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
lende