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 SEPTEMBER 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 (I.R.S. Employer Identification No.)
Incorporation or Organization)

1000 Main Street
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 12b-2 of the Exchange Act). Yes [X] No [ ].

As of November 10, 2003, Reliant Resources, Inc. had 294,591,650 shares of
common stock outstanding, excluding 5,212,350 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 SEPTEMBER 30, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Consolidated Statements of Operations (unaudited)
Three and Nine Months Ended September 30, 2002 and 2003 .................................. 1

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

Consolidated Statements of Cash Flows (unaudited)
Nine Months Ended September 30, 2002 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 .... 48

Item 3. Quantitative and Qualitative Disclosures About Market Risk ............................... 81

Item 4. Controls and Procedures .................................................................. 84

PART II. OTHER INFORMATION

Item 1. Legal Proceedings ........................................................................ 85

Item 2. Changes in Securities and Use of Proceeds ................................................ 85

Item 4. Submission of Matters to a Vote of Security Holders ...................................... 85

Item 6. Exhibits, Financial Statement Schedules and Reports on Form 8-K .......................... 85

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

When we make statements containing projections about our revenues,
income, earnings and other financial items, our plans and objectives for the
future, future economic performance, transactions for the sale of parts of our
operations and financings related thereto, when we make statements containing
any other projections or estimates about our assumptions relating to these types
of statements, we are making "forward-looking statements." These statements
usually relate to future events and anticipated revenues, earnings, business
strategies, competitive position or other aspects of our operations or operating
results. In many cases you can identify forward-looking statements by
terminology such as "anticipate," "estimate," "believe," "continue," "could,"
"intend," "may," "plan," "potential," "predict," "should," "will," "expect,"
"objective," "projection," "forecast," "goal," "guidance," "outlook" and other
similar words. However, the absence of these words does not mean that the
statements are not forward-looking. Although we believe that the expectations
and the underlying assumptions reflected in our forward-looking statements are
reasonable, there can be no assurance that these expectations will prove to be
correct. Forward-looking statements are not guarantees of future performance or
events. Such statements involve a number of risks and uncertainties, and actual
results may differ materially from the results discussed in the forward-looking
statements.

In addition to the matters described in this report and the exhibits
attached hereto, the following are some of the factors that could cause actual
results to differ materially from those expressed or implied in our
forward-looking statements:

o changes in laws and regulations, including deregulation,
re-regulation and restructuring of the electric utility
industry, changes in or application of environmental and other
laws and regulations to which we are subject, and changes in
or application of laws or regulations applicable to other
aspects of our business, such as hedging activities;

o the outcome of pending lawsuits, governmental proceedings and
investigations;

o the effects of competition, including the extent and timing of
the entry of additional competitors in our markets;

o liquidity concerns in our markets;

o our pursuit of potential business strategies;

o the timing and extent of changes in commodity prices and
interest rates;

o the availability of adequate supplies of fuel, water and
associated transportation necessary to operate our portfolio
of generation assets;

o weather variations and other natural phenomena, which can
affect the demand for power from or our ability to produce
power at our generating facilities;

o financial market conditions and our access to capital,
including availability of funds in the capital markets for
merchant generation companies;

o the creditworthiness or bankruptcy or other financial distress
of our counterparties;

o actions by rating agencies with respect to us or our
competitors;

o acts of terrorism or war;

o the availability and price of insurance;

o political, legal, regulatory and economic conditions and
developments;

o the successful operation of deregulating power markets; the
reliability of the systems, procedures and other
infrastructure necessary to operate our retail electric
business, including the systems owned and operated by the
independent system operator in the Electric Reliability
Council of Texas;

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o the resolution of the refusal by certain California market
participants to pay our receivables balances and the
resolution of the refund methodologies; and

o the outcome of regulatory approval processes relating to the
pending sale of our European energy operations (including the
impact of these processes under the terms and conditions of
the share purchase agreement relating to the disposition of
these operations) and the consequences of a significant delay
in the consummation of, or the termination of, the share
purchase agreement relating to these operations.

Each forward-looking statement speaks only as of the date of the particular
statement and we undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, future events
or otherwise. 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 and six months ended June 30, 2002 and 2003
in our Quarterly Report on Form 10-Q filed on August 13, 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 audited consolidated
financial statements and notes included in our Current Report on Form 8-K filed
on June 30, 2003.

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.

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 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.

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 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 nine months ended
September 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

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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 17 regarding the sale of our
European energy operations and the classification as discontinued operations.

(2) NEW ACCOUNTING PRONOUNCEMENTS

Recent Accounting Pronouncements.

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 and when a derivative contains a financing
component, as discussed in SFAS No. 133, "Accounting for Derivative Instruments
and Hedging Activities," as amended (SFAS No. 133). 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. The implementation of SFAS No. 149 did not have a material impact
on our consolidated financial statements.

FIN No. 46. In January 2003, the FASB issued FASB Interpretation No. 46
"Consolidation of Variable Interest Entities, an Interpretation of ARB No. 51"
(FIN No. 46). The objective of FIN No. 46 is to achieve more consistent
application of consolidation policies to variable interest entities and to
improve comparability between enterprises engaged in similar activities. FIN No.
46 states that an enterprise must consolidate a variable interest entity if the
enterprise has a variable interest that will absorb a majority of the entity's
expected losses if they occur, receives a majority of the entity's expected
residual returns if they occur, or both. 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.
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, as it relates to our variable
interests in three power generation projects that were being constructed by
off-balance sheet entities under construction agency agreements, which pursuant
to this guidance required consolidation upon adoption. Results for the nine
months ended September 30, 2003, include the cumulative effect of accounting
change of $1 million loss, net of tax. As of January 1, 2003, these 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 entities' financing
agreements, the construction agency agreements and the related guarantees were
terminated as part of the refinancing in March 2003. For information regarding
the refinancing, see note 10.

The application of FIN No. 46 is still evolving as the FASB continues
to address issues submitted for consideration. On October 9, 2003, the FASB
issued FASB Staff Position (FSP) FIN 46-6, "Effective Date of FASB
Interpretation No. 46," which allows enterprises to defer the application date
for variable interests or potential variable interests entities created before
February 1, 2003 to the end of the first interim or annual period ending after
December 15, 2003. We will continue to assess our adoption of FIN No. 46 and the
application of clarified or revised guidance.

EITF No. 03-11. In July 2003, the EITF issued EITF Issue No. 03-11,
"Reporting Realized Gains and Losses on Derivative Instruments that are Subject
to FASB Statement No. 133 and Not "Held for Trading Purposes" as Defined in EITF
Issue No. 02-03" (EITF No. 03-11). The EITF reached a consensus that realized
gains and losses on derivative contracts not "held for trading purposes" should
be reported either on a net or gross basis based on the relevant facts and
circumstances. In analyzing these facts and circumstances, EITF Issue No. 99-19,
"Reporting Revenue Gross as a Principal versus Net as an Agent," should be
applied. Reclassification of prior year amounts is not required. EITF No. 03-11
became effective October 1, 2003. We believe the application of EITF No. 03-11
could result in a significant amount of our commodity hedging activities to be
reported on a net basis prospectively that were previously reported on a gross
basis.

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Other Accounting Pronouncements.

SFAS No. 143. In June 2001, the Financial Accounting Standards Board
(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 nine months ended September 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.

If we had adopted SFAS No. 143 on January 1, 2002, the impact would
have been immaterial to our consolidated income from continuing operations and
net income.

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
Payments ......................... (2)
----
Balance at September 30, 2003 .... $ 10
====

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 "fair value" valuation
models and other items. We 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 or greater than 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 nine months ended September 30, 2002 and 2003, which take into
account the amortization of stock-based compensation,

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including performance shares, purchases under the employee stock purchase plan
and stock options, to expense on a straight-line basis over the vesting periods:

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 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 nine months ended September 30, 2003 as
the fair value of guarantees issued after December 31, 2002 was nominal on the
date on which the guarantee was issued. See note 13(d).

EITF No. 02-03. In June 2002, the Emerging Issues Task Force (EITF) had
its initial meeting regarding EITF Issue No. 02-03, "Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities" (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 October 2002 consensus was effective for fiscal
periods beginning after December 15, 2002. However, consistent with this
consensus and as then allowed under EITF No. 98-10, "Accounting for Contracts
Involved

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in Energy Trading and Risk Management Activities" (EITF No. 98-10), beginning
with the quarter ended September 30, 2002, we reported all energy trading and
marketing activities on a net basis in the consolidated statements of
operations.

In October 2002, the EITF also reached a consensus to rescind EITF No.
98-10. All contracts that would have been accounted for under EITF No. 98-10,
and that do not fall within the scope of SFAS No. 133, may no longer be
marked-to-market through earnings, effective 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 nine months
ended September 30, 2003. 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 that did not meet the definition of a derivative under SFAS No. 133.

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. Beginning 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. The related revenues and purchased power and delivery fees are
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 2002 and 2003. During the
three and nine months ended September 30, 2002, our retail energy segment
recognized $42 million and $27 million, respectively, of unrealized net gains
related to its contracted electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts. During the
three and nine months ended September 30, 2003, volumes were delivered under
contracted electricity sales to large commercial, industrial and institutional
customers and the related energy supply contracts for which $19 million and $50
million, respectively, was previously recognized as unrealized earnings in prior
periods. As of September 30, 2003, our retail energy segment has unrealized
gains that have been previously recorded in our results of operations of $42
million that will be realized when the electricity is delivered to our customers
($15 million in the remainder of 2003 and $27 million in 2004 through 2006).
These unrealized gains of $42 million are recorded in non-trading derivative
assets/liabilities in our consolidated balance sheet as of September 30, 2003
and the related contracts are accounted for as cash flow hedges or "normal"
sales contracts under SFAS No. 133.

(3) HISTORICAL RELATED PARTY TRANSACTIONS

Prior to the Distribution, as described in note 1, CenterPoint was a
related party. The interim financial statements for 2002 include transactions
between CenterPoint and us. These services included various corporate support
services (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 nine months ended September 30, 2002, were $5 million and $15
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
nine months ended September 30, 2002, we incurred $8 million and $24 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 $5 million, respectively, during the three
and nine months ended September 30, 2002.

We purchased natural gas, natural gas transportation services, electric
generation energy and capacity, and electric transmission services from,
supplied natural gas to, and provided marketing and risk management services to
affiliates of

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CenterPoint. Purchases of electric generation energy and capacity and electric
transmission services from CenterPoint and its subsidiaries were $634 million
and $1.5 billion, respectively, for the three and nine months ended September
30, 2002. Purchases and sales related to our trading and marketing activities
are recorded net in trading margins in the consolidated statements of
operations. During the three and nine months ended September 30, 2002, the net
purchases and sales and services from/to CenterPoint and its subsidiaries
related to our trading and marketing operations totaled $16 million and $161
million, respectively. In addition, during the three and nine months ended
September 30, 2002, other sales and services to CenterPoint and its subsidiaries
totaled $2 million and $15 million, respectively. Sales and purchases to/from
CenterPoint subsequent to the Distribution are not reported as affiliated
transactions.

During the three and nine months ended September 30, 2002, CenterPoint
made equity contributions to us of $21 million, which primarily related to
benefit obligations. During the three and nine months ended September 30, 2003,
CenterPoint made equity contributions to us of $0 and $47 million, respectively.
The $47 million in contributions in the first quarter of 2003 primarily related
to the non-cash conversion to equity of accounts payable to CenterPoint.

(4) AGREEMENTS RELATING TO TEXAS GENCO

Texas Genco, LP is a wholly-owned subsidiary of Texas Genco Holdings,
Inc., a majority-owned subsidiary of CenterPoint, and owns the Texas generating
assets formerly held by CenterPoint's electric utility division. Texas Genco, LP
and Texas Genco Holdings, Inc. are collectively referred to herein as "Texas
Genco." Texas Genco, as the affiliated power generator of CenterPoint's electric
utility, 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 provided
by retail electric providers other than us. We are not able to participate in
these legally mandated capacity auctions. Under CenterPoint's agreement with us,
Texas Genco must auction the remainder of its capacity after certain other
adjustments. We have the right to participate directly in such auctions, without
any restrictions on our level of participation. Texas Genco's obligation to
auction its remaining 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.

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. In connection with this contract, we have granted
Texas Genco a security interest in our rights in the accounts receivable and
related assets of certain of our subsidiaries. The liens on our rights in the
accounts receivable and related assets are junior to our receivables facility
and senior to our March 2003 credit facilities and to our senior secured notes.
The term of the master power purchase contract terminates on either (a) the
expiration date of the Texas Genco option, if the option is not exercised, or
(b) on the earlier of (i) the closing date of the acquisition of Texas Genco, if
the option is exercised, or (ii) August 1, 2004. See note 14 regarding our
receivables facility.

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 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, CenterPoint will pay us in cash to assume
CenterPoint's obligations under such instruments in 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 purchased entitlements to some of the generation capacity of
electric generation assets of Texas Genco. We purchased these entitlements in
capacity auctions conducted by Texas Genco and pursuant to rights granted to us

9

under an agreement with CenterPoint. As of September 30, 2003, we had purchased
entitlements to capacity of Texas Genco averaging 6,848 megawatts (MW) per month
in 2003, 4,913 MW per month in 2004 and 798 MW per month in 2005. Our
anticipated capacity payments related to these capacity entitlements are $111
million for the remainder of 2003, $461 million for 2004 and $155 million for
2005. The capacity entitlements are accounted for as normal purchases under SFAS
No. 133. See note 8 for discussion of our derivative financial instruments.

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 generating 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. for an aggregate purchase price of $2.9
billion and assumed debt obligations of $2.4 billion. Orion Power refers to
Orion Power Holdings, Inc. and its subsidiaries, unless we specify or the
context indicates otherwise. We funded the Orion Power acquisition with a $2.9
billion credit facility 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.

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 nine months
ended September 30, 2002, as if the acquisition had occurred on January 1, 2002:

10

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, "Business Combinations" and SFAS No. 142, "Goodwill and Other
Intangible Assets" (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.

SFAS No. 142 requires goodwill to be tested annually and between annual
tests in certain circumstances. The date of our annual impairment test is as of
November 1.

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.

Our goodwill impairment analyses estimate the fair value of our
reporting units using a combination of approaches, including an income approach
based on a discounted cash flow analysis, a market approach based on
transactions in the marketplace for comparable types of assets and a comparable
public company approach. The fair values of our reporting units have been
determined by management with the assistance of an independent appraiser. 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 and the
independent appraiser, any of which if changed could significantly affect the
outcome of the analysis.

Goodwill Impairment Transition Test. 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. 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.

2002 Annual Goodwill Impairment Test. We performed our annual
impairment test in 2002 effective November 1, 2002. 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

11

operations to a Netherlands-based electricity distributor (see note 17). We
concluded that the sales price reflected 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 17. Our 2002 annual impairment test
identified no other impairments of goodwill for our other reporting units.

July 2003 Goodwill Impairment Test Related to our Wholesale Energy
Segment. On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant. The sale closed on October 15, 2003. See note
18 for further discussion of this sale. This sale of our Desert Basin plant
required 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 required 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 to be tested for
impairment was approximately $1.4 billion. We did not allocate any goodwill to
our Desert Basin plant operations prior to July 1, 2003.

As a result of the July 2003 test, we recognized an impairment of $985
million (pre-tax and after-tax) during the three months ended September 30,
2003. This impairment was due to a decrease in the fair value of our wholesale
energy reporting unit. This change in fair value is primarily due to: reduced
projected commercialization opportunities related to our power generation
assets; the elimination of proprietary trading; lower projected regulatory
capacity values due to the lack of development of appropriate market structures
and a lower outlook for revenues from existing regulatory capacity markets;
reduced long-term margins from our existing portfolio as a result of lowering
our estimates of the margins required to induce new capacity to enter the
markets; potential for the retirement and/or mothballing of some of our
facilities; lower market and comparable public company values data; and the
level of working capital; partially offset by reductions in our commercial,
operational and support groups costs and lower projected operations and
maintenance expense. As of September 30, 2003, our wholesale energy reporting
unit had remaining goodwill of $426 million.

The internal cash flow analysis used in our July 2003 impairment
analysis for our wholesale energy reporting unit was over a period of 15 years
with an assumed terminal value of our operations at the end of the analysis
using a multiple of 7.5 as applied to EBITDA (earnings from continuing
operations before depreciation and amortization, interest expense, interest
income and income taxes). For this impairment test, these after-tax cash flows
(excluding interest) were discounted back to the date of the analysis at a
risk-adjusted discount rate of 9% in order to determine the fair value of the
reporting unit under the income approach. The income approach was weighted along
with the market approach and comparable public company approach (which was
weighted at 0%) to determine the fair value of the reporting unit. Our internal
cash flow analyses for our wholesale energy reporting unit assumed that the
demand for power in the regions in which we operate would rise at an average
annual rate of approximately 2% over the next several years (depending on the
region, the specific rate is projected to be somewhat higher or lower). This
growth over time was assumed to result in decreasing reserve margins and
increasing power generation margins. We assumed that margins would increase over
time to a level such that new generation facilities will yield an after-tax rate
of return on investment of 7.5% (depending on the region, estimated to be
between 2008 and 2012). Our November 1, 2002 impairment test had assumed that
power generation margins would increase over time to a level such that new
generation facilities would be able to yield an after-tax rate of return on
investment of 9%. This percentage was decreased due primarily to our belief that
future construction of new generation facilities will likely be driven directly
or indirectly by regulated utilities. As a result, we expect that power
generation margins will increase over time to a level such that new generation
facilities will yield an after-tax rate of return representative of a regulated
utility's cost of capital (7.5%) rather than that of an independent power
producer (9.0%), which was the basis for the November 2002 analysis.

We plan to perform our annual goodwill impairment tests for our
wholesale energy and retail energy reporting units effective November 1, 2003.
If actual results of operations are worse than projected or our wholesale energy
market outlook changes, we could have additional impairments of goodwill and
impairments of our property, plant and equipment in future periods, which, in
turn, could have a material adverse effect on our results of operations.
Additionally, our ongoing evaluation of our wholesale energy business could lead
to decisions to mothball, retire or dispose of assets. Any of these events could
result in additional impairment charges related to goodwill and property, plant
and equipment.

12

(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.
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. This statement requires that a derivative be
recognized at fair value in the balance sheet whether or not it is designated as
a hedge. For a derivative that is designated as a cash flow hedge, and depending
on its effectiveness, changes in fair value are deferred as a component of
accumulated other comprehensive income (loss), net of applicable taxes. For a
derivative that is designated as a fair value hedge, changes in fair value of
the hedge, as well as the hedged item, are recorded as unrealized gains or
losses. For a derivative not designated as a hedge, changes in fair value are
recorded as unrealized gains or losses. 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 17. Derivative contracts meeting the normal
purchases and normal sales exception of SFAS No. 133 are not subject to the
requirements of the statement.

Cash Flow Hedges. During the three and nine months ended September 30,
2002, the amount of hedge ineffectiveness recognized in the results of
operations from derivatives that are designated and qualify as cash flow hedges,
including interest rate derivative instruments (see note 10(b)), was a loss of
$18 million and $19 million, respectively. During the three and nine months
ended September 30, 2003, the amount of hedge ineffectiveness recognized in the
results of operations from derivatives that are designated and qualify as cash
flow hedges, including interest rate derivative instruments, was a loss of $17
million and $32 million, respectively. For the three and nine months ended
September 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 a forecasted transaction will not occur, we immediately recognize in net
income (loss) the deferred gains and losses recognized in accumulated other
comprehensive income (loss). The associated hedging instrument is then marked to
market through earnings for the remainder of the contract term. During the nine
months ended September 30, 2002, we recognized a loss of approximately $0.2
million in earnings as a result of the discontinuance of cash flow hedges
because it was probable that the forecasted transaction would not occur. During
the three and nine months ended September 30, 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 September 30, 2003, we expect $44
million of losses netted in accumulated other comprehensive loss to be
reclassified into net income (loss) during the period from October 1, 2003 to
September 30, 2004.

Classification of Economic Hedges. During the three months ended
September 30, 2003, we changed our classification of certain derivative
activities that historically were classified as trading activities to
non-trading activities. These transactions do not meet the requirements for
hedge accounting treatment under SFAS No. 133; however, such transactions were
entered into to economically hedge commodity risk associated with our wholesale
energy power generation operations. We have reclassified amounts in our
consolidated statement of operations for the six months ended June 30, 2003 from
trading margins of $7 million to revenues and purchased power expense based on
the underlying hedged item resulting in an increase in revenues and purchased
power expense of $15 million and $8 million, respectively. As of June 30, 2003,
the amounts of non-trading derivative assets and liabilities previously
classified as trading and marketing assets and liabilities were $25 million and
$15 million, respectively. Corresponding amounts for these activities have not
been reclassified for periods prior to January 1, 2003 as prior period amounts
were not material to our consolidated financial statements.

13

(9) EQUITY INVESTMENTS

We have a 50% interest in a 470 MW electric generation plant in Boulder
City, Nevada. We have a 50% partnership interest in a 108 MW cogeneration plant
in Orange, Texas. These equity investments are included in our wholesale energy
segment.

Our equity investments are as follows:

As of September 30, 2003 the companies in which we have an equity
investment carry debt that is currently estimated to be $136 million ($68
million based on our proportionate ownership interests of the investments).

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

14

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

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

- ---------
(1) The weighted average interest rate is for borrowings outstanding as of
December 31, 2002 or September 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) See below for a discussion of the facilities refinanced in March 2003. As a
result of the refinancing, $3.9 billion has been classified as long-term as
of December 31, 2002.

(4) Of the amount shown as current under the Liberty credit agreement, $9
million matures in the next twelve months as of September 30, 2003. The
entire balance outstanding under this credit agreement has been classified
as current. See below for further discussion.

(5) Debt and interest rate swaps acquired in the Orion Power acquisition were
adjusted to fair market value as of the acquisition date. Included in the
adjustment to fair value of debt is $68 million related to the Orion Power
senior notes as of September 30, 2003. Included in the adjustment to fair
value of interest rate swaps is $29 million and $20 million related to the
Orion MidWest and Orion NY credit facilities, respectively, as of September
30, 2003. Included in interest expense is amortization of $2 million and $2
million for valuation adjustments for debt and $7 million and $4 million for
valuation adjustments for interest rate swaps, respectively, for the three
months ended September 30, 2002 and 2003, respectively. Included in interest
expense is amortization of $5 million and $6 million for valuation
adjustments for debt and $17 million and $16 million for valuation
adjustments for interest rate swaps, respectively, for the nine months ended
September 30, 2002 and 2003, respectively. These valuation adjustments are
being amortized over the respective remaining terms of the related financial
instruments.

Restricted Net Assets of Subsidiaries. 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

15

restrictions are on the net assets of Orion Power Capital, LLC (Orion Capital),
Liberty Electric PA, LLC (Liberty) and Reliant Energy Channelview L.P.
(Channelview). Orion Power Midwest, LP (Orion MidWest) and Orion Power New York,
LP (Orion NY) are subsidiaries of Orion Capital.

(A) BANKING OR CREDIT FACILITIES, BONDS AND NOTES.

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

- ------------
(1) Included in this amount is $407 million of letters of credit outstanding
that support the $400 million of PEDFA bonds related to the Seward plant.

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

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

As of September 30, 2003, committed credit facilities and notes
aggregating $717 million were unsecured.

Senior Secured Term Loans, Senior Secured Revolver and Senior Priority
Revolver. During March 2003, we refinanced our (a) $1.6 billion senior revolving
credit facilities, (b) $2.9 billion 364-day Orion acquisition term loan, and (c)
$1.425 billion construction agency financing commitment, and we obtained a new
$300 million senior priority revolving credit facility. The syndicated 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 CenterPoint's holdings 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.
These credit facilities contain numerous restrictions including that we are not
permitted to use the proceeds from loans under any of these facilities to
acquire Texas Genco.

If the refinanced credit facilities are not permanently reduced by $2.0
billion (cumulatively) by May 2006, we must pay a fee of 1.0% of the amount of
the refinanced credit facilities still outstanding on such date. However, as of
September 30, 2003, we have paid $1.056 billion of the required $2.0 billion
permanent reduction. 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. 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. The covenants are not anticipated to materially restrict
our ability to borrow funds or obtain letters of credit. Our failure

16

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, of which 6,268,716 warrants have subsequently been
cancelled, to acquire shares of our common stock. Of the total issued and
outstanding, 7,835,894 warrants vested in March 2003 and the remaining 6,268,716
will vest if our refinanced credit facilities have not been reduced by an
aggregate of $2.0 billion by May 2006. The exercise prices of the warrants are
based on average market prices of our common stock during specified periods in
proximity to the refinancing date. The exercise price of the warrants that
vested in March 2003 is $5.09 per share. 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 indebtedness 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 holders of other secured indebtedness, 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 (other than any proceeds from the
sale of our Desert Basin plant and our European energy operations) and separates
the Orion Power limited guarantee from the credit agreement so it can ratably
guarantee the bank debt and the senior secured notes.

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 senior secured term loans under our
refinanced credit facilities, discussed above. 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 holders of certain future
secured indebtedness. 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 15 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
senior secured notes indentures contain covenants 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.

Convertible Senior Subordinated Notes. In June and July 2003, we issued
$275 million aggregate principal amount of convertible senior subordinated notes
in a private placement to qualified institutional buyers. 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 CenterPoint's holdings 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). If we
do not use these net proceeds for the acquisition of CenterPoint's holdings of
the common stock of Texas Genco, we may keep up to 50% of the net cash proceeds
for general corporate purposes; however, we must use the remainder to prepay
indebtedness under our March 2003 credit facilities. The notes bear interest at
5.00% per annum, payable semi-annually on February 15 and August 15, 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. 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.

Liberty Credit Agreement. In July 2000, Liberty Electric Power, LLC
(LEP) and Liberty, indirect wholly-owned subsidiaries of Orion Power, entered
into a credit agreement 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 debt service reserve letter of credit facility of $17
million; (d) a revolving working capital facility for an amount of up to $5
million and (e) an equity bridge loan of up to $41 million. In May 2002, the
construction loans were converted to term loans. 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

17

as credit support was returned for cancellation. The outstanding borrowings
related to the Liberty credit agreement are non-recourse to Reliant Resources
and all other subsidiaries. Liberty is currently not permitted to borrow under
the revolving working capital facility (see note 13(e)).

For additional information regarding the Liberty credit agreement, the
default under the Liberty credit agreement, and related issues and concerns, see
note 13(e). 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, was directly owned by an 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 entity (see note 2). Three series of
tax-exempt secured revenue bonds relating to the Seward project were issued in
December 2001 and April 2002 by the Pennsylvania Economic Development Financing
Authority (PEDFA), for a total of $300 million outstanding as of January 1,
2003. In September 2003, an additional $100 million in tax-exempt secured
revenue bonds relating to the Seward project were issued by PEDFA, for a total
of $400 million outstanding as of September 30, 2003. Of the net proceeds from
the September 2003 issuance, $95 million was used to pay down borrowings under
our senior secured revolver. The Seward project bonds mature in December 2036.
The bonds bear interest, which is payable monthly, at a floating rate determined
each week . As of September 30, 2003, the bonds bore interest of 1.15%. The
bonds are non-recourse to Reliant Resources; however, letters of credit totaling
$407 million, with an expiration date of February 2007, have been issued under
our $2.1 billion senior secured revolver to support the bonds. Upon an event of
default under our March 2003 credit facilities, the banks issuing the letters of
credit have the right to cause the trustee to accelerate the bonds and draw on
the letters of credit.

REMA Term Loans. Reliant Energy Mid-Atlantic Power Holdings, LLC and
its subsidiaries' (REMA) is obligated to provide credit support for its lease
obligations, in the form of letters of credit or cash resulting from draws on
the letters of credit, 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 12 months under the related lease.
REMA's lease obligations are currently supported by the cash proceeds resulting
from the draw in August 2003 on three separate letters of credit supporting each
of its lease obligations. The draw on the letters of credit did not constitute a
default under any of REMA's obligations and constituted the making of term loans
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. REMA's subsidiaries guarantee REMA's obligations
under the leases and the term loans. The term loans are non-recourse to Reliant
Resources. The principal amount of the term loans is $42 million and is payable
in six equal semi-annual installments beginning on January 2, 2004, the next
lease payment date. Interest on the term loans is payable at the rate of the
London Inter-Bank Offered Rate (LIBOR) plus 3%.

Financing Costs. Through September 30, 2003, we have incurred
approximately $243 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 $207 million and directly expensed $36 million (of
which $12 million was expensed in the fourth quarter of 2002 and $24 million was
expensed during the 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
senior secured term loans 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 September 30, 2003, we had $68 million and $230 million,
respectively, of net deferred financing costs classified in other long-term
assets in our consolidated balance sheets.

(b) INTEREST RATE DERIVATIVE INSTRUMENTS AND WARRANTS.

As discussed above in (a), we have outstanding with the lenders
14,104,610 warrants to acquire shares of our common stock. We determined the
fair value of the warrants originally issued of $15 million using a binomial
model, created by independent consultants. The value was recorded as a discount
to debt and an increase to additional paid-in capital. The debt discount is
amortized to interest expense using the effective interest method over the life
of the related debt. For the three and nine months ended September 30, 2003, we
amortized $3 million and $5 million, respectively, to interest expense and the
unamortized balance was $10 million as of September 30, 2003.

In connection with the Orion Power acquisition, the existing interest
rate swaps for the Orion MidWest credit agreement and the Orion NY credit
agreement were bifurcated into a debt component and a derivative component. The

18

fair values of the debt components, approximately $59 million for the Orion
MidWest credit agreement and $31 million for the Orion NY credit agreement, were
based on our incremental borrowing rates at the acquisition date for similar
types of borrowing arrangements. The value of the debt component is amortized to
interest expense as interest rate swap payments are made. See note 8 for
information regarding our derivative financial instruments.

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 $750 million as of December 31, 2002 and September 30, 2003,
respectively, that hedge the floating interest rate risk associated with
floating rate long-term debt. As of September 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 September 30, 2003, the unamortized balance of such
loss was $38 million (pre-tax).

During January 2003, we purchased three-month LIBOR interest rate caps
for $29 million to hedge our 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). The unrealized net loss on these derivative instruments
previously reported in other comprehensive loss of $15 million (pre-tax) through
September 30, 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. During the nine months ended September 30,
2003, we recorded $8 million in interest expense due to unrealized losses in
fair value of the interest rate caps.

(11) STOCKHOLDERS' EQUITY

(a) TREASURY STOCK ISSUANCES AND TRANSFERS.

The following table describes the changes in the number of shares of
our treasury stock for the indicated periods:

19

(12) EARNINGS PER SHARE

The following table presents our basic and diluted weighted average
shares outstanding:

For the three and nine months ended September 30, 2002, the computation
of diluted EPS excludes purchase options for 20,008,790 and 14,581,582 shares of
common stock that have an exercise price (ranging from $6.20 to $34.03 per share
and ranging from $10.29 to $34.03 per share, respectively) greater than the per
share average market price ($5.21 per share and $10.23 per share, respectively)
for the respective periods and would thus be anti-dilutive if exercised.

For the three and nine months ended September 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 in the following amounts for the indicated periods:

- ----------

(1) If we had recorded income from continuing operations for the three and nine
months ended September 30, 2003, for purposes of calculating diluted EPS,
we would have increased our income from continuing operations by $2 million
for the three and nine months ended September 30, 2003, as it relates to
the assumed conversions for our convertible senior subordinated notes.

The incremental shares from assumed conversions exclude purchase options
for 17,396,995 and 17,435,628 shares of common stock that have an exercise price
(ranging from $5.28 to $34.03 per share) greater than or equal to the average
market price ($5.11 per share and $4.94 per share, respectively) for the
respective periods and would thus be anti-dilutive if exercised.

(13) COMMITMENTS AND CONTINGENCIES

(a) LEGAL AND ENVIRONMENTAL MATTERS.

We are involved in a number of legal, environmental and other
proceedings before courts and governmental agencies. In addition, we (and
certain of our current and former employees) are also subject to ongoing
investigations by various governmental agencies, including investigations into
possible criminal law violations.

As noted under "Shareholder Class Actions" below, we have assumed,
pursuant to our indemnity agreement with CenterPoint, the defense and related
indemnity obligations in numerous legal claims and proceedings relating to (a)
the

20

conduct of our business and operations prior to the date of Distribution and (b)
alleged material misrepresentations in the registration statement relating to
our IPO.

Although we cannot at this time predict the ultimate outcome of a
number of these lawsuits, proceedings and investigations, many of the matters
described in this note involve substantial claim amounts which, in the event of
an adverse judgment, could have a material adverse effect on our financial
condition, results of operations and cash flows.

Legal Matters.

Western States Class Actions. Certain operating subsidiaries within the
wholesale energy segment, as well as certain former officers, have been named,
along with a number of other energy and trading companies active in the
California market, as defendants in a number of class action lawsuits in
California. In general, the plaintiffs allege that our operating subsidiaries
conspired to increase the price of wholesale electricity in California from 2000
to 2001 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.

These lawsuits can generally be segregated into three groups based on
their pre-trial status:

o 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.

o 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 various United States District Courts, later consolidated
and transferred to the United States District Court for the
Southern District of California. On May 20, 2003, the court
denied the plaintiffs' motion to remand these cases back to
state court. On August 28, 2003, the court granted the
defendants motion to dismiss all eight cases on the ground
that the plaintiffs' claims were barred by federal preemption
and the filed rate doctrine. The plaintiffs have appealed the
District Court's rulings to the United States Court of Appeals
for the Ninth Circuit.

o The following two lawsuits constitute the third group:

o An operating company of our wholesale energy segment
and a subsidiary of CenterPoint are parties to a
multi-state class action lawsuit file on May 1, 2003
in the Superior Court of the State of California, San
Diego County. Pursuant to our indemnity agreement
with CenterPoint, we have assumed the defense and
related indemnity obligations arising from the claims
against CenterPoint. 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 western United States. 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. In May 2003, we
removed the case to the Federal Court for the
Southern District of California.

o On November 20, 2002, the California Lieutenant
Governor filed a taxpayer representative lawsuit
against several of our wholesale energy segment
operating companies, along with many other
generating, trading and marketing companies in the
Superior Court of the State of California, Los
Angeles County on behalf of purchasers of gas and
power in California. The plaintiffs allege that

21

defendants manipulated the price 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. In
July 2003, the presiding judge ruled 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. The judge, however, permitted the
plaintiffs to replead their case on alternate grounds
and the plaintiffs have done so. The matter is still
under review by the court.

Snohomish County PUD Action. On July 15, 2002, the Snohomish County
Public Utility District (PUD) filed a lawsuit on behalf of itself and its
customer-owners against one of our wholesale energy segment operating companies
and several other energy and trading companies in the United States District
Court for the Central District of California. The lawsuit was later transferred
to the Unites States District Court for the Southern District of California. The
plaintiffs allege that the defendants manipulated the price of electricity paid
by the utility for its customers in violation of California's antitrust and
unfair and unlawful business practices laws. In January 2003, the court granted
the defendants' motion to dismiss the lawsuit on the grounds that the
plaintiffs' claims are barred by federal preemption and the filed rate doctrine.
The plaintiffs have appealed to the United States Court of Appeals for the Ninth
Circuit.

Natural Gas Class Actions. On April 16, 2003, a class action lawsuit
was filed against us, one of our employees, and a subsidiary of CenterPoint in
the Superior Court of the State of California, Los Angeles County. On May 9,
2003, another class action lawsuit was filed against one of our wholesale energy
segment operating companies and a subsidiary of CenterPoint in the Superior
Court for the State of California, San Diego County. Pursuant to our indemnity
agreement with CenterPoint, we have assumed the defense and related indemnity
obligations arising from the claims against it. In both suits, 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 to separate federal district courts. The plaintiffs
in both cases are seeking to remand the cases back to state court.

California Attorney General Actions. On March 11, 2002, the California
Attorney General filed a lawsuit against Reliant Resources, a subsidiary of
CenterPoint and several of our wholesale energy segment operating companies 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 Federal
Energy Regulatory Commission (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 two of our wholesale energy segment operating companies with the FERC.
The complaint alleges that the operating companies, as a seller with
market-based rates, violated our tariffs by not filing with the FERC
transaction-specific information about all of our sales and purchases at
market-based rates. The California Attorney General argued that, as a result,
all past sales should be subject to a refund if they are found to be above just
and reasonable levels. In May 2002, the FERC issued an order that denied the
complaint in most respects and required only that the operating companies 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 Reliant Resources, a subsidiary of CenterPoint and several of our
wholesale energy segment operating companies 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 filed rate doctrine. The California Attorney General
has

22

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 Reliant Resources,
a subsidiary of CenterPoint and several of our wholesale energy segment
operating companies 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.

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 one of our wholesale energy segment
operating companies and several other energy generation and trading companies in
the First Judicial District Court of Montana, County of Lewis and Clark. The
plaintiffs allege that, along with that of other defendants, our operating
companies 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. In July 2003, one of the other defendants
removed the case to federal court in Montana. The case has been conditionally
transferred to the Southern District of California, but the plaintiffs have
objected and the objection has not been heard.

Sierra Pacific Resources and Nevada Power Company. 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 11, 2003,
the City of Los Angeles filed suit against Reliant Resources, one of our
employees, CenterPoint and one of its subsidiaries and one of our wholesale
energy segment operating companies in the United States District Court for the
Central District of California. Pursuant to our indemnity agreement with
CenterPoint, we have assumed the defense and related indemnity obligations
arising from the claims against it and its subsidiaries. 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. The lawsuit also seeks a
determination that an extension of the contract with LADWP was invalid in that
required municipal approvals for the extension were allegedly not obtained. The
defendants filed motions to dismiss, which have not been heard by the court.

Natural Gas Futures Complaints. On August 18, 2003, Cornerstone Propane
Partners, L.P. filed a class action lawsuit against one of our wholesale energy
segment operating companies, a subsidiary of CenterPoint and several other
traders and marketers in the United States District Court for the Southern
District of New York. On October 1, 2003, Roberto Gracey filed a class action
lawsuit against one of our wholesale energy segment operating companies, a
subsidiary of CenterPoint and a number of other energy trading and marketing
firms in the United States District Court for the Southern District of New York.
Pursuant to our indemnity agreement with CenterPoint, we have assumed the
defense and related indemnity obligations arising from the claims against its
subsidiary in both cases. The plaintiffs in both cases allege that the
defendants manipulated the price of natural gas futures traded on the New York
Mercantile Exchange in violation of the Commodity Exchange Act, and seek
unspecified damages on behalf of themselves and the respective putative class
members.

FERC Complaints. In June 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 one of our
wholesale energy segment operating companies that have since been terminated.
Also, in June 2003, the FERC denied a similar complaint brought by PacifiCorp
Company, which sought to challenge two 90-day contracts with us. In July 2003,
PacifiCorp Company filed for rehearing of the FERC's June 28, 2002 order and
also filed an appeal in the United

23

States Court of Appeals for the Ninth Circuit 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. PacifiCorp requested that its appeal
be abated pending action on its request for rehearing and the FERC has filed a
motion to dismiss the appeal as premature.

Texas Commercial Energy. On July 7, 2003, Texas Commercial Energy, LLP
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.
We filed a motion to dismiss the lawsuit. The Court has not yet ruled on the
motion to dismiss.

Trading and Marketing Proceedings and Investigations. In 2003, we have
been a party to a number of proceedings and investigations relating to our past
trading and marketing activities, including our round trip trades and certain
structured transactions. In certain cases, as described below, we have been able
to reach settlements of these investigations. We intend to continue to evaluate
and pursue possible ways of resolving through settlement the various
investigations, lawsuits and regulatory proceedings pending against us and our
subsidiaries. However, we are unable at this time to predict whether efforts to
achieve additional settlements will be successful.

Settlement of FERC Investigation of Western Market Issues. In October
2003, the FERC issued an order approving an agreement with certain subsidiaries
in our wholesale energy segment to settle inquiries, investigations, and
proceedings instituted by the FERC in connection with the FERC's ongoing review
of western energy markets. The settlement, which did not address the pending
FERC refund proceeding that is described below, resolved, among other matters,
the following:

o the show cause proceeding instituted in March 2003 regarding
certain trades that had been conducted with BP Energy; and

o an investigation being conducted by the FERC into allegations
of anomalous bidding behavior; and

o an investigation being conducted by the FERC into allegations
of physical withholding of power.

The settlement generally provides that:

o all proceeds under the settlement, which could total $50
million, will be paid into a fund established at the United
States Treasury for the benefit of California and western
market electricity consumers;

o we make three cash settlement payments, totaling $25 million.
In October 2003, we paid $15 million into the fund described
above; additional payments of $5 million each shall be made in
September 2005 and 2006;

o we offer capacity from a portion (totaling 824 MW) of our
generation portfolio in California to the market for one-year
terms for delivery commencing in 2004, 2005, and 2006 on a
unit-contingent, gas-tolling basis; we will pay the
difference, up to $25 million, between the collected auction
revenues and our projected cash costs to generate the power
into the fund described above; the requirement to offer this
capacity to the market ceases at the earlier of three years,
or the point in time when projected auction revenues less our
cost to generate power reach $25 million; and

o for a period of 12 months following the effective date of the
settlement, our sales in the western power markets will be
subject to review, and we will report sales data to the FERC
on a transaction-by-transaction basis; we have also made other
commitments in the settlement regarding providing information
to the FERC upon request.

The offer of capacity for delivery commencing in 2004 has been completed. No
bids above the minimum threshold were received. Given that no bids were received
in the auction process, the decision was made to mothball these units, which
aggregate 824 MW, through March 2005, at a minimum, pending results of the
auction process for the 12-month period beginning April 1, 2005.

Under the terms of the settlement, we retain the ability to make sales
of power at market-based rates. The FERC

24

also found no reason to investigate us further with respect to physical
withholding of power. In addition, the FERC addressed in the settlement the
issues surrounding our trading of natural gas at the Topock, Arizona delivery
point that had been raised in a March 2002 report by the FERC staff. The FERC
found that our trading activities did not violate either the Natural Gas Act or
any FERC regulations, that there was no evidence of any intent by our trader or
us to manipulate the price of natural gas and that as a result, no remedy was
necessary.

During the three months ended September 30, 2003, we recognized a $37
million pre-tax loss for the settlement based on (a) the present value ($24
million) of the cash settlement payments ($25 million) and (b) the fair value of
our obligation to offer capacity from our power generation portfolio ($13
million) during 2005 and 2006, based on an option valuation model. The amount of
the liability ascribed to each auction period will be offset against the
payments required to be made to the FERC, if any, resulting from contracts
entered into as a result of such auction. If there are no contracts that result
from an auction, the associated liability for that period will be reversed in
the period that the auction occurs.

In a separate FERC proceeding initiated to determine whether various
sellers engaged in so-called "gaming" activity, we have entered into a
settlement with the FERC trial staff to resolve all allegations against us for
the payment of $0.84 million related to allegations of "double-selling" of
ancillary services. This settlement is pending before an administrative law
judge, who will decide whether the settlement should now be considered by the
FERC. The payment of $0.84 million will be an offset against any amount
determined to be owed by us with respect to allegations of double-selling of
ancillary services made by the Cal ISO in its Tariff Amendment No. 51
proceedings, described below.

Pending Claims for Double Selling Ancillary Services. In July 2003, the
Cal ISO filed an amendment to its Tariff Amendment No. 51 proposing, among other
things, to rescind payments made to us from 1998 to 2001, for ancillary services
that the Cal ISO claims we did not provide. The Cal ISO presented us with
information detailing approximately $11 million of ancillary services payments
for that period that it proposes to rescind. We have protested this proposal,
which is pending at the FERC.

Settlement of FERC Price Investigation. 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
California Power Exchange (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. The June
2000 incident continues to be the subject of investigation by other agencies.

Settlement of SEC Investigation. 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. 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 may be continuing to investigate certain of our former employees.

Pending Investigations by the US Attorney and CFTC. 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 the FERC in January 2003 described
above.

We have received subpoenas and informal requests for information from
the United States Attorneys for the Southern District of New York, the Southern
District of Texas and the Northern District of California for documents,
interviews and other information pertaining to the round trip trades, price
reporting and alleged price manipulation. We have produced information to each
of the United States Attorneys' offices. In response to July 24, 2003 subpoenas
from the United States Attorney for the Northern District of California, a
number of current and former employees have given interviews to the United
States Attorney for the Northern District of California or testified before the
Grand Jury investigating allegations of electricity price manipulation. In
October 2003, we received a request for information from the United States
Attorney for the Southern District of Texas regarding certain price reporting
matters. These investigations could result in civil or criminal actions against
us and our current or former employees.

25

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 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.

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.

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 in August 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
Distribution 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. In
March 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. In response, 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

26

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 to the employee benefit plans. 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 August 12, 2003, the shareholder plaintiff filed an amended petition, which
added allegations that the defendants caused us to withhold power from the
California energy market in June 2000, and that defendants were improperly given
shares in connection with our IPO. A special litigation committee of our board
of directors is currently investigating the plaintiff's allegations. In response
to the amended petition, we filed a motion to dismiss on September 8, 2003. A
hearing was held on these matters on October 3, 2003. At the hearing, the court
stayed the action to allow the special litigation committee to complete its
investigation. The court has deferred ruling on the motion to dismiss.

On October 25, 2002, a derivative lawsuit was filed against the
directors and officers of CenterPoint. The lawsuit was filed in the United
States District Court for the Southern District of Texas, Houston Division. The
lawsuit alleges breach of fiduciary duty, waste of corporate assets, abuse of
control and gross mismanagement by the defendants causing CenterPoint to
overstate the revenues through round trip and structured transactions and breach
of fiduciary duty in connection with the Distribution and our IPO. The lawsuit
sought 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. On
March 13, 2003, the Court dismissed this derivative lawsuit without prejudice
because the shareholder plaintiff had not submitted a demand to CenterPoint's
board of directors as required by Texas law. On March 28, 2003, the CenterPoint
board of directors received a demand letter making the same allegations as the
dismissed lawsuit and demanding that CenterPoint file an action against certain
directors and officers. A special litigation committee appointed by the board of
directors of CenterPoint investigated similar allegations made in a June 28,
2002 demand letter from another stockholder of CenterPoint. On June 18, 2003,
CenterPoint's board of directors determined, by way of a resolution, that the
actions proposed in the two demand letters are not in the best interests of
CenterPoint. As of yet, neither of the shareholders who wrote the demand letters
has filed a new derivative lawsuit. Therefore, there are no derivative lawsuits
currently pending against CenterPoint for which we have assumed defense pursuant
to our indemnity agreement with CenterPoint.

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.

In early 2002, we commenced an action in the United States District
Court for the Southern District of Texas (District Court) to recover from Enron
Canada Corp. (Enron Canada), 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 various Enron subsidiaries and our applicable
subsidiaries. In March 2002, the District Court dismissed our claim and we
appealed the decision to the United States Court of Appeals for the Fifth
Circuit (the Fifth Circuit). In January 2003, Enron filed an adversary action in
the Bankruptcy Court for the Southern District of New York (Bankruptcy Court)
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 assumed by the District Court in the Enron case.

In October 2003, the Fifth Circuit reversed the District Court's
dismissal of our action against Enron Canada, and remanded the case back to the
District Court for further proceedings. In other proceedings initiated by Enron
in the Bankruptcy Court, Enron is alleging that netting agreements, such as the
one it signed with us, are unenforceable. This contention was not at issue in
our appeal recently decided by the Fifth Circuit.

27

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 September 30, 2002 and 2003, $10 million gain and
$3 million gain, respectively, was reclassified into earnings related to these
cash flow hedges. During the nine months ended September 30, 2002 and 2003, $36
million gain and $3 million loss, respectively, was reclassified into earnings
related to these cash flow hedges.

Environmental Matters.

REMA Ash Disposal Site Closures and Site Contaminations. REMA is
responsible for environmental costs related to (a) the closure of six ash
disposal sites and (b) site contamination investigations and remediation
requirements of four of its generation facilities. Based on our evaluations with
assistance from third-party consultants and engineers, we have recorded the
estimated aggregate costs associated with these environmental liabilities of $26
million, of which we expect to spend $12 million over the next five years.

Orion Power Environmental Contingencies. Orion Power is liable under
the terms of a consent order issued in 2000 with the New York State Department
of Environmental Conservation (NYSDEC) for past releases of petroleum and other
substances at two of its generation facilities. Based on our evaluations with
assistance from third-party consultants and engineers, we have developed
remediation plans for both facilities. As of September 30, 2003, we have
recorded the estimated liability for the remediation costs of $7 million, which
we expect to pay out through 2006.

Under a separate consent order issued by the NYSDEC in 2000, Orion
Power is required to evaluate certain technical changes to modify the intake
cooling system of one of its plants. Orion Power and the NYSDEC will discuss the
technical changes to be implemented. Depending on the outcome of these
discussions, including the form of technology ultimately selected, we estimate
that capital expenditures necessary to comply with the order could meet or
exceed $65 million. We expect to begin construction on a portion of the cooling
water intake in 2004.

Orion Power is responsible for environmental liabilities associated
with the future closure of three ash disposal sites in Pennsylvania. As of
September 30, 2003, the total estimated liability determined by management with
assistance from third-party engineers and recorded by Orion Power for these
disposal sites was $11 million, of which $1 million is to be paid over the next
five years.

In April 2003, the Group Against Smog and Pollution (GASP), a private
citizens organization, notified the Allegheny County Health Department (ACHD)
and Pennsylvania Department of Environmental Protection (PDEP) of GASP's intent
to initiate an action under the citizens' suit provisions of the state and
federal clean air laws to compel Orion Power to comply with ACHD air quality
regulations at one of its plants. Under applicable PDEP environmental
regulations, potential penalties in an action for past violations could exceed
$100,000. We are currently in discussions with GASP in an effort to resolve the
issue, but the outcome cannot be predicted at this time.

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 from the EPA a copy of all correspondence
relating to the EPA's request for information for one of the six stations, which
request the EPA has granted. We have recently signed a confidentiality agreement
with NJDEP relative to the information they will receive from the EPA.

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 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.

(b) 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

28

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 early 2001.

Due to the disparity between wholesale and retail rates, the credit
ratings of PG&E and SCE fell below investment grade and, in April 2001, PG&E
filed for protection under the bankruptcy laws. Because of insufficient credit
standing, from January 17, 2001 through June 30, 2003, PG&E and SCE discontinued
purchasing power from third-party suppliers through the Cal ISO to cover their
customers' requirements that could not be served by their own sources of supply
(net short load). Pursuant to emergency legislation, the CDWR 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 that served the net short load requirements of PG&E and SCE. In May
2002, the FERC issued an order stating that we and other wholesale suppliers
should receive interest payments on past due amounts owed by the Cal ISO and the
CDWR. As a result, we recorded $5 million and $10 million of net interest
receivable during 2002 and for the nine months ended September 30, 2003,
respectively. 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 continuing
proceedings at the FERC relating 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 in July
2001 in the Superior Court of the State of California for Los Angeles County, to
recover the market value of forward contracts seized by the State of California
in violation of the Federal Power Act. The actions of the State of California
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.

The following table presents our receivables, including interest, due
from 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 September 30, 2003 as of the indicated dates:

California Credit Provision. 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, resulting in a pre-tax
credit provision of $68 million as of December 31, 2001. During 2002, we
reversed $62 million ($33 million during the three months ended March 31, 2002,
$5 million during the three months ended June 30, 2002, $6 million during the
three months ended September 30, 2002 and $18 million during the three months
ended December 31, 2002) of this provision resulting in a $6 million provision
as of December 31, 2002. During the nine months ended September 30, 2003, we
recorded additional credit provisions of $13 million ($12 million during the
three months ended March 31, 2003 and $1 million during the three months ended
June 30, 2003) due to the reversal of refund provisions discussed below. As of
September 30, 2003, we had a remaining pre-tax credit provision of $19 million
against these receivable balances. We will continue to assess the collectability
of these receivables based on further developments in the FERC refund
proceedings.

FERC Refund Proceedings. We are a party to a refund proceeding
initiated by the FERC in 2001 regarding wholesale electricity prices charged by
our wholesale energy segment in California from October 2, 2000 through June 20,
2001.

Based on the refund methodology adopted by the FERC, we currently
estimate our refund obligation in these proceedings to be between approximately
$103 million and $231 million. We base this estimate on a number of assumptions:

29

o the amounts charged by us for wholesale electricity sales in California
during the refund period as computed by the Cal ISO; and

o the refund methodology adopted by the FERC in July 2001, as modified in
March 2003 and October 2003 (a) to use a "proxy" gas price based on
producing area daily price indices plus posted transportation costs
during the period in question and (b) to permit a reduction in refund
liability if actual gas costs during the refund period exceeded allowed
gas costs under the proxy gas price used in the FERC's refund formula.

During 2001, we established a $15 million reserve for potential refund
obligations. During 2002, we recognized an additional reserve for potential
refund obligations in the amount of $176 million ($34 million during the three
months ended June 30, 2002, $21 million during the three months ended September
30, 2002 and $121 million during the three months ended December 31, 2002)
resulting in a reserve of $191 million as of December 31, 2002. During the nine
months ended September 30, 2003, we reversed $88 million ($87 million during the
three months ended March 31, 2003 and $1 million during the three months ended
June 30, 2003) of previously recorded refund provisions due to the refund
methodology adopted by the FERC and additional clarification and other
information received from the FERC. As of September 30, 2003, our reserve for
refunds related to energy sales in California was $103 million.

It is our current expectation that the amount of refunds we ultimately
are determined to owe will be offset against our receivables for energy sales in
California.

Interest Calculation. During the three months ended September 30, 2003,
we did not record any net interest income. During the nine months ended
September 30, 2003, we recorded net interest income of $10 million. We estimated
net interest income based on:

o the December 2002 findings of the presiding administrative law
judge in the FERC refund proceeding, described above;

o the lowest range in our estimated potential refund;

o the receivable balance outstanding; and

o the quarterly interest rates for the applicable time period as
designated by the FERC.

(c) PAYMENT TO CENTERPOINT IN 2004.

We will be required to make a payment to CenterPoint in 2004 as
required by the Texas electric restructuring law, unless on or prior to January
1, 2004, 40% or more of the amount of electric power that was consumed in 2000
by residential or small commercial customers, as applicable, within
CenterPoint's Houston service territory is being provided by retail electric
providers other than us. This amount will be computed by multiplying $150 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 in the range of $170 million to $180
million (pre-tax), with a most probable estimate of $175 million to CenterPoint
related to our residential customers only. 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 September
30, 2003. In the future, we will revise our estimates of this payment as
additional information becomes available about the market share that will be
served by us and other retail electric providers on January 1, 2004 in the
Houston area and other areas of Texas.

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. In
similar petitions already filed, the PUCT has requested the ERCOT Independent
System Operator (ERCOT ISO) verify the 40% test. In all cases the ERCOT ISO
determined the percentage lost was less than the petitioner's filing and in one
case found the loss was less than 40% resulting in the PUCT recommending
rejection of the petition and subsequent withdrawal by the company. In the
remaining cases, parties have intervened contesting the findings, resulting in
the final opinions being issued by the PUCT beyond the thirty days outlined in
the statute. While at this time we believe we will ultimately prevail, 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.

30

(d) GUARANTEES.

We have guaranteed, in the event CenterPoint becomes insolvent, certain
non-qualified benefits of CenterPoint's and its subsidiaries' existing retirees
at the date of Distribution. The estimated maximum potential amount of future
payments under this guarantee is $56 million as of September 30, 2003. There are
no assets held as collateral. There is no liability recorded on our consolidated
balance sheet as of September 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, service 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 certain
specified liabilities. In the case of commodity purchase and sale agreements,
generally damages are limited through liquidated damages clauses whereby the
parties agree to establish damages as the costs of covering any breached
performance obligations. In the case of debt agreements, we generally indemnify
against liabilities that arise from the preparation, entry into, administration
or enforcement of the agreement. Under 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.

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

LEP owns a 530 MW combined cycle gas fired power generation facility
(the Liberty generating station). Liberty financed substantially all of the
construction costs of the Liberty generating station through borrowings under a
credit agreement of which $262 million is outstanding as of September 30, 2003.
Borrowings under the Liberty credit agreement, which are non-recourse to Reliant
Resources and its affiliates (other than LEP and Liberty), are secured by
pledges of the assets of the Liberty generating station and of the ownership
interests in LEP. The pledge includes a pledge of LEP's rights under a
now-terminated long-term tolling agreement. The tolling agreement formerly
provided for the purchase and sale of all of the electric energy, capacity and
ancillary services of the Liberty generating station.

In July 2003, the counterparty under the tolling agreement, NEGT Energy
Trading - Power, L.P. (formerly known as PG&E Energy Trading-Power, L.P.) (ET
Power), filed for reorganization under Chapter 11 of the United States
Bankruptcy Code. In August 2003, the federal bankruptcy court issued an order
rejecting the tolling agreement at the request of ET Power, which had the effect
of terminating it.

The bankruptcy filing of ET Power and National Energy & Gas
Transmission, Inc. (formerly known as PG&E National Energy Group, Inc.) (NEGT),
the parent corporation of ET Power and a guarantor of ET Power's obligations
under the tolling agreement, and the related termination of the tolling
agreement have had, among other things, the following consequences:

o the bankruptcy filings constitute an event of default under
the Liberty credit agreement;

o under the terms of the Liberty credit agreement, Liberty's
lenders are currently entitled to control disbursement of
funds by Liberty, accelerate the maturity date of the debt of
the Liberty credit agreement and/or foreclose upon the
lenders' security interests in LEP's assets;

o as a result of the termination of the tolling agreement, and
in light of current market conditions, LEP does not expect to
have sufficient cash flow to pay all of its expenses and to
post the collateral required to buy fuel or in respect of the
gas transportation agreements, and, at the same time, meet
debt service obligations; Liberty received a temporary
deferral until January 2004 from its lenders for the quarterly
principal and interest installment that was due in October
2003 which aggregated $7 million; however, that temporary
deferral does not extend to future payments with the next
installment being due January 2004; and

o Liberty is considering a variety of options, including
permitting its lenders to exercise their pledges and other
security interests to assume ownership of the Liberty
generating station or negotiating a possible restructuring of
the terms of the Liberty credit agreement or filing for
reorganization under the bankruptcy laws.

31

An event of default under the Liberty credit agreement does not
constitute an event of default under any other debt agreements of Reliant
Resources or its affiliates. Likewise, a bankruptcy or reorganization of Liberty
would not constitute an event of default under the debt agreements of Reliant
Resources or its affiliates. As of November 1, 2003, the lenders under the
Liberty credit agreement have not exercised their default remedies with the
exception of assuming control of Liberty's disbursement of funds. However, there
can be no assurance that the lenders will continue to refrain from exercising
such rights. Also, as of November 1, 2003, the lenders have allowed Liberty to
continue to pay all operating costs of Liberty, including reimbursement to
Reliant Resources and its affiliates for certain out-of-pocket costs related to
Liberty.

In July 2003, LEP demanded that ET Power pay it a termination fee in
connection with the rejected tolling agreement in the amount of $177 million.
LEP has also demanded that ET Power pay its pre-petition tolling fees of
approximately $5 million. In addition, LEP submitted a demand for payment by Gas
Transmission Northwest Corporation (formerly known as PG&E Gas Transmission,
Northwest Corporation) (GTN), a guarantor of ET Power, under its $140 million
aggregate guaranty issued with respect to the tolling agreement. GTN is a
subsidiary of NEGT and an affiliate of ET Power that did not file for protection
under the bankruptcy laws. In September 2003, LEP filed a lawsuit in Texas
federal district court against GTN seeking payment of such amounts. NEGT, GTN
and ET Power subsequently filed a claim against LEP in US bankruptcy court in
Maryland, where NEGT's and ET Power's case is pending, seeking to stay or enjoin
LEP's Texas lawsuit. ET Power also asserted a claim in the amount of $108
million as a termination payment from LEP under the tolling agreement. In its
lawsuit, ET Power also reserved the right to draw upon a $35 million letter of
credit provided by LEP to ET Power in support of its obligations under the
tolling agreement. The $35 million letter of credit is outstanding, having been
issued under the senior secured revolver of Reliant Resources. In the event of a
draw under the letter of credit by ET Power, Reliant Resources would be required
to reimburse the issuing bank for the amount of the draw and, in turn, Reliant
Resources would have an unsecured subrogation claim against LEP.

Although LEP intends to vigorously prosecute its claim and defend
against the lawsuit filed in Maryland bankruptcy court, there can be no
assurance that GTN, ET Power or NEGT would promptly pay any award or how much,
if anything, could be recovered from GTN, ET Power or NEGT. Any amounts
recovered from these entities would be applied as provided under the Liberty
credit agreement to prepay debt unless the lenders otherwise agree. A
termination payment may also result in taxable income to Reliant Resources. The
resultant possible tax liability would not be reimbursed by Liberty without
agreement from Liberty's lenders.

At December 31, 2002 and September 30, 2003, we evaluated the Liberty
generating station and the related tolling agreement for impairment. Based on
our analyses, there were no impairments.

If, however, the lenders foreclose on LEP and/or the Liberty generating
station, 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 to LEP, as a result of the foreclosure. As of September 30,
2003, the combined net book value of LEP and Liberty was $358 million, excluding
the non-recourse debt obligations of $262 million.

(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
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 eligible receivables. This facility was amended in
September 2003 to include a second financial institution, to include our
accounts receivable from our large commercial, industrial and institutional
customers and to increase the facility to a maximum total of $350 million.
Pursuant to the receivables facility, we formed a qualified special purpose
entity (QSPE), as a bankruptcy remote subsidiary. The QSPE was formed for the
sole purpose of buying receivables generated by us and selling undivided
interests to the financial institutions. 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. The QSPE, in turn, sells an undivided interest in these receivables to the
participating financial institutions. 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.

32

The amount of accounts receivable included under the arrangement may
increase as certain accounts receivable become eligible, particularly from our
large commercial, industrial, and institutional customers, and result in
additional available funding. There can be no assurance that these accounts
receivable will become eligible and result in additional available funding.

The two-step transaction described in the above paragraph is accounted
for as a sale of receivables and as a result the related receivables are
excluded from our consolidated balance sheets. Costs associated with the sale of
receivables, $4 million for the three and nine months ended September 30, 2002,
primarily the loss on sale and bad debt expense, are included in other expenses
in our consolidated statements of operations. We incurred $7 million and $15
million in costs for the three and nine months ended September 30, 2003,
respectively. As of December 31, 2002 and September 30, 2003, $277 million and
$752 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 $168 million and $461 million at
December 31, 2002 and September 30, 2003, respectively, which are included in
our consolidated balance sheets. 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 September 30, 2003, the equity
investment balance was $8 million and $22 million, respectively. Texas Genco
holds a senior lien on these notes receivable, while the senior secured note
holders and the banks in our March 2003 credit facilities ratably hold a junior
lien. See note 4 for further discussion.

The amount of funding available to us under the receivables facility
fluctuates based on the amount of eligible receivables available and by the
performance of the receivables portfolio. The following table details the
maximum amount under the receivables facility and the amount of funding
outstanding as of December 31, 2002 and September 30, 2003:

Prior to their sale, the book value of the accounts receivable is
offset by the amount of the allowance for doubtful accounts and customer
security deposits. In calculating the loss on sale, an average discount rate of
5.78% is 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.

The receivables facility expires on September 28, 2004. If the
receivables facility is not renewed on its termination date, the collections
from the receivables purchased will repay the financial institutions' investment
and no new receivables will be purchased under the receivables facility.

(15) SUPPLEMENTAL GUARANTOR INFORMATION

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

The primary full and unconditional 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.

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

33

Power Holdings, LLC; Reliant Energy New Jersey Holdings, LLC; Reliant Energy
Power Generation Benelux, N.V. and Reliant Energy Europe B.V. All subsidiaries
of Orion Power Holdings, Inc. are non-guarantors.

Each of 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 MidWest, Orion Power MidWest LP, LLC, Orion
Power MidWest GP, Inc., Twelvepole Creek, LLC and Orion Capital is a separate
legal entity and has its own assets.

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

Condensed Consolidating Statements of Operations.

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

(1) These amounts relate to either (a) eliminations and adjustments 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) Based on Orion Power and its subsidiaries' annual goodwill impairment test
as of November 1, 2002, Orion Power's consolidated goodwill was impaired by
$337 million, which was recognized during the three months ended December
31, 2002. Impairments related to Orion Power have been reflected in the
non-guarantor column since Orion Power uses push-down accounting for
acquired subsidiaries. However, for continuing operations at a consolidated
level, we did not have an impairment of goodwill during 2002. The Orion
Power impairment loss was eliminated from Reliant Resources consolidated
financial statements, as goodwill was not impaired at the higher level
reporting unit, as of December 31, 2002. Based on our wholesale energy
reporting unit's goodwill impairment test as of July 2003, we recognized an
impairment of $985 million on a consolidated basis during the three months
ended September 30, 2003. Due to this impairment at the consolidated level,
we concluded that it was more likely than not that there would be
impairments at the subsidiary level for entities within the wholesale
energy reporting unit. We therefore performed an updated impairment
analysis for Orion Power and its subsidiaries as of July 2003. This test
resulted in an impairment of $585 million on an Orion Power consolidated
basis, which was recognized during the three months ended September 30,
2003 in the non-guarantor column. When combined with the $337 million
impairment recognized in 2002, Orion Power and its consolidated
subsidiaries have recorded a cumulative impairment of $922 million as of
September 30, 2003. Other than Orion Power's subsidiaries' goodwill, the
only other goodwill recorded in entities within the wholesale energy
reporting unit (other than $4 million related to REMA), totaling $177
million prior to this review, was recorded in the guarantor column and was
derived from companies for which we are not required to prepare separate
financial statements. We recognized $126 million of impairment in the
guarantor column during the three months ended September 30, 2003. This
estimate reflects the difference between the consolidated Reliant
Resources' impairment and the cumulative impairments recorded by Orion
Power and subsidiaries and is supported by management's belief that this
remaining amount of impairment is primarily associated with the wholesale
energy reporting unit's entities that are guarantors.

37

Condensed Consolidating Balance Sheets.

- -------------
(1) These amounts relate to either (a) eliminations and adjustments 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.

(16) REPORTABLE SEGMENTS

We have identified the following reportable segments: retail energy,
wholesale energy and other operations. In February 2003, we signed an agreement
to sell our European energy operations and have classified that as discontinued
operations. See note 17 for further discussion. In July 2003, we entered into a
definitive agreement to sell our Desert Basin plant operations (which was
formerly included in our wholesale energy segment) 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. Earnings (loss) before interest expense, interest income and
income taxes (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 (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 Texas 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.

41

We have made certain changes in presentation to transfer and/or
eliminate certain intrasegment and intersegment revenues and purchased power
expense for all periods beginning January 1, 2002. For the six months ended June
30, 2002 and 2003, we transferred and/or eliminated these amounts and decreased
our retail energy segment's revenues and purchased power expense by $1 million
and $290 million, respectively. For the nine months ended September 30, 2002, we
transferred and/or eliminated these amounts and decreased our retail energy
segment's revenues and purchased power expense by $31 million. For the six
months ended June 30, 2002 and for the nine months ended September 30, 2002, we
transferred certain of these amounts and decreased our wholesale energy
segment's revenues and purchased power expense by $24 million and $68 million,
respectively. These transfers and/or eliminations had no impact on our
consolidated revenues and purchased power expense for any period.

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

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

General. 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.

Purchase Price. 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 1.1656 US dollar
to the Euro, which was the exchange rate in effect on September 30, 2003, while
the December 31, 2002 balances were calculated using an exchange rate of 1.0492
US dollar to the Euro. In August 2003, we hedged our anticipated net proceeds
from the sale of our European energy operations by purchasing Euro 544 million
of foreign currency options, which expire on November 21, 2003. We intend to
further evaluate our hedging of the net proceeds of the sale transaction based
on future developments in the regulatory approval process and our assessment of
the anticipated closing date for the transaction.

The purchase price payable at closing assumes that our European energy
operations will have, on the closing date, net cash of at least $134 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 that our European energy operations will have more than Euro 115 million
of net cash at closing. 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 $128 million
(Euro 110 million) paid by NEA B.V. (NEA) after February 2003, to Reliant Energy
Power Generation Benelux B.V. (REPGB), the operating subsidiary of RE BV. 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.

Use of Cash Proceeds from Sale. 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.
This would result in net cash proceeds of

43

approximately $0.6 billion (Euro 0.5 billion). We intend to place $360 million
of the net cash proceeds in a restricted escrow account for the possible
acquisition of CenterPoint's holdings of the common stock of Texas Genco. We
intend to use the balance of the net proceeds (approximately $0.2 billion) to
prepay debt under our March 2003 credit facilities.

Status of Regulatory Approvals. The sale remains subject to regulatory
approval of the Dutch competition authority (the NMa).

In September 2003, the NMa issued an order regarding the outcome of its
first phase review of the proposed acquisition of our European energy operations
by Nuon. In its order, the NMa informed the parties that a second phase
investigation of the proposed acquisition is required in light of the
possibility of a negative impact on competition in certain segments of the Dutch
electricity market that could result from increased concentration in the
electricity production sector following the acquisition.

On September 16, 2003, the parties submitted to the NMa a "license
application" as required under the Dutch Competition Act to initiate the second
phase review. Under the Dutch regulatory system, the NMa has a maximum of 13
weeks in which to reach a decision on the license application. Assuming no
interruption in the second phase review period, the deadline for the NMa to
reach a decision on the transaction is December 16, 2003. During the second
phase review, the NMa typically undertakes a more in-depth investigation of the
impact of the proposed acquisition. The NMa can request additional information
or ask additional questions of us and Nuon. While requests or questions are
outstanding, the 13-week period is interrupted. In certain circumstances, the
NMa also has the right to initiate hearings regarding the proposed acquisition
or solicit third-party comments regarding any proposed condition to its approval
of an acquisition. Any final decision of the NMa would be subject to appeal
through the Dutch courts or, in cases of extraordinary reasons of public
interest, by application to the Minister of Economic Affairs of the Netherlands.

Together with Nuon, we are engaged in ongoing discussions with the NMa
to address the concerns identified in its order. These discussions are centered
on various proposals submitted by Nuon to the NMa regarding possible
post-closing conditions to the NMa's approval of the acquisition.

Based on our understanding of applicable regulatory precedents and the
status of the NMa's investigation, and subject to the outcome of the ongoing
discussions between the parties and the NMa, we continue to believe that NMa
approval and closing should occur prior to the end of 2003. Under the share
purchase agreement and related agreements, Nuon has agreed to use its best
efforts to obtain NMa regulatory approval, including, where required to do so,
to make or agree to any proposal or action and comply with all requirements of
the NMa, including divestitures or any other commitment, undertakings or
conditions, unless such would have a material adverse effect on Nuon or the
companies comprising our European energy operations. As defined in the share
purchase agreement, a "material adverse effect" generally means any change,
circumstance, event or effect that individually or jointly is materially adverse
to the business, assets, condition, or results of operations of Nuon, the
companies comprising our European energy operations or any of their affiliates
and their respective businesses that individually or jointly result in an
economic loss to Nuon, the companies comprising our European energy operations
or any of their affiliates equal to or in excess of an aggregate amount of one
hundred million Euros.

If a material adverse effect were deemed to exist, Nuon would be
entitled, but not obligated, to consummate the transaction on the terms provided
in the share purchase agreement. The share purchase agreement contains a
provision allowing each of the parties to terminate the proposed acquisition if
regulatory approval is not received on or prior to November 28, 2003.

While we continue to believe that the sale of our European energy
operations to Nuon will be consummated, given the uncertainties inherent in any
regulatory process, we can provide no assurance (a) that the transaction will be
approved by the NMa, (b) that such approval can be obtained in a timely manner
or (c) that the terms and conditions under which such approval are granted will
not be deemed by Nuon to result in a material adverse effect.

Extension of European Financing Terms. To address the possibility of a
delay in the consummation of the proposed sale of our European energy
operations, or a possible termination of the share purchase agreement with Nuon
due to failure to receive timely NMa approval, we have initiated discussions
with our lenders regarding extensions of the maturity dates of the credit
facilities associated with our European energy operations. As in the case of any
financing, there can be no assurances that these efforts to extend the maturity
dates will be successful.

RECE is a borrower under a Euro 600 million secured term loan facility
originally entered into in connection with the acquisition of our European
energy operations. Under its terms, the RECE facility will mature on the earlier
of (a)

44

completion of the sale to Nuon or (b) December 31, 2003. As of December 31, 2002
and September 30, 2003, $630 million (Euro 600 million) and $699 million (Euro
600 million), respectively, under this facility was outstanding and is included
in liabilities of discontinued operations in our consolidated balance sheets.
Under the RECE facility, there is no recourse to Reliant Resources.

REPGB has unsecured credit facilities that consist of (a) a Euro 150
million ($175 million) revolving credit facility and (b) a letter of credit
facility for $400 million. Under the two facilities, there is no recourse to
Reliant Resources. Upon the closing of the sale to Nuon, the REPGB credit
facilities will remain the obligations of REPGB.

The revolving credit facility matures on December 31, 2003. It contains
an option that allows REPGB to utilize up to Euro 100 million ($117 million) for
letters of credit. At December 31, 2002 and September 30, 2003, there were no
borrowings outstanding under the revolving credit facility. At December 31, 2002
and September 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 September 30, 2003, letters of credit of $355 million
and $363 million, respectively, were outstanding under the facility.

In addition, REPGB has current and long-term indebtedness, consisting
primarily of medium term notes and private loans, which mature in 2004 and 2006,
respectively, of $38 million at December 31, 2002 and $41 million at September
30, 2003. This debt is unsecured and non-recourse to Reliant Resources. Upon
closing of the sale to Nuon, this indebtedness will remain the obligation of
REPGB.

Accounting Treatment of Sale Transaction. In connection with the
anticipated sale, we recognized an estimated loss on disposition of $393 million
during the nine months ended September 30, 2003 ($384 million loss recorded
during the three months ended March 31, 2003, $44 million offset to the loss
recorded during the three months ended June 30, 2003 and $53 million loss
recorded during the three months ended September 30, 2003). The loss recognized
during the three months ended September 30, 2003, is primarily a result of
changes in our estimated loss due to refinement of the estimated loss
calculation and changes in the estimate of the tax assets and obligations to be
retained. 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 September 30, 2003 to the date of sale, (b) changes
in intercompany balances from September 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, "Accounting for the Impairment or
Disposal of Long-lived Assets" (SFAS No. 144) and accordingly, reclassified
amounts from prior periods. 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.

45

Assets and liabilities related to our European energy discontinued
operations were as follows:

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

- ---------
(1) Included in these amounts are a $53 million loss and a $393 million loss
for the three and nine months ended September 30, 2003, respectively,
related to our gain/loss on disposition.

(18) DISCONTINUED OPERATIONS - 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 Salt River
Project Agricultural Improvement and Power District (SRP) of Phoenix for $289
million. The sale closed on October 15, 2003. Desert Basin, a combined-cycle
facility that we developed, started commercial operation in 2001 and provided
all of its power to SRP under a 10-year power purchase agreement, which
terminated in connection with the sale. The Desert Basin plant was the only
operation of Reliant Energy Desert Basin, LLC, a subsidiary of Reliant
Resources. Our March 2003 credit facilities permit us to place cash proceeds
from certain asset sales in a restricted escrow account for the possible
acquisition of CenterPoint's holdings of the common stock of Texas Genco, and
the net proceeds of $285 million of the sale were placed in such an escrow
account. We intend to use the net proceeds for the possible acquisition of
CenterPoint's holdings of the common stock of Texas Genco or to prepay
indebtedness under our March 2003 credit facilities.

Our agreement to sell our Desert Basin plant resulted in Desert Basin
meeting the definition of an asset that is "held for sale" in accordance with
generally accepted accounting principles and has been reflected as such in our
interim financial statements. Accordingly, we have recognized a loss of $75
million, after-tax, on the disposition of our Desert

46

Basin plant operations during the three months ended September 30, 2003. The
loss on disposition of $83 million ($75 million after-tax), consisted of a loss
of $20 million ($12 million after-tax) on the tangible assets and liabilities
associated with our actual investment in the Desert Basin plant operations and a
loss of $63 million (pre-tax and after-tax) relating to the allocated goodwill
of our wholesale energy reporting unit. We did not allocate any goodwill to our
Desert Basin plant operations prior to July 1, 2003.

Assets and liabilities related to our Desert Basin plant discontinued
operations were as follows:

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

- ----------

(1) Included in these amounts is an $83 million loss for the three and nine
months ended September 30, 2003, related to our loss on disposition.

* * *

47

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

This "Management's Discussion and Analysis of Financial Condition and
Results of Operations" should be read in conjunction with (a) our Current Report
on Form 8-K filed on June 5, 2003 and (b) our Current Report on Form 8-K filed
on June 30, 2003.

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 the
Pennsylvania - New Jersey - Maryland (PJM) Interconnection. 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 manage the risk of our asset portfolio. We sell energy commodities to and
buy energy commodities from a variety of over-the-counter and exchange-based
markets, as well as directly to or from energy producers, distributors and
retailers, as appropriate.

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 16 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 nine months ended September 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 gas-fired generation facilities;

o the effects of market participant contraction;

o reduced liquidity in the United States power markets; and

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

We tested our wholesale energy segment's goodwill for impairment effective
July 2003 as required under SFAS No. 142 due to the disposition of our Desert
Basin plant operations. In connection with this July 2003 impairment analysis,
we recognized an impairment of $985 million (pre-tax and after-tax) relating to
our wholesale energy reporting unit. See note 7 to our interim financial
statements for a discussion of the impairment. We plan to perform our annual
goodwill impairment tests for our wholesale energy and retail energy reporting
units effective November 1, 2003. If actual results of operations are worse than
projected or our wholesale energy market outlook changes, we could have
additional impairments of goodwill and impairments of our property, plant and
equipment in future periods, which, in turn, could have a material adverse
effect on our results of operations. Additionally, our ongoing evaluation of our
wholesale energy

48

business could lead to decisions to mothball, retire or dispose of assets. Any
of these events could result in additional impairment charges related to
goodwill and property, plant and equipment.

In addition, our operations are impacted by changes in commodities other
than electric energy, in particular by changes in natural gas prices. 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 (natural
gas and fuel oil) generating assets by running the most cost-efficient fuel.
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 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. Although we cannot predict with
any certainty, we feel it is unlikely that the current PUCT rules and
regulations will materially change before the next Texas state legislative
session in 2005. If the Texas state legislature revises the statutes governing
price to beat calculations or the PUCT revised our price to beat rates in 2004
to provide for less than a full recovery of any increased costs, we could face
significant risks that cannot be quantified at this time. 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. We
expect to implement the majority of these opportunities by the end of 2003, with
the remainder over the course of 2004. We expect to achieve approximately $125
million in realized savings in 2004. We have also initiated a comprehensive
review of our wholesale energy business, strategy, portfolio and operations and
maintenance practices, which could lead to additional cost savings, both expense
and capital.

The capital constraints currently impacting our industry may require
additional future indebtedness to include terms and/or pricing that are more
restrictive or burdensome than those of our current indebtedness. This may
negatively impact our ability to operate our business and could adversely affect
our results of operations, financial condition and cash flows. As a result of
the June and July 2003 issuances of convertible senior subordinated notes and
senior secured notes (see note 10 to our interim financial statements), our
interest expense has increased substantially. In addition, as a result of the
July 2003 issuance of senior secured notes, during the three months ended
September 30, 2003, we expensed approximately $31 million of deferred financing
costs incurred in connection with the March 2003 refinancing associated with the
prepayment of indebtedness under the March 2003 credit facilities 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 $393 million during the nine months ended
September 30, 2003 ($384 million loss recorded during the three months ended
March 31, 2003, $44 million offset to the loss recorded during the three months
ended June 30, 2003 and $53 million loss recorded during the three months ended
September 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 amounts from prior
periods. For further discussion of the sale, see note 17 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 sale closed on October 15, 2003. Our agreement to
sell our

49

Desert Basin plant resulted in Desert Basin meeting the definition of an asset
that is "held for sale" in accordance with generally accepted accounting
principles and has been reflected as such in our interim financial statements.
Accordingly, we recognized a loss of $75 million, after-tax, on the disposition
of our Desert Basin plant operations during the three months ended September 30,
2003. Further, the Desert Basin plant operations assets and liabilities sold,
and their results of operations, have been reflected as discontinued operations
and prior periods have been restated to reflect this change. For further
discussion of the sale, see note 18 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 nine months ended September 30, 2002 and
2003:

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

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

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

Net Income (Loss). We reported $916 million consolidated net loss, or $3.11
loss per share, for the three months ended September 30, 2003 compared to $50
million consolidated net income, or $0.17 per diluted share, for the three
months ended September 30, 2002. The $966 million decrease from net income to
net loss was primarily due to:

o a $967 million decrease in EBIT from our wholesale energy segment due
primarily to the goodwill impairment charge of $985 million;

o a $61 million increase in interest expense to third parties; and

o a $67 million increase in loss from discontinued operations, which
includes estimated losses on dispositions of $53 million and $75
million recognized during the three months ended September 30, 2003
due to the anticipated sales of our European energy operations and our
Desert Basin plant, respectively (see notes 17 and 18 to our interim
financial statements).

These decreases were partially offset by the following:

o a $130 million increase in EBIT from our retail energy segment; and

o a $46 million increase in EBIT from our other operations segment due
primarily to a $47 million charge relating to the accounting
settlement of certain benefit obligations in the three months ended
September 30, 2002.

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

Interest Expense. We incurred $154 million of interest expense to third
parties during the three months ended September 30, 2003 compared to $93 million
in the same period of 2002. The $61 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 due to the
refinancing of debt at fixed rates for longer terms, (b) an increase in
amortization of deferred financing costs due to the refinancing and debt
issuances in March, June and July 2003, (c) a $31 million write-off of
previously deferred financing

50

costs during July 2003 as a result of issuing the senior secured notes and the
prepayment of senior secured term loans (see note 10(a) to our interim financial
statements) and (d) $10 million of interest expense (net of capitalized
interest) associated with the debt under the former construction agency
agreements, which was consolidated effective January 1, 2003 (see note 10(a) to
our interim financial statements). Included in interest expense for 2003 is $54
million of deferred financing costs amortized and/or expensed during the three
months ended September 30, 2003, which includes the $31 million discussed above.

Income Tax Expense. During the three months ended September 30, 2002, our
effective tax rate was 45.8%. Our effective tax rate for the three months ended
September 30, 2003 is not meaningful due to the goodwill impairment charge of
$985 million, which is non-deductible for income tax purposes. Our reconciling
items from the federal statutory rate of 35% to the effective tax rate totaled
$21 million for the three months ended September 30, 2002. These items primarily
related to state income taxes and to a lesser extent valuation allowances on
Canadian operating losses. Our reconciling items from the federal statutory rate
of 35% to the effective tax rate totaled $18 million, excluding the goodwill
impairment charge, for the three months ended September 30, 2003. These items
primarily related to state income taxes, tax reserves and valuation allowances
related to Canadian operating losses.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2003.

Net Income (Loss). We reported $1.4 billion consolidated net loss, or $4.70
loss per share, for the nine months ended September 30, 2003 compared to $89
million consolidated net income, or $0.30 earnings per diluted share, for the
nine months ended September 30, 2002. The $1.5 billion decrease from net income
to net loss was primarily due to:

o a $1.1 billion decrease in EBIT from our wholesale energy segment due
primarily to the goodwill impairment charge of $985 million;

o a $187 million increase in interest expense to third parties; and

o a $502 million decrease in income from discontinued operations, which
includes estimated losses on dispositions of $393 million and $75
million recognized during the nine months ended September 30, 2003 due
to the anticipated sales of our European energy operations and our
Desert Basin plant, respectively (see notes 17 and 18 to our interim
financial statements).

These changes were partially offset by the following:

o a $210 million decrease in cumulative effect of accounting changes
primarily related to the adoption of SFAS No. 142 on January 1, 2002
for our European energy operations (see notes 2 and 7 to our interim
financial statements);

o a $37 million increase in EBIT from our other operations segment due
primarily to a $47 million charge relating to the accounting
settlement of certain benefit obligations in the nine months ended
September 30, 2002; and

o a $10 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 $365 million of interest expense to third
parties during the nine months ended September 30, 2003 compared to $178 million
in the same period of 2002. The $187 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 September 30, 2002 and 2003, as
discussed above. Included in interest expense for 2003 is $70 million of
deferred financing costs amortized and/or expensed during the nine months ended
September 30, 2003. We wrote-off $31 million of previously deferred financing
costs, which is included in the $70 million discussed above.

Interest Income. We recognized interest income from third parties of $24
million for the nine months ended September 30, 2003 as compared to $14 million
for the same period in 2002. The increase is primarily due to interest income of
$10 million recorded during the nine months ended September 30, 2003, recognized
on receivables related to energy sales in California (see note 13(b) to our
interim financial statements) and excess cash invested on a short-term basis.

51

Income Tax Expense. During the nine months ended September 30, 2002, our
effective tax rate was 38.7%. Our effective tax rate for the nine months ended
September 30, 2003 is not meaningful due to the goodwill impairment charge of
$985 million, which is non-deductible for income tax purposes. Our reconciling
items from the federal statutory rate of 35% to the effective tax rate totaled
$18 million for the nine months ended September 30, 2002. These items primarily
related to state income taxes partially offset by the utilization of Canadian
net operating loss carryovers. Our reconciling items from the federal statutory
rate of 35% to the effective tax rate totaled $24 million, excluding the
goodwill impairment charge, for the nine months ended September 30, 2003. These
items primarily related to state income taxes, tax reserves, valuation
allowances related to Canadian operating losses and revisions of estimates for
taxes accrued in prior periods.

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 nine months ended September 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 (loss) 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 16 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 have identified the following reportable segments: retail energy,
wholesale energy and other operations (see note 16 to our interim financial
statements).

The following tables set forth our operating income (loss) and EBIT by
segment for the three and nine months ended September 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. 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. Despite losing market share in the Houston market, as of
September 30, 2003, our total retail customer count in Texas, as measured by
number of metered locations, had increased approximately five percent as
compared to September 30, 2002 due to customers added in markets outside of the
Houston area. 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," in Pennsylvania, we are registered as an "electric generation
supplier" and in Maryland, we are licensed as an "electric supplier." We began
to deliver electricity in New Jersey effective August 1, 2003.

Our retail energy obligations exceed the physical generation capabilities
of our seven Texas generation facilities, which have total net generating
capacity of 805 MW. As a retail energy provider, we must contract with other
generators/suppliers to supply our obligations. Sales to retail customers create
varying degrees of commodity exposures. We manage this risk through various
commodity hedging strategies including the use of energy derivatives. We also
purchase and sell electricity supply in the market as a means to manage and
optimize our energy supply portfolio. For example, we may purchase power in one
zone of Texas and subsequently resell that power and purchase power in another
zone of Texas based on changing energy supply needs. These transactions are
recorded as gross revenues and purchased power. These types of transactions are
disclosed as "revenues from resales of purchased power and other hedging
activities" and the related purchased power costs are included in "purchased
power and delivery fees." Our power supply requirements for the balance of 2003
are substantially hedged and we have hedged a significant portion of our
estimated power supply requirements for 2004. For further information regarding
our contract to purchase supply from Texas Genco, see note 4 to our interim
financial statements.

Electricity sales and services related to retail customers, which have not
yet been 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 September 30, 2003, the amount of estimated unbilled revenue
was $334 million. Problems or delays in the flow of information between the
ERCOT ISO, the transmission and distribution utility and the retail electric
providers and operational problems with our systems and processes could impact
our ability to accurately estimate the amount of electricity sales and services
not billed as of September 30, 2003.

54

The transmission and distribution utilities 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.

The ERCOT ISO is responsible for maintaining reliable operations of the
electric power supply system in the electric market operated by ERCOT (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 has been delayed on several
occasions since the opening of the market in order to address operational
problems with data management between the ERCOT ISO, the transmission and
distribution utilities and the retail electric providers. During the third
quarter of 2002, the ERCOT ISO issued true-up settlements for the pilot time
period of July 31, 2001 to December 31, 2001. True-up settlement calculations
were then temporarily suspended to allow a threshold level of consumption data
for subsequent periods from the transmission and distribution utilities to be
loaded into the ERCOT ISO's systems. True-up settlement calculations for the
period January 1, 2002 through December 31, 2002 were performed by the ERCOT ISO
during the second, third and early fourth quarters of 2003. These settlement
calculations indicate that our customers utilized greater volumes of electricity
than our records indicate. We are currently pursuing the ERCOT ISO's process for
disputing settlement calculations for that time period. True-up settlement
calculations for periods after December 31, 2002 are currently suspended while
the ERCOT ISO provides the transmission and distribution utilities and retail
electric providers with more detailed information on data in the ERCOT ISO's
systems that are being used in the settlement calculations. We are working
closely with the ERCOT ISO and other market participants to identify and resolve
discrepancies that may have impacted settlements already performed as well as
future settlements.

The ERCOT ISO fees related to resolving local congestion have increased
substantially during 2003. 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 larger than expected 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 related to 2002
and accordingly, recognized $39 million of income in our operating results
during the nine months ended September 30, 2003 related to 2002. During the
three months ended September 30, 2003, we recognized $31 million of income in
our operating results related to prior periods due to revised estimates and
assumptions. 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 as competition increases. We expect to continue to gain
residential and small commercial market share in other areas. Our continuing
efforts to seek such gains may require us to increase our spending for marketing
and advertising. We expect to continue to renew contracts with a significant
portion of our large commercial, industrial and institutional customers in the
Texas and PJM regions, and where possible, we will add new customer contracts,
attempting to increase market share when profitable opportunities exist.

55

We 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 one million British
thermal units (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.

On June 26, 2003, CenterPoint petitioned the PUCT to request 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
comply with the procedure set out in the statute for addressing the issues
raised. Subsequently, the procedural schedule was suspended. We, along with a
number of other parties, are currently engaged in settlement discussions on this
issue and other outstanding issues that CenterPoint currently has before the
PUCT. 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.

56

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

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

(1) Revenues less fuel and purchased power and delivery fees.

(2) Includes volumes/customers of the Government Land Office for whom we
provide services.

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 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 and delivery fees are recorded on a gross basis in
our results of operations. Due to the implementation of EITF

57

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. For further discussion, see note 2 to our
interim financial statements.

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

EBIT. Our retail energy segment's EBIT increased $130 million during the
three months ended September 30, 2003 compared to the same period in 2002. The
increase is primarily due to the following:

o $51 million in increased margins, as described below; and

o an $89 million accrual for payment to CenterPoint (as discussed below)
during the three months ended September 30, 2002, for which no accrual
was made in the same period during 2003.

Total Revenues. Total revenues increased $258 million during the three
months ended September 30, 2003 compared to the same period in 2002. The results
of operations are not comparable between 2002 and 2003, as discussed above. The
following table reconciles 2002 revenues on a comparable basis to 2003:

The $252 million increase in revenues from end-use customers is primarily due to
increases in the price to beat revenue rate for residential and small commercial
customers and an increase in large commercial, industrial and institutional
customers' rates that are indexed to the price of natural gas and new
fixed-price contracts that were executed at higher rates.

Our revenues from resales of purchased power and other hedging activities
decreased due to changes in our strategies for risk management, hedging and
optimizing of our electric energy supply. During 2002, we experienced greater
purchasing and selling of supply in the market due to uncertainty about the
level of price volatility and uncertainty regarding customer behavior and the
related effects on our supply requirements. This factor resulted in additional
revenues and purchased power during the three months ended September 30, 2002
compared to the same period in 2003.

Fuel and Purchased Power and Delivery Fees. Fuel and purchased power and
delivery fees increased $207 million during the three months ended September 30,
2003 compared to the same period in 2002. The results of operations are not
comparable between 2002 and 2003, as discussed above. The following table
reconciles 2002 fuel and purchased power and delivery fees on a comparable basis
to 2003:

58

The $201 million increase in fuel and purchased power and delivery fees
attributable to end-use customers is due to higher natural gas prices, which
have led to higher market prices of purchased power, and our hedging activities.

Margins. Our retail energy segment's margins increased $51 million during
the three months ended September 30, 2003 compared to the same period in 2002
primarily due to the following:

o a $100 million increase due to higher revenue rates and partially
offset by higher fuel and purchased power costs; and

o $31 million of income resulting from revised estimates for electric
sales and supply costs related to prior periods, as discussed above.

The increase was partially offset by the following:

o a $61 million variance between 2002 and 2003 due to a change in
accounting method as discussed above. In 2002, we recognized $42
million of net unrealized gains that related to volumes to be
delivered in future periods. In 2003, we realized $19 million of
margins from deliveries recognized in previous periods; and

o a $19 million increase in rates for load related fees from the ERCOT
ISO, as discussed above.

Accrual for Payment to CenterPoint. We will be required to make a payment
to CenterPoint in 2004 related to residential customers. As of September 30,
2003, our estimate for the payment is between $170 million and $180 million,
with a most probable estimate of $175 million. We accrued $89 million during the
three months ended September 30, 2002, $39 million during the three months ended
December 31, 2002 and $47 million during the three months ended March 31, 2003,
for a total accrual of $175 million. For additional information regarding this
payment, see note 13(c) to our interim financial statements.

Operation and Maintenance and Selling, General and Administrative.
Operation and maintenance expenses and selling, general and administrative
expenses did not change significantly during the three months ended September
30, 2003 compared to the same period in 2002.

Depreciation and Amortization. Depreciation and amortization expense did
not change significantly during the three months ended September 30, 2003
compared to the same period in 2002.

Other, net. Other losses increased $5 million during the three months ended
September 30, 2003 compared to the same period in 2002 due to recording losses
on sales of receivables. For additional information on our receivables facility,
see note 14 to our interim financial statements.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2003.

EBIT. Our retail energy segment's EBIT increased $7 million during the nine
months ended September 30, 2003 compared to the same period in 2002. The
increase is primarily due to the following:

o a $48 million increase in margins, as discussed below; and

o a $42 million decrease in the accrual for payment to CenterPoint (as
discussed above) recorded during the periods.

The increase was partially offset by the following:

o a $64 million increase in operation and maintenance and selling,
general and administrative expenses, as discussed below; and

o a $10 million increase in depreciation and amortization expense, as
discussed below.

Total Revenues. Total revenues increased $1.4 billion during the nine
months ended September 30, 2003 compared to the same period in 2002. The results
of operations are not comparable between 2002 and 2003, as discussed above. The
following table reconciles 2002 total revenues on a comparable basis to 2003:

59

The $731 million increase in revenues from end-use customers is due to increases
in the price to beat revenue rate for residential and small commercial
customers, an increase in large commercial, industrial and institutional
customers' rates that are indexed to the price of natural gas and new
fixed-price contracts that were executed at higher prices as well as an increase
in customers and volumes.

Our revenues from resales of purchased power and other hedging activities
decreased due to changes in our strategies for risk management, hedging and
optimizing of our electric energy supply, as discussed above.

Fuel and Purchased Power and Delivery Fees. Fuel and purchased power and
delivery fees increased $1.4 billion during the nine months ended September 30,
2003 compared to the same period in 2002. The results of operations are not
comparable between 2002 and 2003, as discussed above. The following table
reconciles 2002 fuel and purchased power and delivery fees on a comparable basis
to 2003:

The $683 million increase in fuel and purchased power and delivery fees
attributable to end-use customers is primarily due to the following:

o a $522 million increase in fuel and purchased power and delivery fees
due to higher natural gas prices, which have led to higher market
prices of purchased power, our hedging activities and increased
volumes; and

o a $161 million increase in fuel costs for our Texas generation
facilities, as units began commercial operation in June 2002.

Margins. Our retail energy segment's margins increased $48 million during
the nine months ended September 30, 2003 compared to the same period in 2002
primarily due to:

o a $138 million increase due to higher revenue rates and volumes, and
partially offset by higher fuel and purchased power costs; and

o $34 million of income resulting from revised estimates for electric
sales and supply costs related to prior periods, as discussed above.

The increase was partially offset by the following:

o a $77 million variance between 2002 and 2003 due to a change in
accounting method as discussed above. In 2002, we recognized $27
million of net unrealized gains that related to volumes to be
delivered in future periods and in 2003, we realized $50 million of
margins from deliveries recognized in previous periods; and

60

o a $47 million increase in rates for load related fees from the ERCOT
ISO, as discussed above.

Operation and Maintenance and Selling, General and Administrative.
Operation and maintenance expenses and selling, general and administrative
expenses increased $64 million during the nine months ended September 30, 2003
compared to the same period in 2002 primarily due to the following:

o a $29 million increase 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 a $23 million increase in corporate overhead charges;

o a $16 million increase in marketing costs primarily due to additional
marketing and customer acquisitions in areas outside of the Houston
market;

o a $7 million increase in allowance for customer receivables; and

o a $6 million increase in operating costs related to the startup of the
Texas generation facilities.

These increases were partially offset by a $17 million decrease in gross
receipts tax primarily due to increased revenues and an adjustment in the
accrual rate.

Depreciation and Amortization. Depreciation and amortization expense
increased $10 million during the nine months ended September 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 Texas generation facilities.

Other, net. Other losses increased $9 million during the nine months ended
September 30, 2003 compared to the same period in 2002 due to recording losses
on sales 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-Texas portfolio of electric
power generation facilities and related purchased power, 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 manage the risk of our asset portfolio. We sell
energy commodities to and buy energy commodities from a variety of
over-the-counter and exchange-based markets, as well as directly to or from
energy producers, distributors and retailers, as appropriate.

We own or lease electric power generation facilities with an aggregate net
operating generating capacity of 19,594 MW in the United States. This excludes
588 MW related to our Desert Basin plant, which was sold in October 2003, and
496 MW related to the retirement of certain units in the West and Mid-Atlantic
regions. We have 866 MW (1,063 MW, net of 197 MW to be retired upon completion
of one facility) of additional net generating capacity under construction. One
gas-fired generating facility is due to reach commercial operation in November
2003 and one waste-coal fired generating facility is due to reach commercial
operation in the second half of 2004.

On July 9, 2003, we entered into a definitive agreement to sell our Desert
Basin plant. The sale closed on October 15, 2003. See note 18 to our interim
financial statements for a discussion on the sale of the Desert Basin plant
operations and the classification as discontinued operations.

We recently retired from service two power-generating units totaling 264 MW
at our Etiwanda power plant near Rancho Cucamonga, California. Additionally, we
plan to retire a natural gas-fired steam unit and an oil-fired steam unit
totaling 225 MW at our power generating station at Sayreville, New Jersey early
in 2004. In connection with these

61

retirements, we recorded a charge of $14 million to depreciation expense during
the three months ended September 30, 2003.

Furthermore, in November 2003, given that no bids were received in the
auction process on our offer of capacity for 2004 in connection with our FERC
settlement agreement, the decision was made to mothball four units in California
through March 2005, at a minimum, pending results of the auction process for the
12-month period beginning April 1, 2005. The following units will be mothballed:
two units totaling 640 MW at our Etiwanda facility; one unit, 130 MW, at our
Mandalay facility and one unit, 54 MW, at our Ellwood facility, for a total of
824 MW. See note 13(a) to our interim financial statements for further
discussion. Additionally, it is possible that we may sell, retire, mothball or
dispose of additional assets, although to date, we have not reached a decision
to do so for any other generating assets of our wholesale energy segment. Such
plans could result in impairment losses in property, plant and equipment and
goodwill. Due to unfavorable market conditions in the wholesale power markets,
there can be no assurance that we will be successful in disposing of generating
assets at reasonable prices.

Given the downturn in the industry and downgrades of our credit ratings, in
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 liquidity 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. Other than with respect to the completion of projects already under
construction, our March 2003 credit facilities substantially restrict new
development. The restructuring of all of our associated commercial, development
and support groups resulted in $17 million of severance costs in 2002. In June
2003, we launched a review of our internal cost structure with a focus primarily
on our non-plant related expenses. See discussion above.

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 during the three months ended March 31, 2003
related to these positions. These positions have been closed. In March 2003, we
decided to exit our proprietary trading activities. See discussion above.

Liberty is currently in default under its credit facility and the
counter-party to LEP's tolling agreement (which has been rejected) at the
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 to LEP. We evaluated the Liberty
generating station and the related tolling agreement for impairment during the
third quarter of 2003 and determined that no impairment has occurred. For
information regarding issues and contingencies related to our Liberty generating
station, see note 13(e) to our interim financial statements.

We recognized an impairment of our wholesale energy reporting unit's
goodwill of $985 million during the three months ended September 30, 2003. See
note 7 to our interim financial statements for further discussion.

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The following table provides summary data, including EBIT, of our wholesale
energy segment for the three and nine months ended September 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. These amounts exclude volumes associated with our
Desert Basin plant operations, which are classified as discontinued
operations.

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

EBIT. The wholesale energy segment's EBIT decreased by $967 million during
the three months ended September 30, 2003 compared to the same period in 2002.
The decrease is primarily due to the following:

o a $985 million charge related to the impairment of our goodwill
recorded during the three months ended September 30, 2003;

o a $16 million decrease in power generation margins; and

o a $7 million decrease in trading margins.

The decrease was partially offset by the following:

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o a $28 million decrease in general, administrative and development
expenses; and

o a $15 million decrease in operation and maintenance expenses.

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, decreased by $1.6 billion during the three months ended September 30,
2003 compared to the same period in 2002 primarily due to a 43% decrease in
power sales volumes, which includes our hedging activities, and an 11% decrease
in prices for power sales.

Fuel and Cost of Gas Sold and Purchased Power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power decreased by $1.6
billion during the three months ended September 30, 2003 compared to the same
period in 2002 primarily due to decreased purchased power and a decrease in
prices of purchased power.

Trading Margins. Trading margins decreased $7 million during the three
months ended September 30, 2003 compared to the same period in 2002 primarily
due to the discontinuance of proprietary trading in March 2003. The decrease was
partially offset by the impact of positive reserve and valuation adjustments
totaling $12 million recorded during the three months ended September 30, 2003,
which related to changes in assumptions and estimates for calculating credit,
liquidity and administrative reserves and a change in the associated discount
rate.

Power Generation Margins. Our wholesale energy segment's power generation
margins decreased $16 million during the three months ended September 30, 2003
compared to the same period in 2002 primarily due to the following:

o a $37 million provision for a settlement agreement reached with the
FERC (see note 13(a) to our interim financial statements);

o a $10 million net decrease in margins in the New York region due to
increased gas prices partially offset by an increase in power prices
and capacity revenues at our New York City facilities and an increase
in generation at our hydro facilities; and

o a $5 million net decrease in power generation margins in the
Mid-Atlantic region due to the termination of a tolling contract
related to the Liberty generating facility (see note 13(e) to our
interim financial statements), partially offset by an increase in
margins resulting from our coal-fired plants at our REMA facilities
and an increase in margins associated with hedge ineffectiveness.

The decrease was partially offset by the following:

o a $15 million net increase resulting from a $21 million refund
provision for California energy sales, partially offset by a $6
million reversal of credit provisions, each recorded during the three
months ended September 30, 2002;

o a $10 million increase in margins resulting from various hedging
activities, including activities related to a terminated counterparty;

o a $7 million increase in margins in the West region due to $14 million
of mark-to-market earnings of economic hedges offset by $7 million of
hedge ineffectiveness; and

o a $5 million increase in margins associated with billings to
CenterPoint for engineering, technical and other support services
provided to Texas Genco's facilities under a support agreement entered
into in September 2002 (see note 4 to our interim financial
statements).

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment decreased $15 million during the three months ended
September 30, 2003 compared to the same period in 2002 primarily due to fewer
outages in 2003 and deferral of some maintenance projects to the fourth quarter
of 2003.

General, Administrative and Development. General, administrative and
development expenses decreased $28 million during the three months ended
September 30, 2003 compared to the same period in 2002 primarily due to the
following:

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o an $11 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;

o an $11 million decrease in our reserve for uncollectible accounts
primarily due to a reduction in outstanding receivables compared to
2002;

o an $8 million net decrease in consulting fees and legal costs; and

o a $5 million decrease in development expenses.

The decrease was partially offset by a $7 million increase in corporate overhead
allocations.

Depreciation and Amortization. Depreciation and amortization expense did
not change during the three months ended September 30, 2003 compared to same
period in 2002. The three months ended September 30, 2002 included a $37 million
equipment impairment charge related to turbines and generators.

The absence of this charge was offset by the following:

o a $21 million increase in amortization of emission allowances due to
higher average prices of allowances used;

o a $14 million increase in depreciation expense associated with the
early retirement of certain units at the Sayreville facility and
certain units at our Etiwanda facility; and

o a $5 million increase in depreciation expense associated with two
power generation facilities reaching commercial operation during the
three months ended September 30, 2003.

Income of Equity Investments. The equity income 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 increased $2
million during the three months ended September 30, 2003 compared to the same
period in 2002 primarily due to increased power prices partially offset by
increased fuel prices.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2003.

EBIT. The wholesale energy segment's EBIT decreased by $1.1 billion during
the nine months ended September 30, 2003 compared to the same period in 2002.
The decrease is primarily due to the following:

o a $985 million charge related to the impairment of our goodwill
recorded during the three months ended September 30, 2003;

o a $176 million decrease in trading margins;

o a $41 million increase in operation and maintenance expenses;

o a $22 million increase in depreciation and amortization; and

o a $12 million decrease in income of equity investments.

The decrease was partially offset by the following:

o a $71 million decrease in general, administrative and development
expenses; and

o a $45 million increase in power generation margins.

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Revenues. Our wholesale energy segment's revenues, excluding trading
margins, decreased by $910 million during the nine months ended September 30,
2003 compared to the same period in 2002 primarily due to a 17% decrease in
power sales volumes, including hedging activity, and a 4% decrease in prices for
power sales.

Fuel and Cost of Gas Sold and Purchased Power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power decreased by $955
million during the nine months ended September 30, 2003 compared to the same
period in 2002 primarily due to decreased purchased power and a decrease in
prices of purchased power.

Trading Margins. Trading margins decreased $176 million during the nine
months ended September 30, 2003 compared to the same period in 2002 primarily
due to the discontinuance of proprietary trading in March 2003 and a pre-tax
loss of approximately $80 million in connection with a financial gas spread
position during the month of February 2003, as discussed above. In addition, the
reduced market liquidity driven by the industry's restructuring contributed to
the decrease. The decrease was partially offset by the impact of positive
reserve and valuation adjustments totaling $11 million recorded during the nine
months ended September 30, 2003, as discussed above.

Power Generation Margins. Our wholesale energy segment's power generation
margins increased $45 million during the nine months ended September 30, 2003
compared to the same period in 2002 primarily due to the following:

o a $143 million change in refund provisions due to the reversal of
previously recorded refund provisions of $88 million during the nine
months ended September 30, 2003 coupled with the recognition of a
refund provision of $55 million during the nine months ended September
30, 2002 (see note 13(b) to our interim financial statements);

o a $35 million increase in power generation margins in the
Mid-Continent region primarily due to the inclusion of a full period's
results from Orion MidWest's facilities during the nine months ended
September 30, 2003 as a result of the Orion Power acquisition in
February 2002;

o a $16 million increase in margins associated with billings to
CenterPoint for engineering, technical and other support services
provided to Texas Genco's facilities under a support agreement entered
into in September 2002 (see note 4 to our interim financial
statements); and

o a $14 million increase in margins resulting from various hedging
activities, including activities related to a terminated counterparty.

The increase was partially offset by the following:

o a $57 million change in credit provisions related to energy sales in
California primarily due to the recognition of a $13 million provision
during the nine months ended September 30, 2003 resulting from the
reversal of the refund provision coupled with a $44 million reversal
in 2002 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 a $39 million decrease in margins in the New York region as a result
of increased fuel costs due to unhedged fuel positions and forward
power sales, partially offset by the inclusion of a full period's
results from Orion NY's facilities during the nine months ended
September 30, 2003 as a result of the Orion Power acquisition in
February 2002;

o a $37 million provision for a settlement agreement reached with the
FERC (see note 13(a) to our interim financial statements); and

o a $33 million decrease in margins in the West region due to (a) lower
spark spreads during the nine months ended September 30, 2003, (b)
roll off of hedging activity entered into at higher prices and (c) an
increase in losses due to hedge ineffectiveness.

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $41 million during the nine months ended
September 30, 2003 compared to the same period in 2002 primarily due to the
following:

66

o a $33 million increase in operation and maintenance expenses primarily
due to the inclusion of a full period's results from the Orion Power
facilities during the nine months ended September 30, 2003; and

o a $4 million increase in operation and maintenance expenses due to the
Liberty generating station achieving commercial operation in May 2002.

General, Administrative and Development. General, administrative and
development expenses decreased $71 million during the nine months ended
September 30, 2003 compared to the same period in 2002 primarily due to the
following:

o a $37 million reduction in development expenses, including the
write-offs of $17 million in 2002 of previously capitalized costs
related to projects that were terminated;

o a $35 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 $17 million net decrease in consulting fees and legal costs.

The decrease was partially offset by the following:

o a $17 million increase in corporate overhead allocations; and

o a $6 million increase in the provision for doubtful accounts related
to the tolling agreement at the Liberty generating station.

Depreciation and Amortization. Depreciation and amortization expense
increased by $22 million during the nine months ended September 30, 2003
compared to same period in 2002 primarily due to the following:

o a $21 million increase in depreciation expense due to the write-down
of an office building to its fair value less cost to sell and the
early retirement of certain units at the Sayreville facility and
certain units at our Etiwanda facility;

o a $30 million increase in amortization of emission allowances due to
higher average prices of allowances used;

o a $5 million increase in depreciation and amortization expense,
excluding emission allowances, due to the inclusion of a full period's
results from the Orion Power facilities during the nine months ended
September 30, 2003;

o a $5 million increase in depreciation expense associated with two
power generation facilities reaching commercial operation during the
three months ended September 30, 2003; and

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

The increase was partially offset by the following:

o a $15 million charge to depreciation expense in 2002 for the early
retirement of certain units at the Warren plant; and

o a $35 million net decrease in impairment charges related to turbines
and generators.

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
$12 million during the nine months ended September 30, 2003 compared to the same
period in 2002, primarily due to receipts of $12 million of business
interruption and property/casualty insurance settlements during 2002.

67

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 nine months ended September 30, 2002 and
2003:

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

Other operation's loss before interest and income taxes decreased $46
million during the three months ended September 30, 2003 compared to the same
period in 2002 primarily due to a $47 million charge relating to the accounting
settlement of certain benefit obligations associated with our separation from
CenterPoint during the three months ended September 30, 2002.

Nine Months Ended September 30, 2002 Compared to Nine Months Ended September 30,
2003.

Other operation's loss before interest and income taxes decreased $37
million during the nine months ended September 30, 2003 compared to the same
period in 2002 primarily due to a $47 million charge relating to the accounting
settlement of certain benefit obligations associated with our separation from
CenterPoint, offset by a $7 million accrual of Texas franchise taxes during the
nine months ended September 30, 2003 and an increase of $7 million in
unallocated corporate costs previously allocated to our discontinued European
energy operations. Included in other losses during the nine months ended
September 30, 2002 is a $6 million accrual for investment banking 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 in 2002.

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 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

68

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.

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 economically hedge commodity risk
associated with our wholesale energy power generation operations but which do
not qualify for hedge accounting (in prior periods through December 31, 2002)
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. We account for
these transactions under mark-to-market accounting. During the three months
ended September 30, 2003, we changed our classification of certain derivative
activities that historically were classified as trading activities to
non-trading activities. These activities include transactions that are entered
into to economically hedge commodity risk associated with our wholesale energy
power generation operations but which do not qualify for hedge accounting. We
have reclassified amounts in our consolidated statement of operations for the
six months ended June 30, 2003 from trading margins of $7 million to revenues
and purchased power expense based on the underlying hedged item. As of June 30,
2003, the amounts of non-trading derivative assets and liabilities previously
classified as trading and marketing assets and liabilities were $25 million and
$15 million, respectively. Corresponding amounts for these activities have not
been reclassified for periods prior to January 1, 2003 as prior period amounts
were not material to our consolidated financial statements.

For additional information regarding the types of contracts and activities
of our trading and marketing operations, see "Quantitative and Qualitative
Disclosures About Market Risk" in this Form 10-Q and note 8 to our interim
financial statements.

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

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

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

Fair Value of New Contracts - 2002. During the nine months ended September
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 nine months ended September 30, 2002, we
recognized total fair value of $42 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. The remaining fair value of contracts
(entered into during the nine months ended September 30, 2002) recorded at
inception of $6 million primarily relates to natural gas transportation
contracts entered into by the wholesale energy segment.

Changes in Fair Values Attributable to Changes in Valuation Techniques and
Assumptions - 2002. During the three months ended June 30, 2002, we changed our
methodology for allocating credit reserves between our trading and non-trading
portfolios. Total credit reserves calculated for both the trading and
non-trading portfolios, which are less than the sum of the independently
calculated credit reserves for each portfolio due to common counterparties
between the portfolios, are allocated to the trading and non-trading portfolios
based upon the independently calculated trading and non-trading credit reserves.
Previously, credit reserves were independently calculated for the trading
portfolio while credit reserves for the non-trading portfolio were calculated by
deducting the trading credit reserves from the total credit reserves calculated
for both portfolios. This change in methodology reduced credit reserves relating
to the trading portfolio by $18 million. During the three months ended September
30, 2002, our retail energy segment eliminated one valuation factor adjustment
and added another to its fair value calculation. Our retail energy segment
eliminated a valuation factor for potential claims for delays in switching under
the liquidated damages clauses in contracts. We eliminated this valuation factor
because there was adequate data to substantiate that these claims would not be
submitted. This change in methodology reduced credit reserves by $5 million. Our
retail energy segment added a valuation factor adjustment to capture the
potential earnings loss associated with customers terminating contracts due to a
provision in some of its contracts that allows customers to terminate their
contracts if our unsecured debt ratings fall below investment grade or if our
ratings are withdrawn entirely by a rating agency. During the three months ended
September 30, 2002, each of the major rating agencies downgraded our credit
ratings to sub-investment grade. We performed an analysis at the customer level
to estimate our exposure for these provisions. This change in methodology
increased credit reserves by $1 million. Our retail energy segment also changed
the methodology related to recording its estimate of unaccounted for energy. Our
retail energy segment changed its unaccounted for energy factor from 1.6% to
zero. The reason for the change is that we believe the unaccounted for energy
factor is included in the volatility valuation factor and our results from
energy sales in 2001 were not negatively impacted by unaccounted for energy.
This change in methodology increased the fair value of the net trading and
marketing assets by $9 million.

Changes in Fair Values Attributable to Changes in Valuation Techniques and
Assumptions - 2003. During the three months ended June 30, 2003, we refined the
probabilities of counterparty default applied in calculating the credit
reserves, increasing credit reserves by $1 million. During the three months
ended September 30, 2003, we revised our assumptions used to estimate credit,
administrative and liquidity reserves and adjusted our discount rate used in
valuing forward positions. We modified our estimated probabilities of
counterparty default and considered master netting agreements, which resulted in
a decrease in credit reserves of $11 million. We reduced estimated costs to
administer transactions used in calculating administrative reserves to reflect
the change in our cost structure, which resulted in a decrease in administrative
reserves of $2 million. With regards to liquidity reserves, we modified our
assumptions to consider the widening of bid/ask spreads for transactions
occurring further into the future, which resulted in an increase

70

in the liquidity reserves of $5 million. Also, during the three months ended
September 30, 2003, we adjusted our discount rate used in valuing derivative
transactions to a risk-free U.S. Treasury rate from an investment-grade utility
rate, which resulted in an increase in fair value of $4 million.

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

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

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.

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

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

71

Based on our analysis, as of September 30, 2003, the total dollar amounts
of our investment and non-investment grade credit exposures have declined since
December 31, 2002 and June 30, 2003. However, the proportion of non-investment
grade credit exposure to total credit exposure has increased as a result of a
decrease in our total credit exposure. One non-investment grade counterparty
represented approximately 14% and 26% of our overall credit exposure as of
December 31, 2002 and September 30, 2003, respectively. The dollar amounts of
our credit exposure to this one counterparty were $86 million and $108 million
as of December 31, 2002 and September 30, 2003, respectively.

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 and non-trading risk
exposures through a variety of processes and committees.

FINANCIAL CONDITION

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

Cash Provided by Operating Activities

Net cash provided by operating activities during the nine months ended
September 30, 2003 increased $256 million compared to the same period in 2002.
This increase was primarily due to $390 million of decreased working capital
requirements and other changes in assets and liabilities from continuing
operations offset by $228 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
operations decreased $94 million for the nine months ended September 30, 2003
compared to the same period in 2002.

Cash flows used for working capital and other assets and liabilities
decreased by $390 million from net cash outflows of $410 million in the nine
months ended September 30, 2002 to net cash outflows of $20 million in the nine
months ended September 30, 2003.

Net cash provided by our operations, excluding changes in working capital
and other changes in assets and liabilities, decreased by $228 million from $792
million in the nine months ended September 30, 2002 to $564 million in the nine
months ended September 30, 2003, primarily due to a decline in cash flows of our
wholesale energy segment due to a decline in operating results.

Nine Months Ended September 30, 2003. Net cash provided by operating
activities during the nine months ended September 30, 2003 was $528 million,
comprised of $564 million in cash flows from continuing operations, excluding
changes in working capital and other changes in assets and liabilities, offset
by $20 million of cash outflows related to changes in working capital and other
assets and liabilities. Additionally, cash flows used in the operations of our
discontinued operations was $16 million.

Net cash provided by our operations in the nine months ended September 30,
2003, excluding changes in working capital and other changes in assets and
liabilities, primarily related to our retail energy segment.

The $20 million in cash outflows for working capital and other changes in
assets and liabilities was primarily due to the following:

o $143 million decrease in accounts payable primarily associated with
the decrease in purchased power and fuel purchases in our wholesale
energy segment as a result of decreased hedging activities;

o $112 million of net option premiums purchased related to our retail
energy segment's hedging activities;

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o $99 million increase in accounts receivable primarily related to our
retail energy segment, partially offset by a decrease due to a
decrease in our wholesale energy segment's proprietary trading
activities;

o $58 million increase in restricted cash primarily related to our Orion
Power operations and restricted funds for the support of lease
obligations of REMA;

o $47 million of net purchases of emissions credits;

o $32 million in increased lease prepayments related to the REMA
sale-leaseback agreements;

o $29 million paid to purchase interest rate caps; and

o other changes in working capital and assets and liabilities.

These cash outflows were partially offset by the following:

o $225 million of cash inflows related to reduced cash requirements for
margin deposits for our trading and hedging activities, which were
primarily replaced with letters of credit;

o $158 million in net proceeds related to our receivables facility with
financial institutions (see note 14 to our interim financial
statements);

o $97 million of changes in income tax receivables; and

o $50 million for settlement of volumes delivered under contracted
electricity sales to large commercial, industrial and institutional
customers and the related energy supply contracts, which were
previously recognized as unrealized earnings in prior periods (see
note 2 to our interim financial statements).

Nine Months Ended September 30, 2002. Net cash provided by operating
activities during the nine months ended September 30, 2002 was $272 million,
comprised of $792 million in cash flows from continuing operations, excluding
changes in working capital and other changes in assets and liabilities, offset
by $410 million of cash outflows related to changes in working capital and other
assets and liabilities. Additionally, cash flows used in the operations of our
discontinued operations was $110 million.

Net cash provided by our operations in the nine months ended September 30,
2002, excluding changes in working capital and other changes in assets and
liabilities, primarily related to both our retail energy segment and our
wholesale energy segment.

The $410 million in cash outflows for working capital and other changes in
assets and liabilities was primarily due to the following:

o $787 million increase in accounts receivable primarily due to the
start-up of our retail energy segment in 2002 as a result of the
opening of the Texas retail market to full competition in January
2002;

o $130 million of cash outflows related to margin deposits related to
our trading and hedging activities and our lower credit ratings;

o $94 million increase in inventory for fuel related primarily to our
wholesale energy segment;

o $93 million in increased lease prepayments related to the REMA
sale-leaseback agreements; and

o other changes in working capital and assets and liabilities.

These cash outflows were partially offset by the following:

o $250 million in net proceeds related to our receivables facility with
a financial institution to sell an undivided interest in accounts
receivable from residential and small commercial retail electric
customers;

o $136 million of net collateral deposits related to an operating lease
returned to us in the nine months ended September 30, 2002;

o $114 million decrease in restricted cash primarily attributable to
REMA's funds becoming unrestricted pursuant to REMA's sale-leaseback
agreement, partially offset by Orion Power's operations;

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o $103 million increase in accounts payable primarily related to gas
purchases made by our wholesale energy segment, coupled with increased
gas prices;

o $96 million related to two structured transactions, which were settled
in 2002; and

o $24 million of net option premium purchases related to our retail
energy segment's hedging activities.

Cash Used in Investing Activities

Net cash used in investing activities during the nine months ended
September 30, 2003 decreased $2.5 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 the investment of
$266 million of net proceeds from our June and July 2003 issuances of
convertible senior subordinated notes into restricted cash, as discussed below.

Nine Months Ended September 30, 2003. Net cash used in investing activities
during the nine months ended September 30, 2003 was $757 million, primarily due
to capital expenditures of $472 million primarily related to our power
generation operations. In addition, we received $266 million in net proceeds
from our June and July 2003 issuances of convertible senior subordinated notes,
which were placed in an escrow account and are recorded as restricted cash in
our consolidated balance sheet as of September 30, 2003.

Nine Months Ended September 30, 2002. Net cash used in investing activities
during the nine months ended September 30, 2002 was $3.3 billion, primarily due
to funding the acquisition of Orion Power for $2.9 billion in February 2002 as
discussed below and $455 million in capital expenditures primarily related to
our power generation operations. This was offset by cash inflows of $118 million
from our discontinued operations primarily due to a $137 million cash dividend
from our discontinued European energy operation's equity investment in NEA.

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 6 to our interim financial statements.

Cash Provided by (Used in) Financing Activities

Net cash provided by financing activities during the nine months ended
September 30, 2003 decreased by $5.1 billion compared to the same period in
2002.

Nine Months Ended September 30, 2003. Net cash used in financing activities
during the nine months ended September 30, 2003 was $771 million which was
primarily due to the following:

o $1.056 billion prepayment of senior secured term loans under our March
2003 credit facilities due to proceeds from our July 2003 debt
issuances (see below);

o a $350 million prepayment in March 2003 of the senior revolving credit
facility made in connection with the refinancing in March 2003;

o $716 million of other net payments on our senior secured revolving
credit facility;

o $183 million of payments of financing costs related to the March 2003
refinancings and our debt issuances in June and July of 2003; and

o $66 million of repayments of Orion MidWest and Orion NY senior term
loans.

The following cash inflows partially offset those uses of cash:

o $1.056 billion in net proceeds from our senior secured notes issued in
July 2003;

o $266 million in net proceeds from our convertible senior subordinated
notes issued in June and July 2003;

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o $99 million in net proceeds from an additional PEDFA bond issuance for
our Seward generation plant;

o $95 million of net borrowings under a financing commitment for the
construction of three power generation facilities in the first quarter
of 2003 prior to the March 2003 refinancings; and

o $42 million of draws under letters of credit to provide support for
REMA's lease obligations.

Nine Months Ended September 30, 2002. Net cash provided by financing
activities during the nine months ended September 30, 2002 was $4.3 billion due
primarily to an increase in short-term borrowings used to fund the acquisition
of Orion Power and an increase in working capital to meet future obligations and
other working capital requirements. In addition, net cash provided by financing
activities was due to decreased investments of excess cash in an affiliate of
CenterPoint. These cash inflows were partially offset by the purchase of $189
million in principal amount of the Orion Power 4.5% convertible senior notes.

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. After completion of the construction
of two generation facilities that are in progress, we intend to sharply limit
any construction and also our March 2003 credit facilities substantially
restrict the construction of any new generation facilities. Maintenance of
plants will continue to include costs necessary to operate the plants safely,
including necessary environmental expenditures. We will evaluate opportunities
to enter retail electric markets for large commercial, industrial and
institutional customers, in particular, in regions in which we have electric
generating facilities and capacity. Subject to restrictions in our March 2003
credit facilities 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
facility and proceeds from one or more debt and equity offerings, securitization
of assets, other borrowings and potential sales of assets. 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, as well as the capital
expenditures needed to complete the two generation facilities under construction
discussed above and to maintain our other generation facilities.

Generating Projects. As of September 30, 2003, we had two generating
facilities under construction. We expect to complete these two facilities in
November 2003 and the second half of 2004. Total estimated cost of constructing
these facilities is $1.2 billion. As of September 30, 2003, we had incurred $1.0
billion in construction costs, property, plant and equipment and spare parts
inventory on these projects, which was funded from equity and debt.

Environmental Expenditures. We anticipate spending up to $226 million in
capital expenditures for the remainder of 2003 through 2007 for environmental
compliance, totaling approximately $44 million, $39 million, $34 million, $70
million and $39 million in the remainder of 2003, 2004, 2005, 2006 and 2007,
respectively. In addition, we expect to spend $20 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 September 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. 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.

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Other Operating Lease Commitments. For a discussion of other operating
leases, see our Current Report on Form 8-K filed on June 30, 2003.

Commodity Commitments. For a discussion of other commodity commitments, see
our Current Report on Form 8-K filed on June 30, 2003.

Payment to CenterPoint. We will be required to make a payment to
CenterPoint in 2004 related to residential customers. As of September 30, 2003,
our estimate for the payment is between $170 million and $180 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(c) to our interim financial
statements.

Naming Rights to Houston Sports Complex. In October 2000, we acquired the
naming rights for a football stadium and other convention and entertainment
facilities included in the stadium complex. Starting in 2002 and continuing
through 2032, we pay $10 million each year for annual advertising under this
agreement.

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

During 2002 and through 2003 to date, many factors negatively impacted us.
These factors included weaker pricing for electric energy, capacity and
ancillary services, coupled with a narrowing of the spark spread in the United
States; market contraction, reduced volatility and reduced liquidity in the gas
and power trading markets in the United States; 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(a) 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 in 2002; 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 and senior secured notes. 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.

If we do require but 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. These factors
may negatively impact our ability to operate our business.

As a result of our March 2003 refinancing and our June and July 2003
capital markets debt issuances, our interest expense has increased
substantially. The exact future 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
refinanced as part of 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 September 30,
2003, the weighted average interest rate on the senior secured term loans was
5.27% while the weighted average interest rate on the senior secured notes was
9.38%, 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 as much as $14 million on an annual basis as long as
this debt remains outstanding. For additional

76

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.

Banking or Credit Facilities, Bonds, Notes and Other Debt.

As of September 30, 2003, we had consolidated current and long-term debt
outstanding of $7.5 billion. As of September 30, 2003, we had $9.4 billion in
committed credit facilities, bonds and notes of which $1.1 billion was unused.
As of September 30, 2003, letters of credit outstanding under these facilities
aggregated $865 million. As of September 30, 2003, $92 million of our committed
credit facilities are to expire by September 30, 2004. For a discussion of our
banking or credit facilities, bonds, notes and other debt, see note 10 to our
interim financial statements.

Currently, we are satisfying our capital requirements and other commitments
primarily with cash from operations, cash on hand and borrowings available under
our credit facilities. The following table summarizes our credit capacity, cash
and cash equivalents and current restricted cash at September 30, 2003:

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

(1) As discussed in notes 10 and 13(e) 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
effectively restricted by financing agreements, but is available to the
applicable subsidiary to use to satisfy certain of its obligations.

(3) This amount does not include $266 million from the net proceeds of our
convertible senior subordinated notes, which are classified as long-term
restricted cash in our consolidated balance sheet.

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 and other areas in which we
operate;

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

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

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

o provisions of relevant tax and securities laws;

o impact of lawsuits, investigations and other proceedings including
market expectations related thereto;

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

77

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

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

Our March 2003 credit facilities restrict our ability to take specific
actions without the consent of our lenders, even if such actions may be in our
best interest.

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.

Credit Ratings.

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

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

As of November 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 November 1, 2003, the Moody's senior unsecured 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 previous downgrades 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

78

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
possible 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 have been 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 November 1,
2003, we have posted cash collateral of $96 million and letters of credit of
$426 million from Reliant Resources' facilities. In addition, we have posted
cash collateral of $6 million and letters of credit of $17 million related to
commercial operations from Orion Power subsidiary facilities. In support of
financings, we have issued additional letters of credit of $407 million from
Reliant Resources' facilities and $17 million from subsidiary facilities and
posted cash collateral of $42 million with cash from subsidiaries. Based on
current commodity prices, we estimate that as of November 1, 2003, we could be
required to post additional collateral of up to $368 million related to our
domestic operations. As of November 1, 2003, we had $58 million in unrestricted
cash and cash equivalents and $1.1 billion available under committed corporate
facilities. Factors which could lead to an increase in our actual posting of
collateral include adverse changes in our industry, negative reactions to
additional credit rating downgrades and changes in commodity prices.

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.

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 12 months. Under certain
unfavorable commodity price scenarios, however, it is possible that we could
experience inadequate liquidity.

Other Sources and Uses of Cash and Factors Impacting Cash.

Asset Sales.

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 sale closed on
October 15, 2003. The net proceeds of $285 million were placed in a restricted
escrow account for the possible acquisition of CenterPoint's holdings of the
common stock of Texas Genco. For further discussion of the sale, see note 18 to
our interim financial statements.

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. 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. Upon consummation of
the sale, we expect to receive cash proceeds 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. This would result in net cash proceeds of approximately $0.6
billion (Euro 0.5 billion). We intend to place $360 million of the net proceeds
in a restricted escrow account for the possible acquisition of CenterPoint's
holdings of the common stock of Texas Genco. We intend to use the balance of the
net proceeds (approximately $0.2 billion) to prepay indebtedness under our March
2003 credit facilities. For further discussion of the sale, see note 17 to our
interim financial statements.

If we elect to acquire CenterPoint's holdings of the common stock of Texas
Genco in 2004, we intend to use the $650 million of net proceeds from asset
sales in the restricted escrow account to partially fund such acquisition.
However, if by September 30, 2004, we elect not to acquire CenterPoint's
holdings of the common stock of Texas Genco, we must use the cash in the
restricted escrow account to prepay indebtedness under our March 2003 credit
facilities and to collateralize the $300 million senior priority loan

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commitment.

Other.

Generating Capacity Auction Line of Credit. 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. See note 4 to our
interim financial statements for further discussion.

California Trade Receivables and the FERC Refunds. As of September 30,
2003, we were owed total receivables, including interest, of $218 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 September 30, 2003.
For additional information regarding these receivables and uncertainties in the
California wholesale market, see note 13(b) to our interim financial statements.

October 2003 Settlement with the FERC. In October 2003, the FERC issued an
order approving an agreement with certain of our subsidiaries to settle all
inquiries, investigations and proceedings instituted by the FERC involving us in
connection with the FERC's ongoing review of western energy markets (excluding
the FERC refund issue discussed above). We are required to make cash payments
totaling $25 million and offer a certain amount of capacity, paying the
difference, up to $25 million, between the collected auction revenues and our
projected cash costs to generate the power through 2006. For additional
information, see note 13(a) 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."

Liberty Electric Generating Station Contingency. The output of the Liberty
generating station was contracted under a tolling agreement (which was rejected
effective July 8, 2003) between LEP, a wholly-owned indirect subsidiary of Orion
Power, and ET Power, which has filed for chapter 11 of the United States
bankruptcy code. 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(e) to our interim financial
statements.

OFF-BALANCE SHEET TRANSACTIONS

Receivables Facility Agreement. We entered into a receivables facility
arrangement with financial institutions to sell an undivided interest in our
accounts receivable from our residential and small commercial retail electric
customers and our large commercial, industrial and institutional customers under
which, on an ongoing basis, the financial institutions could invest a maximum of
$350 million for their interest in eligible receivables. Pursuant to this
receivables facility, we formed a QSPE as a bankruptcy remote subsidiary. For
additional information, 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 our Current Report on
Form 8-K filed on June 30, 2003.

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NEW ACCOUNTING PRONOUNCEMENTS, SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL
ACCOUNTING ESTIMATES

NEW ACCOUNTING PRONOUNCEMENTS

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

SIGNIFICANT ACCOUNTING POLICIES

For discussion regarding our significant accounting policies, see our
Current Report on Form 8-K filed on June 30, 2003. For a discussion of
significant changes in our accounting policies during the nine months ended
September 30, 2003, see note 2 to our interim financial statements.

CRITICAL ACCOUNTING ESTIMATES

For discussion regarding our critical accounting estimates, see our Current
Report on Form 8-K filed on June 5, 2003. There have been no significant changes
in our critical accounting estimates other than our estimates and assumptions
that relate to the analysis of our goodwill. See note 7 to our interim financial
statements for further discussion.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

This "Quantitative and Qualitative Disclosures about Market Risk" should be
read in conjunction with our Current Report on Form 8-K filed on June 5, 2003.

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 the
activities, which we report 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 significant market risks include
exposures primarily related to commodity prices 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."

We seek to monitor and control our trading risk exposures through a variety
of processes and committees.

TRADING MARKET RISK

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

The following table presents the daily value at risk for substantially all
of our trading and marketing positions for the three and nine months ended
September 30, 2002 and 2003 based on a 95% confidence level and primarily a two
day

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holding period for natural gas and petroleum products and holding periods of 5
to 20 days with a 99% confidence level based on the risk profile of the
portfolio for power products:

During the nine months ended September 30, 2003, average value at risk
exposure was lower compared to 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 fair value based on a hypothetical 10% movement
in the underlying energy prices. A decrease of 10% in the market prices of
energy commodities from their September 30, 2003 levels would have decreased the
fair value of our non-trading energy derivatives by $42 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 $5.4 billion at September 30,
2003. If the floating interest rates were to increase by 10% from September 30,
2003 rates, our interest expense would increase by a total of $2.0 million each
month in which such increase continued. This does not include the impact of our
interest rate swaps discussed below.

At September 30, 2003, we had issued fixed-rate debt to third parties
aggregating $1.9 billion, excluding Liberty's fixed-rate debt of $165 million.
As of September 30, 2003, the fair values of these debt instruments, excluding
Liberty's fixed rate debt, were $1.7 billion. These instruments are fixed-rate
and, therefore, do not expose us to the risk of loss in earnings due to changes
in market interest rates. However, the fair value of these instruments,
excluding Liberty's fixed-rate debt, would increase by $99 million if interest
rates were to decline by 10% from their rates at September 30, 2003.

As of September 30, 2003, we have interest rate swap contracts with an
aggregate notional amount of $750 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 $110 million ($94 million for Orion MidWest and
Orion NY and $16 million for Channelview) at September 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 September 30, 2003 level of interest rates would increase the cost of
terminating the interest rate swaps by $7 million. For information regarding the
accounting for these interest rate derivative instruments, see notes 8 and 10(b)
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

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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 $4 million at September 30,
2003. A decrease of 10% in the September 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(b) 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(a), 13(b)
and 13(e) to our interim financial statements.

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS.

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 restrictions, see note 10 to our interim financial statements and our
Quarterly Report on Form 10-Q filed on August 13, 2003.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

The 2003 annual meeting of our stockholders was held on June 4, 2003. The
purpose of the annual meeting was to consider and vote upon the following
proposals:

1. To elect one director to our board of directors;

2. To ratify the appointment of Deloitte & Touche LLP as our independent
accountants for 2003; and

3. To consider and vote upon a proposal to amend certain terms of the
Reliant Resources, Inc. Employee Stock Purchase Plan.

At the annual meeting, Joel V. Staff was re-elected to serve as a Class I
director of Reliant Resources, Inc. The votes cast for the nominee and the votes
withheld were as follows:

The names of each other director whose terms of office as a director continued
after the meeting are: E. William Barnett, Donald J. Breeding, Laree E. Perez
and William L. Transier.

The following votes were cast with respect to the ratification of the
appointment of Deloitte & Touche LLP as our independent accountants for the
fiscal year ended December 31, 2003:

The following votes were cast with respect to the proposal to amend certain
terms of the Reliant Resources, Inc. Employee Stock Purchase Plan. There were
82,567,928 broker non-votes.

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.

During the quarter ended September 30, 2003, we filed or furnished the
following Current Reports on Form 8-K:

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o Current Report on Form 8-K, dated July 9, 2003 (Items 5 and 7),
announcing that we had entered into a definitive agreement for the sale
of our Desert Basin plant;

o Current Report on Form 8-K, dated July 16, 2003 (Items 7 and 9),
providing the slide presentation used by the Senior Vice President -
Finance of Reliant Resources, Inc. when he spoke to the public, as well
as various members of the financial and investing community on July 17,
2003;

o Current Report on Form 8-K, dated July 22, 2003 (Items 7 and 9),
providing combined and consolidated financial statements of Reliant
Energy Mid-Atlantic Power Holdings, LLC and its subsidiaries for the
three years ended December 31, 2000, 2001 and 2002;

o Current Report on Form 8-K, dated July 23, 2003 (Items 5 and 7),
providing revised (a) unaudited interim financial statements as of
December 31, 2002 and March 31, 2003 and for the three months ended
March 31, 2002 and 2003, (b) management's discussion and analysis of
financial condition and results of operations as of March 31, 2003 and
for the three months ended March 31, 2002 and 2003 and (c) unaudited
pro forma condensed consolidated financial statements for the
anticipated sale of our Desert Basin plant;

o Current Report on Form 8-K, dated August 12, 2003 (Items 5, 7, 9 and
12), (a) announcing the appointment of Kirbyjon H. Caldwell and Steven
L. Miller to our board of directors, (b) announcing Joel V. Staff will
serve as the permanent chairman and CEO and that the search process for
these positions has been concluded and (c) announcing our earnings for
the quarterly period ended June 30, 2003;

o Current Report on Form 8-K, dated August 13, 2003 (Item 9), providing
consolidated interim financial statements of Orion Power Holdings, Inc.
and management's narrative analysis of financial condition and results
of operations for the quarterly period ended June 30, 2003;

o Current Report on Form 8-K, dated August 26, 2003 (Items 5 and 7),
providing unaudited pro forma condensed consolidated financial
statements for the anticipated sale of our Desert Basin plant;

o Current Report on Form 8-K, dated August 28, 2003 (Item 9), providing
consolidated interim financial statements of Reliant Energy
Mid-Atlantic Power Holdings, LLC and subsidiaries and management's
narrative analysis of results of operations for the quarterly period
ended June 30, 2003;

o Current Report on Form 8-K, dated September 11, 2003 (Item 9),
providing information regarding the regulatory approval process for the
sale of our European energy operations and filing as exhibits (a) a
press release of the Dutch competition authority (NMa) regarding the
outcome of its first phase review of the proposed acquisition, (b) the
unofficial English translation of an order released September 25, 2003,
of the director-general of the NMa and (c) the Share Purchase
Agreement, dated as of February 28, 2003, among Reliant Energy Europe
Inc., Reliant Energy Wholesale (Europe) Holdings B. V., n.v. Nuon and
Reliant Resources, Inc. The Form 8-K also included as Exhibit 99.4,
information regarding the results of submission of matters to a vote of
security holders at our annual meeting; and

o Current Report on Form 8-K, dated September 18, 2003 (Items 5 and 7),
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 September 18, 2003.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the
registrant has duly caused this report to be signed on its behalf by the
undersigned thereunto duly authorized.

RELIANT RESOURCES, INC.
(Registrant)

November 12, 2003 By: /s/ Thomas C. Livengood
-----------------------
Thomas C. Livengood
Vice President and Controller
(Principal Accounting Officer)

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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.