generating
station and the related tolling agreement for impairment during the third
quarter of 2003. For information regarding issues and contingencies related to
our Liberty generating station and the related tolling agreement, see note 13(f)
to our interim financial statements.

See note 7 to our interim financial statements for a discussion of our
goodwill impairment analysis to be performed effective July 2003 related to our
wholesale energy segment.

69

The following table provides summary data, including EBIT, of our wholesale
energy segment for the three and six months ended June 30, 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 the full period 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 June 30, 2002 Compared to Three Months Ended June 30, 2003.

EBIT. The wholesale energy segment's EBIT decreased by $51 million during
the three months ended June 30, 2003 compared to the same period in 2002. The
decline in EBIT is primarily due to the following:

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

o decreases in trading margins;

o increases in operation and maintenance expenses; and

o decreases in income/loss of equity investments.

The decline in EBIT was partially offset by:

o $34 million in reserves recorded during the three months ended June
30, 2002 for estimated refund provisions for California energy sales,
as discussed below; and

o decreases in general, administrative and development expenses.

70

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, increased by $244 million during the three months ended June 30, 2003
compared to the same period in 2002. The major components of this increase are:

o a $123 million increase in revenues in the Mid-Atlantic region due to
increased hedging activity and a full quarter of operations of the
Liberty generating station in 2003 as a result of it achieving
commercial operation in May 2002;

o a $91 million increase in revenues in the Mid-Continent region
primarily as a result of increased hedging activity;

o a $51 million increase in the West region as a result of increased
hedging activity and increased power prices due to higher gas prices
in the region; and

o a $34 million refund provision for California energy sales recorded
during the three months ended June 30, 2002.

These increases in revenues were partially offset by the following:

o a $28 million decrease in revenues in the New York region due to
reduced hedging activity and reduced generation as a result of milder
temperatures during the three months ended June 30, 2003 compared to
the same period in 2002; and

o a $22 million decrease in revenues in the Mid-Atlantic region due to
the expiration in May 2002 of a large capacity contract.

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 $265
million during the three months ended June 30, 2003 compared to the same period
in 2002. The major components of this increase are:

o a $140 million increase in fuel and cost of gas sold and purchased
power of the Mid-Atlantic region due to increased hedging activity;

o a $95 million increase in fuel and cost of gas sold and purchased
power in the Mid-Continent region primarily as a result of increased
hedging activity; and

o a $49 million increase in fuel and cost of gas sold and purchased
power in the West region as a result of increased hedging activity and
higher gas prices partially offset by reduced generation.

Trading Margins. Trading margins decreased $43 million during the three
months ended June 30, 2003 compared to the same period in 2002 primarily due to
the discontinuance of proprietary trading in March 2003 and the impact of credit
reserve adjustments during the three months ended June 30, 2002.

Power Generation Margins. Our wholesale energy segment's power generation
margins decreased $21 million during the three months ended June 30, 2003
compared to the same period in 2002. Power generation margins were negatively
impacted due to:

o a $39 million decrease in power generation margins in the Mid-Atlantic
region due to (a) lower capacity revenues as a result of the expiration
of a large capacity contract in May 2002, (b) a decrease in volumes
generated resulting from milder temperatures during the three months
ended June 30, 2003 compared to the same period in 2002 and (c)
decreased margins associated with hedge ineffectiveness; and

o a $26 million net decrease in margins in the New York region due to
decreased volumes generated resulting from milder temperatures
partially offset by an increase in prices for power generation.

This unfavorable variance was partially offset by a $34 million refund provision
for California energy sales recorded during the three months ended June 30,
2002.

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Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $24 million during the three months ended
June 30, 2003 compared to the same period in 2002. Operation and maintenance was
negatively impacted due to:

o a $9 million increase in maintenance expenses in the Mid-Atlantic
region;

o a $7 million increase in maintenance expenses in the New York region;
and

o a $3 million increase in maintenance expenses in the Mid-Continent
region.

General, Administrative and Development. General, administrative and
development expenses decreased $44 million during the three months ended June
30, 2003 compared to the same period in 2002, primarily due to the following:

o a $27 million reduction in development expenses, including the
write-offs of $17 million in 2002 of previously capitalized costs
related to projects that were terminated during the three months ended
June 30, 2002;

o a $16 million decrease in salary and incentive plan expenses primarily
due to reduced employee head count as a result of our 2002 cost
restructuring discussed above; and

o a $10 million net decrease in consulting fees and legal costs.

These decreases were partially offset by a $6 million increase in corporate
overhead allocations.

Depreciation and Amortization. Depreciation and amortization expense decreased
by $1 million during the three months ended June 30, 2003 compared to same
period in 2002 primarily as a result of a $15 million charge to depreciation
expense in 2002 for the retirement of certain units at the Warren plant in the
Mid-Atlantic region. This decrease was partially offset by:

o a $7 million increase in depreciation expense in 2003 as a result of
the write-down of an office building in the Mid-Atlantic region to its
fair market value less costs to sell; and

o a $5 million increase in amortization of emission allowances primarily
in the Mid-Continent region.

Income (Loss) of Equity Investments. 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 June 30, 2003 compared to the same period in 2002,
primarily due to receipts of $8 million of business interruption and
property/casualty insurance settlements in the three months ended June 30, 2002.

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2003.

EBIT. The wholesale energy segment's EBIT decreased by $164 million during
the six months ended June 30, 2003 compared to the same period in 2002. The
decline in EBIT is primarily due to the following:

o reversal in 2002 of previously accrued credit provisions of $38
million for energy sales in California primarily 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 trading margins;

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

o increases in operation and maintenance expenses;

o increases in depreciation and amortization; and

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o decreases in income/loss of equity investments.

These decreases were partially offset by a refund provision for California
energy sales in 2002 of $34 million and a net $75 million reversal in 2003 of
previously recorded refund provisions, as discussed below.

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, increased by $649 million during the six months ended June 30, 2003
compared to the same period in 2002. The major components of this increase were:

o a $268 million increase in revenues in the Mid-Continent region
primarily as a result of the recognition of a full period's revenues
during the six months ended June 30, 2003 compared to the recognition
of a partial period's revenues from Orion MidWest's facilities during
the same period in 2002 as a result of the acquisition of Orion Power
in February 2002 and increased hedging activity;

o a $251 million increase in revenues in the Mid-Atlantic region due to
increased hedging activity and increased power prices driven by colder
winter temperatures and higher gas prices in the region during the six
months ended June 30, 2003;

o a $119 million increase in revenues in the West region primarily as a
result of increased hedging activity and increased power prices due to
higher gas prices in the region;

o a net $75 million reversal in 2003 of previously recorded refund
provisions of $88 million offset by an additional credit provision of
$13 million due to the adoption by the FERC of a different methodology
for determining the gas price component of the refund formula in 2003
(see note 13(e) to our interim financial statements); and

o a $34 million increase in refund provisions recorded during the six
months ended June 30, 2002 for California energy sales.

These increases in revenues were partially offset by the following:

o a $53 million decrease in revenues in the Mid-Atlantic region
primarily as a result of the expiration in May 2002 of a large
capacity contract; and

o a $38 million reversal of a credit provision for energy sales in
California during the six months ended June 30, 2002 (as discussed
above).

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 $596
million during the six months ended June 30, 2003 compared to the same period in
2002. The major components of this increase are:

o a $231 million increase in fuel and cost of gas sold and purchased
power in the Mid-Continent region primarily as a result of the
recognition of a full period's results during the six months ended
June 30, 2003 related to Orion MidWest's facilities, as discussed
above;

o a $199 million increase in fuel and cost of gas sold and purchased
power in the Mid-Atlantic region due to increased hedging activity and
increased gas prices in the region; and

o a $160 million increase in fuel and cost of gas sold and purchased
power in the West region primarily as a result of increased hedging
activity and higher gas prices partially offset by reduced generation.

Trading Margins. Trading margins decreased $162 million during the six
months ended June 30, 2003 compared to the same period in 2002 primarily due to
the discontinuance of proprietary trading in March 2003 and the negative impact
of unanticipated volatility in the natural gas markets. In particular, a pre-tax
loss of approximately $80 million was realized on a financial gas spread
position during the month of February 2003 as discussed above.

Power Generation Margins. Our wholesale energy segment's power generation
margins increased $53 million during the six months ended June 30, 2003 compared
to the same period in 2002. Power generation margins were positively impacted
due to:

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o a net $30 million increase in margins in the West region due primarily
to a net $75 million reserve reversal in 2003 (as discussed above),
which was partially offset by a $41 million decrease in margins due to
(a) lower spark spreads during the six months ended June 30, 2003, (b)
the reduction in hedging results in 2003 as in 2002 we benefited from
hedges entered into in 2001 and (c) an increase in hedge
ineffectiveness losses;

o a $37 million increase in power generation margins in the
Mid-Continent region primarily due to the recognition of a full
period's results from Orion MidWest's facilities during the six months
ended June 30, 2003 compared to the recognition of a partial period's
results during the same period in 2002 as a result of the Orion Power
acquisition in February 2002;

o a $34 million increase in refund provisions recorded during the six
months ended June 30, 2002 for California energy sales.

This favorable variance was partially offset by the following:

o a $38 million reversal of credit provisions during the six months
ended June 30, 2002 (as discussed above);

o a $25 million decrease in margins in the New York region as a result
of losses on open fuel positions and forward power sales and reduced
capacity revenues, partially offset by a full period's results during
the six months ended June 30, 2003 compared to the same period in 2002
as a result of the Orion Power acquisition in February 2002; and

o a net $1 million decrease in margins in the Mid-Atlantic region due to
lower capacity revenues as a result of the expiration of a large
capacity contract in May 2002 offset by (a) an increase in spark
spreads in 2003 and (b) the recognition of a full six months of
operations in 2003 compared to the same period in 2002 due to the
Liberty generating station achieving commercial operation in May 2002.

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $59 million during the six months ended June
30, 2003 compared to the same period in 2002. This was primarily due to:

o a $34 million increase in operation and maintenance expenses in the
New York region primarily as a result of increased maintenance at
Orion NY's facilities coupled with a full period's operations in 2003
compared to a partial period's operations in 2002 as result of the
acquisition of Orion Power in February 2002;

o an $18 million increase in operation and maintenance expense in the
Mid-Continent region primarily as a result of a full period's
operations in 2003 compared to a partial period's operations in 2002
as a result of the acquisition of Orion Power in February 2002; and

o a $12 million increase in operation and maintenance expense in the
Mid-Atlantic region due to increased maintenance expenses in 2003 and
increased costs at the Liberty generating station compared to 2002 as
a result of the Liberty generating station achieving commercial
operation in May 2002.

General, Administrative and Development. General, administrative and
development expenses decreased $43 million during the six months ended June 30,
2003 compared to the same period in 2002, primarily due to the following:

o a $32 million reduction in development expenses, including the
write-offs of $17 million of previously capitalized costs related to
projects that were terminated during the three months ended June 30,
2002;

o a $25 million decrease in salary and incentive plan expenses primarily
due to reduced employee head count as a result of our 2002 cost
restructuring discussed above; and

o a $9 million net decrease in consulting fees and legal costs.

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The decreases were partially offset by:

o an $11 million increase in corporate overhead allocations;

o a $5 million increase in the provision for doubtful accounts related
to the tolling agreement at the Liberty generating station; and

o a $3 million increase in the provision for doubtful accounts due to
the financial deterioration of counterparties in the wholesale energy
industry.

Depreciation and Amortization. Depreciation and amortization expense
increased by $23 million during the six months ended June 30, 2003 compared to
same period in 2002 primarily as a result of the following:

o a $20 million increase in depreciation and amortization expense as a
result of the recognition of a full period's depreciation and
amortization in 2003 at Orion Power as discussed above;

o a $7 million increase in depreciation expense in 2003 as a result of
the write-down of an office building in the Mid-Atlantic region to its
fair market value less cost to sell;

o a $4 million increase in depreciation expense primarily associated
with new information technology systems that were not placed into
service until March 2002; and

o a $2 million increase in depreciation expense as a result of increases
in depreciable assets during 2002 in the West region.

These increases were partially offset by a $15 million charge to depreciation
expense in 2002 for the early retirement of certain units at the Warren plant in
the Mid-Atlantic region resulting in reductions of the estimated useful lives of
those units.

Income (Loss) of Equity Investments. 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 six months ended June 30, 2003 compared to the same period in 2002,
primarily due to receipts of $12 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, including EBIT, of our other
operations segment for the three and six months ended June 30, 2002 and 2003:

Three Months Ended June 30, 2002 Compared to Three Months Ended June 30, 2003.

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Other operation's income (loss) before interest and income taxes changed by
$10 million during the three months ended June 30, 2003 compared to the same
period in 2002, primarily due to an increase in operating loss. Operating loss
increased $8 million during the three months ended June 30, 2003 compared to the
same period in 2002 primarily due to a $3 million accrual of Texas franchise
taxes during the three months ended June 30, 2003 and an increase of $4 million
in unallocated corporate costs previously allocated to our discontinued European
energy operations.

Six Months Ended June 30, 2002 Compared to Six Months Ended June 30, 2003.

Other operation's loss before interest and income taxes increased by $10
million during the six months ended June 30, 2003 compared to the same period in
2002, primarily due to an increase in operating loss. Operating loss increased
$12 million during the six months ended June 30, 2003 compared to the same
period in 2002 primarily due to a $5 million accrual of Texas franchise taxes
during the six months ended June 30, 2003 and an increase of $5 million in
unallocated corporate costs previously allocated to our discontinued European
energy operations. The increase in operating loss was offset by a decrease in
other non-operating losses during the six months ended June 30, 2003 compared to
the same period in 2002. Included in other losses during the six months ended
June 30, 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 our venture capital investments
of $7 million.

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 have exited our proprietary trading activities, we have legacy
positions, which will be closed as economically feasible or in accordance with
their terms. We will continue to engage in marketing and hedging activities
related to our electric generating facilities, pipeline transportation capacity
positions, pipeline storage positions and fuel positions of our wholesale energy
segment and energy supply costs related to our retail energy segment.

Prior to 2003, our retail energy segment's contracts for electricity sales
to large commercial, industrial and institutional customers and the related
energy supply 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 consolidated statements of
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 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 8-K.

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," notes 2(t) and 7 to our Form 8-K 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

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interim financial statements, note 7 to our Form 8-K and "Management's
Discussion and Analysis of Financial Condition and Results of Operations -
Trading and Marketing Operations" to our Form 8-K.

The following table sets forth our consolidated net trading and marketing
assets (liabilities) by segment as of December 31, 2002 and June 30, 2003:

The following table sets forth our consolidated realized and unrealized
trading, marketing and risk management services margins for the three and six
months ended June 30, 2002 and 2003:

Below is an analysis of our net consolidated trading and marketing assets
and liabilities for the six months ended June 30, 2002 and 2003.

During the six months ended June 30, 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 six months ended June 30, 2002, we recognized total fair value of $35
million for these contracts at the inception dates. We have entered into energy
supply contracts to substantially hedge the economics of these contracts. These
contracts had an aggregate fair value of $6 million at the contract inception
dates. 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 8-K.

The remaining fair value of contracts (entered into during the six months
ended June 30, 2002) recorded at inception of $5 million primarily relates to
natural gas transportation contracts entered into by the wholesale energy
segment. The fair values of these wholesale energy contracts at inception
required the utilization of a spread option model and were estimated using OTC
forward price and volatility curves and correlation among natural gas prices at
differing locations, net of estimated credit risk.

During the second quarter of 2002, we changed our methodology for
allocating credit reserves between our trading and non-trading portfolios. Total
credit reserves calculated for both the trading and non-trading portfolios,
which are less than the sum of the independently calculated credit reserves for
each portfolio due to common counterparties between the portfolios, are
allocated to the trading and non-trading portfolios based upon the

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independently calculated trading and non-trading credit reserves. Previously,
credit reserves were independently calculated for the trading portfolio while
credit reserves for the non-trading portfolio were calculated by deducting the
trading credit reserves from the total credit reserves calculated for both
portfolios. This change in methodology reduced credit reserves relating to the
trading portfolio by $18 million.

During the six months ended June 30, 2003, we incorporated rating modifiers
into our calculations of probabilities of default, increasing credit reserves by
$1 million.

The following table sets forth the fair values of the contracts related to
our trading and marketing assets and liabilities as of June 30, 2003:

The following table sets forth the fair values of the contracts related to
our non-trading derivative assets and liabilities as of June 30, 2003:

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 8-K.

The fair values in the above tables are subject to significant changes
based on fluctuating market prices and conditions. Changes in the trading and
marketing assets and liabilities and non-trading derivative assets and
liabilities result primarily from changes in the valuation of the portfolio of
contracts and the timing of settlements. The most significant parameters
impacting the value of our trading and marketing and non-trading portfolios 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" to our Form 8-K for
further discussion and measurement of the market exposure in the trading and
marketing businesses and discussion of credit risk management.

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

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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. Credit risk exposure is monitored daily and the financial
condition of our counterparties is reviewed periodically.

Based on our analysis, we believe our increase in exposure to
non-investment grade or unrated counterparties compared to our total trading and
marketing assets and total non-trading derivative assets has not increased
significantly from December 31, 2002 and March 31, 2003. For additional
information regarding our credit exposure to counterparties, see note 7 to our
Form 8-K and "Management's Discussion and Analysis of Financial Condition and
Results of Operations - Trading and Marketing" in our Form 8-K.

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 our Form 8-K.

FINANCIAL CONDITION

The net cash provided by or used in operating, investing and financing
activities for the six months ended June 30, 2002 and 2003 follows:

Cash Provided by (Used in) Operating Activities

Net cash provided by operating activities during the six months ended June
30, 2003 increased $90 million compared to the same period in 2002. This
increase was primarily due to $277 million of increased working capital and
other changes in assets and liabilities from continuing operations offset by
$241 million of decreases from cash flows from continuing operations, excluding
changes in working capital and other changes in assets and liabilities.
Additionally, cash flows used in the operations of our discontinued European
energy operations decreased $54 million for the six months ended June 30, 2003
compared to the same period in 2002.

Net cash provided by/used in operating activities increased by $277 million
from $168 million in net cash outflows in the six months ended June 30, 2002 to
$109 million in net cash inflows in the six months ended June 30, 2003 due to
changes in working capital and other changes in assets and liabilities due to
the following:

o a $595 million change in cash flows due to a change in accounts
receivable of $1.2 billion primarily due to the startup of our retail
energy segment in 2002 coupled with the impact of our receivables
facility in 2003, offset by a net decrease in cash inflows related to
accounts payable of $396 million primarily related to our wholesale
energy segment and a decrease in cash inflows related to net
intercompany accounts receivable with formerly affiliated companies of
$175 million;

o a $95 million change in inventory related to our wholesale energy
segment; and

o other changes in working capital primarily related to other
liabilities partially offset by taxes.

These increases were partially offset by the following:

o a $114 million decrease in margin deposits on energy trading and
hedging activities primarily due to cash inflows of $203 million in
the six months ended June 30, 2002 compared to $89 million in the six
months ended June 30, 2003;

o $138 million of net collateral deposits related to an operating lease
returned to us in the six months ended June 30, 2002;

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o $114 million decrease in cash inflows related to restricted cash for
the six months ended June 30, 2003 compared to the same period in 2002
primarily attributed to REMA in 2002 (see note 14(a) to our Form 8-K);

o $50 million related to the settlement of two structured transactions
during the six months ended June 30, 2002;

o $29 million paid to purchase interest rate caps during the six months
ended June 30, 2003; and

o purchase of options related to our retail energy segment during the
three months ended June 30, 2003.

Net cash provided by our operations, excluding changes in working capital and
other changes in assets and liabilities, decreased by $241 million from $385
million in the six months ended June 30, 2002 to $144 million in the six months
ended June 30, 2003, primarily due to cash flows of our wholesale energy segment
due to a decline in operating results.

Cash Used in Investing Activities

Net cash used in investing activities during the six months ended June 30,
2003 decreased $2.7 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. The net decrease was partially offset by $217 million of net proceeds
from our June 2003 issuance of convertible senior subordinated notes, which were
placed in an escrow account and are recorded as restricted cash in our
consolidated balance sheet.

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 8-K and note 6 to our interim financial statements.

Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities during the six months ended June
30, 2003 decreased by $4.1 billion compared to the same period in 2002,
primarily due to an increase in 2002 in short-term borrowings of $2.9 billion
used to fund the acquisition of Orion Power in February 2002 and the $350
million prepayment in 2003 of the senior revolving credit facility made in
connection with the refinancing in March 2003 and other reductions in the senior
revolving credit facility in 2003. In addition, during the six months ended June
30, 2003, we paid financing costs of $139 million related to the March 2003
refinancing and our debt issuance in June 2003. This net decrease was partially
offset by the issuance in June 2003 of $225 million aggregate principal amount
of convertible senior subordinated notes in a private placement of which net
proceeds of $217 million were placed in an escrow account for the possible
acquisition of common stock of Texas Genco (as discussed above). See note 10 to
our interim financial statements for further discussion.

CONSOLIDATED CAPITAL REQUIREMENTS

Our liquidity and capital requirements are affected primarily by our
results of operations, capital expenditures, debt service requirements, working
capital needs and collateral requirements. We expect to complete the
construction of new generation facilities that are in progress; however, our
March 2003 credit facilities restrict the construction of any new generation
facilities in the future. Maintenance of plants will continue to include costs
necessary to operate the plants safely, including necessary environmental
expenditures. We will evaluate opportunities to enter retail electric markets
for large commercial, industrial and institutional customers, in particular, in
regions in which we have electric generating facilities and capacity. Subject to
restrictions in our March 2003 credit facilities and our senior secured notes,
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 and our senior secured
notes, if cash generated from operations is insufficient to satisfy our
liquidity requirements, we may seek to sell assets, obtain

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additional credit facilities or other financings and/or issue additional equity
or convertible instruments. For additional discussion regarding our capital
commitments, see note 14(e) to our Form 8-K.

Generating Projects. As of June 30, 2003, we had four generating facilities
under construction (two of which were completed in July 2003). We expect to
complete the remaining facilities in the fourth quarter of 2003 to 2004. Total
estimated cost of constructing these facilities is $2.3 billion. As of June 30,
2003, we had incurred $2.0 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. For more information regarding the
construction agency agreements, see note 13(a) to our interim financial
statements.

Environmental Expenditures. We anticipate spending up to $153 million in
capital expenditures for the remainder of 2003 through 2007 for environmental
compliance, totaling approximately $41 million, $39 million, $23 million, $24
million and $26 million in the remainder of 2003, 2004, 2005, 2006 and 2007,
respectively. In addition, we expect to spend $21 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 June 30, 2003.

Texas Genco Acquisition. 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. Alternatively, we may seek to purchase the common stock or certain assets
of Texas Genco from CenterPoint through a commercial transaction other than
exercise of the option. However, if we acquire Texas Genco (either through
exercise of our purchase option or otherwise), our March 2003 credit facilities
and our senior secured notes impose certain restrictions and limitations on the
structure and funding of the acquisition (including that our March 2003 credit
facilities do not currently allow us to buy assets of Texas Genco). If we do not
acquire Texas Genco, we will need to continue to contract with Texas Genco or
others to meet some of our retail supply obligations. For additional information
regarding our option to purchase CenterPoint's interest in Texas Genco, see
notes 4 and 10 to our interim financial statements.

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 8-K.

Other Operating Lease Commitments. For a discussion of other operating
leases, see note 14(a) to our Form 8-K.

Other Commodity Commitments. For a discussion of other commodity
commitments, see note 14(e) to our Form 8-K.

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 June 30,
2003, our estimate for the payment related to residential customers is between
$160 million and $190 million, with a most probable estimate of $175 million.
Currently, we believe that we will not have to make a payment relating to small
commercial customers. For additional information regarding these items, see note
13(b) to our interim financial statements and note 14(d) to our Form 8-K.

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(e) to our Form 8-K.

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

During 2002 and the first half of 2003, 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

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United States; market contraction, reduced volatility and reduced liquidity in
the gas and power trading markets in the United States; downgrades, in 2002 and
the earlier part of 2003, 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 remaining 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 and our senior secured notes, 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 and our senior secured notes 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 or we may need
to issue equity or convertible instruments (subject to restrictions in our
credit facilities and our senior secured notes), 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 and our June and July 2003 issuances. This may
negatively impact our ability to operate our business.

As a result of our March 2003 refinancing and our June and July 2003 debt
issuances, 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. In addition, a comparison of the
interest rates on the senior secured term loans, of which $1.056 billion was
prepaid with the net proceeds of our issuance of $1.1 billion of senior secured
notes on July 1, 2003, indicates a substantial increase in interest expense. As
of June 30, 2003, the weighted average interest rate on the senior secured term
loans was 5.26% while the weighted average interest rate on the senior secured
notes would have been 9.375%, equivalent to an interest expense difference of
$41 million annually for each $1 billion of principal amount. Also, with the
issuance of $275 million of 5.00% convertible senior subordinated notes in June
and July 2003, our interest expense will increase by approximately $14 million
on an annual basis as long as this debt remains outstanding. For additional
information concerning our March 2003 refinancing and our June and July 2003
debt issuances, including applicable principal amounts and interest rates, see
note 10 to our interim financial statements.

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

In addition, under our March 2003 credit facilities, we were required to
make a $500 million principal payment on May 15, 2006 and 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. With the net
proceeds of our issuance of senior secured notes on July 1, 2003, we have
satisfied (a) the May 15, 2006 principal payment requirement of $500 million and
(b) the May 14, 2004 and May 16, 2005 permanent reduction/paydown amounts, and
therefore we will not be required to make a $500 million principal payment on
May 15, 2006 or pay the applicable fees set forth below, and the applicable
6,268,716 warrants have been cancelled and will not vest on May 16, 2005.

- ----------

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

(2) We have satisfied these aggregate reduction/paydown amounts with the net
proceeds of our issuance of senior secured notes on July 1, 2003.
Consequently, we will not be required to pay these fees and these warrants
have been cancelled.

(3) 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;

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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;

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

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

o successful execution of our planned sale of our European energy
operations and our Desert Basin plant 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. Such restrictions are discussed in note 10 to our interim
financial statements.

Debt Issuances in June and July 2003.

In June 2003, we issued $225 million aggregate principal amount of
convertible senior subordinated notes in a private placement to qualified
institutional buyers. On July 2, 2003, we issued an additional $50 million as a
result of the underwriters' exercise of their option to purchase additional
notes. Our March 2003 credit facilities permit us to place cash proceeds from
certain asset sales and offerings of junior securities in a restricted escrow
account for the possible acquisition of the common stock of Texas Genco, and the
net proceeds of the notes were placed in such an escrow account. The notes bear
interest at 5.00% per annum and mature August 15, 2010. The notes are
convertible into shares of our common stock at a conversion price of
approximately $9.54 per share, subject to adjustment in certain circumstances.
For additional discussion, see note 10 to our interim financial statements.

On July 1, 2003, we issued $550 million 9.25% senior secured notes due July
15, 2010 and $550 million 9.50% senior secured notes due July 15, 2013 in a
private placement to qualified institutional buyers and received net proceeds,
after deducting the initial purchasers' discount and estimated out-of-pocket
expenses, of $1.056 billion. We used the net proceeds of the issuance to prepay
$1.056 billion of a senior secured term loan under our March 2003 credit
facilities. For additional discussion, see note 10 to our interim financial
statements.

Subject to market conditions and other factors, including the restrictions
in our credit facilities and our senior secured notes, we intend to reduce our
bank debt from time to time with the net proceeds from the sale of debt or
equity securities in the capital markets.

Credit Facilities, Bonds and Notes.

As of June 30, 2003, we had $9.3 billion in committed credit facilities,
bonds and notes of which $894 million was unused. As of June 30, 2003, letters
of credit outstanding under these facilities aggregated $828 million and
borrowings aggregated $7.6 billion. As of June 30, 2003, $163 million of our
committed credit facilities are to expire by June 30, 2004. For a discussion of
our credit facilities, bonds and notes, see note 10 to our interim financial
statements.

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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 June 30, 2003:

- ----------

(1) As discussed in notes 10 and 13(f) to our interim financial statements, $5
million of the unused capacity relates to Liberty's working capital
facility, which is currently not available to Liberty.

(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 8-K and note 10 to our interim
financial statements.

Credit Ratings.

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

As of August 1, 2003 the ratings of our convertible senior subordinated
notes and senior secured notes were as follows:

As of August 1, 2003, Moody's rated the REMA lease certificates B1; the
rating outlook is stable. Standard & Poor's rated the certificates B; the rating
outlook is negative. As of August 1, 2003, the Moody's senior unsecured

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debt rating for Orion Power was B2; the rating outlook is stable. Standard &
Poor's senior unsecured debt and corporate ratings for Orion Power were B- and
B, respectively. The outlook is negative.

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 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. 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 August 1,
2003, we have posted cash collateral of $157 million and letters of credit of
$444 million from Reliant Resources' facilities. In addition, we have posted
cash collateral related to commercial operations of $6 million and letters of
credit of $12 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 $17 million from subsidiary facilities and
posted cash collateral of $42 million from subsidiary facilities. Based on
current commodity prices, we estimate that as of August 1, 2003, we could be
required to post additional collateral of up to $565 million related to our
domestic operations. This estimate could increase based on changes to commodity
prices. As of August 1, 2003, we had $52 million in unrestricted cash and cash
equivalents and $866 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 and our July 2003 senior secured notes.

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 marketing and hedging activities, which may result in a
potential reduction and greater volatility in future earnings.

Other Sources and Uses of Cash and Factors Impacting Cash.

Asset Sales.

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 $1.3 billion (Euro 1.1 billion). We
intend to use the cash proceeds from the sale first to pay transaction costs and
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

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the credit facility is December 31, 2003. If we acquire the common stock of
Texas Genco in 2004, we intend to use the remaining cash proceeds of
approximately $0.6 billion (Euro 0.5 billion) to partially fund such
acquisition. However, if we elect not to acquire Texas Genco, 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 18 to our interim financial statements.

Sale of Our Desert Basin Plant Operations. On July 9, 2003, we entered into
a definitive agreement to sell our 588-megawatt Desert Basin plant, located in
Casa Grande, Arizona, to SRP of Phoenix for $289 million. The transaction is
subject to regulatory approvals, including the FERC, and certain third-party
consents and approvals. The transaction is expected to close by the end of 2003.
We intend to use the net proceeds of approximately $287 million to prepay
indebtedness of our senior secured debt or, subject to the limitations in our
March 2003 credit facilities, for the possible acquisition of the common stock
of Texas Genco. For further information regarding the sale of our Desert Plant
operations and the impact on our results of operations, see note 19 to our
interim financial statements.

We intend to use the net proceeds (after prepaying the RECE bank term loan)
from the above asset sales to prepay indebtedness of our March 2003 credit
facilities or for the possible acquisition of the common stock of Texas Genco.
We are limited by our March 2003 credit facilities to utilize a maximum of $650
million of net proceeds from asset sales towards the acquisition of the common
stock of Texas Genco. Any net proceeds above $650 million will be used to prepay
indebtedness of our March 2003 credit facilities.

Other.

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 June 30, 2003, we
were owed total receivables, including interest, of $205 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 June 30, 2003. 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" and our Form 8-K.

Liberty Electric Generating Station Contingency. The output of the Liberty
generating station is contracted under a tolling agreement (which has been
rejected) between LEP, a wholly-owned indirect subsidiary of Orion Power, and
PGET. For information regarding Liberty's default under its credit facility and
issues related to this tolling agreement, the financing of the Liberty
generating station and other related contingencies, including foreclosure
concerns, see notes 10 and 13(f) to our interim financial statements.

Other Items. For other items that may affect our future cash flows from
operations, see our Form 8-K.

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.

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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 $200 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
8-K.

NEW ACCOUNTING PRONOUNCEMENTS, SIGNIFICANT ACCOUNTING POLICIES AND
CHRITICAL ACOUNTING 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 8-K.

CRITICAL ACCOUNTING ESTIMATES

For discussion regarding our critical accounting estimates, see our Form
8-K.

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. For further
discussion of this, see "Management's Discussion and Analysis of Financial
Condition and Results of Operations."

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.

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 our
Form 8-K.

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

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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 and six months ended June
30, 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:

During the six months ended June 30, 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 2003 due to the decline in proprietary trading also contributed
to a reduction in value at risk. There was a short-term increase in value at
risk during February 2003 due to volatility in the natural gas market. As a
result and prior to exiting proprietary trading activities, 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.

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 June 30, 2003 levels would have decreased the fair value of our
non-trading energy derivatives by $69 million.

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 $6.7 billion at June 30, 2003. If
the floating interest rates were to increase by 10% from June 30, 2003 rates,
our interest expense would increase by a total of $2.5 million each month in
which such increase continued. This does not include the impact of our interest
rate swaps discussed below.

On July 1, 2003, we issued $550 million 9.25% senior secured notes due July
15, 2010 and $550 million 9.50% senior secured notes due July 15, 2013 and
received net proceeds, after deducting the initial purchasers' discount and
estimated out-of-pocket expenses, of $1.056 billion. We used the net proceeds of
the issuance to prepay $1.056 billion of a senior secured term loan under our
refinanced credit facilities, which is a floating obligation. As a result of the
July 2003 issuance of senior secured notes (see note 10 to our interim financial
statements), our interest expense will increase substantially.

At June 30, 2003, we had issued fixed-rate debt to third parties
aggregating $777 million, excluding Liberty's fixed-rate debt of $165 million.
As of June 30, 2003, the fair values of these debt instruments, excluding
Liberty's fixed rate debt, were $762 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

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Liberty's fixed-rate debt, would increase by $35 million if interest rates were
to decline by 10% from their rates at June 30, 2003.

As of June 30, 2003, we have interest rate swap contracts with an aggregate
notional amount of $850 million that fix the interest rate applicable to
floating rate short-term debt and floating rate long-term debt. These swaps
could be terminated at a cost of $129 million ($111 million for Orion MidWest
and Orion NY and $18 million for Channelview) at June 30, 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
June 30, 2003 level of interest rates would increase the cost of terminating the
interest rate swaps by $6 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.
The notional amounts of the interest rate caps are $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 $3 million at June 30, 2003.
A decrease of 10% in the June 30, 2003 level of interest rates would cause the
market value of the interest rate caps to decline by $1 million, resulting in a
loss in earnings. For information regarding the accounting for these interest
rate derivative instruments, see notes 8 and 10 to our interim financial
statements.

* * *

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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-15(e) and 15d-15(e) under the Securities Exchange Act of 1934) as
of the end of the period covered by this report. Based on such evaluation, such
officers have concluded that, as of the end of such period, 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

There have not been any changes in our internal control over financial
reporting (as such term is defined in Rules 13a-15(f) and 15d-15(f) under the
Securities Exchange Act of 1934) during the fiscal quarter to which this report
relates that have materially affected, or are reasonably likely to materially
affect, our internal control over financial reporting.

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PART II.
OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For a description of legal proceedings affecting us, see notes 13(d) and
13(e) 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. With the net
proceeds of our issuance of senior secured notes on July 1, 2003, we have
satisfied the May 2005 permanent reduction amount and therefore the applicable
6,268,716 warrants described above have been cancelled. The 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.

In June 2003, we issued $225 million aggregate principal amount of
convertible senior subordinated notes in a private placement to qualified
institutional buyers. The underwriters for the offering were Deutsche Bank
Securities, Goldman, Sachs & Co., Banc of America Securities LLC, Barclays
Capital, ABNAMRO Rothschild LLC and Commerzbank Securities. On July 2, 2003, we
issued an additional $50 million as a result of the underwriters' exercise of
their option to purchase additional notes. We received net proceeds from the
issuances, after deducting the initial purchasers' discount and estimated
out-of-pocket expenses, of $266 million. Our March 2003 credit facilities permit
us to place cash proceeds from certain asset sales and offerings of junior
securities in a restricted escrow account for the possible acquisition of the
common stock of Texas Genco, and the net proceeds of the notes were placed in
such an escrow account. The notes bear interest at 5.00% per annum, payable
semi-annually on February 15 and August 15, and mature August 15, 2010. The
first interest payment will be made on August 15, 2003. The notes are
convertible into shares of our common stock at a conversion price of
approximately $9.54 per share, subject to adjustment in certain circumstances.
We may redeem the notes, in whole or in part, at any time on or after August 20,
2008, if the last reported sale price of our common stock is at least 125% of
the conversion price then in effect for a specified period of time. The notes
were not registered with the SEC in reliance upon Rule 144A promulgated under
the Securities Act of 1933.

In connection with our March 2003 credit facilities and the issuance of the
senior secured notes on July 1, 2003, we became subject to restrictions on our
ability to pay dividends on our common stock. For a discussion of the terms of
these items, see note 10 to our interim financial statements.

ITEM 6. 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.

We filed a Current Report on Form 8-K, dated March 31, 2003, (a) announcing
we received an extension of the March 28 maturity date of the $2.9 billion Orion
bridge loan until midnight, Monday, March 31, (b) announcing we successfully
completed a $6.2 billion financing package, and (c) providing the slide
presentation used by certain of our executive officers when they spoke to the
public, as well as various members of the financial and investing community on
April 1, 2003.

We filed a Current Report on Form 8-K, dated April 13, 2003, (a) announcing
the resignation of Steve Letbetter and (b) providing consolidated financial
statements of Orion Power Holdings, Inc.

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We filed a Current Report on Form 8-K, dated April 28, 2003, providing
consolidated financial statements of Reliant Energy Retail Holdings, LLC.

We filed a Current Report on Form 8-K, dated May 8, 2003, (a) announcing
our earnings for the quarter ended March 31, 2003 and (b) providing the slide
presentation used by certain executive officers of Reliant Resources, Inc. when
they spoke to the public, as well as various members of the financial and
investing community on May 8, 2003.

We filed a Current Report on Form 8-K, dated May 12, 2003, announcing that
we had entered into a settlement with the United States Securities and Exchange
Commission.

We filed a Current Report on Form 8-K, dated May 15, 2003, providing
consolidated interim financial statements of Orion Power Holdings, Inc.

We filed a Current Report on Form 8-K, dated May 27, 2003, providing
consolidated interim financial statements of Reliant Energy Mid-Atlantic Power
Holdings, LLC.

We filed a Current Report on Form 8-K, dated June 4, 2003, providing
revised (a) Selected Financial Data, (b) Management's Discussion and Analysis of
Financial Condition and Results of Operations, (c) Quantitative and Qualitative
Disclosures About Market Risk, and (d) historical consolidated financial
statements, as reported in our Annual Report on Form 10-K/A for the year ended
December 31, 2002, as well as (e) the consent of our independent auditors and
(f) a glossary of terms used in (a)-(d).

We filed a Current Report on Form 8-K, dated June 9, 2003, (a) announcing a
presentation on the company on Tuesday, June 10 by our chief financial officer
and (b) providing the slide presentation used by our chief financial officer
when he spoke to the public, as well as various members of the financial and
investing community on June 10, 2003.

We filed a Current Report on Form 8-K, dated June 13, 2003, (a) announcing
our request to the Public Utility Commission of Texas for permission to increase
the price to beat for Houston-area residential electricity customers and (b)
announcing the launch of a private placement of senior secured notes and
convertible senior subordinated notes.

We filed a Current Report on Form 8-K, dated June 19, 2003, announcing the
pricing of $225 million of 5% convertible senior subordinated notes due 2010 in
a placement with qualified institutional buyers under rule 144A.

We filed a Current Report on Form 8-K, dated June 27, 2003, providing
consolidated financial statements of Reliant Energy Retail Holdings, LLC.

We filed a Current Report on Form 8-K, dated June 30, 2003, providing (a)
Financial Statements and Supplementary Data of Reliant Resources, Inc. and
Subsidiaries and (b) the consent of our independent auditors.

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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)
August 13, 2003

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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.