RELIANT RESOURCES INC - 10-K Annual Report

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

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
OR
[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934
FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-16455
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RELIANT RESOURCES, INC.
(Exact Name of Registrant as Specified in Its Charter)

DELAWARE 76-0655566
(State or Other Jurisdiction of Incorporation (I.R.S. Employer Identification No.)
or Organization)

1000 MAIN STREET, HOUSTON, TEXAS 77002 (713) 497-3000
(Address and Zip Code of Principal Executive (Registrant's Telephone Number, Including
Offices) Area Code)

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: NONE
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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 if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein, and will not be contained, to the
best of the Registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K/A or any
amendment to this Form 10-K/A. [X]

Indicate by check mark whether the Registrant is an accelerated filer (as
defined in Exchange Act Rule 12b-2). Yes [X] No [ ]

The aggregate market value of the voting stock held by non-affiliates of
the Registrant was $1,788,989,958 (computed by reference to the closing sale
price of the Registrant's common stock on the New York Stock Exchange on June
30, 2003). As of March 1, 2004, the Registrant had 295,539,205 shares of common
stock outstanding, excluding 4,264,795 shares of common stock held by the
Registrant as treasury stock.

Portions of the definitive proxy statement relating to the 2004 Annual
Meeting of Stockholders of the Registrant's, which will be filed with the
Securities and Exchange Commission within 120 days of December 31, 2003, are
incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of
Part III of this Form 10-K.
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TABLE OF CONTENTS

iii

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

When we make statements containing projections, estimates or assumptions
about our revenues, income and other financial items, our plans for the future,
future economic performance, transactions for the sale of parts of our
operations and financings related thereto, we are making "forward-looking
statements." Forward-looking statements 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," "effort," "target" 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.

Among other things, the matters described in "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Risk Factors" in
Item 7 of this report and note 15 to our consolidated financial statements could
cause actual results to differ materially from those expressed or implied in our
forward-looking statements.

Each forward-looking statement speaks only as of the date of the particular
statement and we undertake no obligation to publicly update or revise any
forward-looking statement, whether as a result of new information, future events
or otherwise.

1

GLOSSARY OF TERMS

The following terms are used in this report:

APB No. 25.................... Accounting Principles Board Opinion No. 25,
"Accounting for Stock Issued to Employees."

Bcf........................... one billion cubic feet of natural gas.

Cal ISO....................... California Independent System Operator.

Cal PX........................ California Power Exchange.

CDWR.......................... California Department of Water.

CenterPoint................... CenterPoint Energy, Inc., on and after August
31, 2002 and Reliant Energy, Incorporated prior
to August 31, 2002.

CenterPoint Plans............. CenterPoint Long-Term Incentive Compensation
Plan and certain other incentive compensation
plans of CenterPoint.

CERCLA........................ Comprehensive Environmental Response
Corporation and Liability Act of 1980.

CFTC.......................... Commodity Futures Trading Commission.

Channelview................... Reliant Energy Channelview L.P.

CO(2)......................... Carbon dioxide.

Distribution.................. the distribution of approximately 83% of our
common stock owned by CenterPoint to its
stockholders on September 30, 2002.

EBIT.......................... earnings (loss) before interest expense,
interest income and income taxes.

EBITDA........................ earnings (loss) before interest expense,
interest income, income taxes, depreciation and
amortization expense.

ECAR Market................... the wholesale electric market operated by East
Central Area Reliability Coordination Council.

EITF.......................... Emerging Issues Task Force.

EITF No. 98-10................ EITF Issue No. 98-10, "Accounting for Contracts
Involved in Energy Trading and Risk Management
Activities."

EITF No. 02-03................ EITF Issue No. 02-03, "Issues Related to
Accounting for Contracts Involved in Energy
Trading and Risk Management Activities."

EITF No. 03-11................ 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."

Enron......................... Enron Corp. and its affiliates.

EPA........................... United States Environmental Protection Agency.

ERCOT......................... Electric Reliability Council of Texas.

ERCOT ISO..................... ERCOT Independent System Operator.

2

ERCOT Region.................. the electric market operated by ERCOT.

ESPP.......................... Reliant Resources Employee Stock Purchase Plan.

FASB.......................... Financial Accounting Standards Board.

FERC.......................... Federal Energy Regulatory Commission.

FIN No. 45.................... FASB Interpretation No. 45, "Guarantor's
Accounting and Disclosure Requirements for
Guarantees, Including Direct Guarantees of
Indebtedness of Others."

FIN No. 46.................... FASB Interpretation No. 46, "Consolidation of
Variable Interest Entities, an Interpretation
of ARB No. 51."

FIN No. 46R................... FASB Interpretation No. 46 (revised December
2003), "Consolidation of Variable Interest
Entities, an Interpretation of ARB No. 51."

GAAP.......................... United States generally accepted accounting
principles.

GWh........................... gigawatt hour.

IPO........................... our initial public offering in May 2001.

ISO........................... independent system operator.

KWh........................... kilowatt hour.

LEP........................... Liberty Electric Power, LLC, one of our
subsidiaries.

Liberty....................... Liberty Electric PA, LLC, one of our
subsidiaries.

LIBOR......................... London inter-bank offered rate.

MACT.......................... Maximum Achievable Control Technology.

MAIN Market................... the wholesale electric market operated by
Mid-America Interconnected Network.

MISO.......................... Midwest Independent Transmission System
Operator.

MISO Market................... the wholesale electric market operated by MISO,
primarily in all parts of Iowa, Kentucky,
Michigan, Minnesota, Missouri, Nebraska, North
Dakota and South Dakota.

MMbtu......................... one million British thermal units.

MW............................ megawatts.

MWh........................... megawatt hour.

NEA........................... NEA, B.V., formerly the coordinating body for
the Dutch electric generating sector.

NO(x)......................... Nitrogen oxides.

NYISO......................... New York Independent System Operator.

NY Market..................... the wholesale electric market operated by NYISO
in the state of New York.

Orion Capital................. Orion Power Capital, LLC, one of our
subsidiaries.

Orion MidWest................. Orion Power MidWest, L.P., one of our
subsidiaries.

Orion NY...................... Orion Power New York, L.P., one of our
subsidiaries.

3

Orion Power................... Orion Power Holdings and its subsidiaries.

Orion Power Holdings.......... Orion Power Holdings, Inc., one of our
subsidiaries.

OTC........................... over-the-counter market.

PEDFA......................... Pennsylvania Economic Development Financing
Authority.

PG&E.......................... Pacific Gas and Electric.

PJM........................... PJM Interconnection, LLC.

PJM Market.................... the wholesale electric market operated by PJM
primarily in all or parts of Delaware, the
District of Columbia, Maryland, New Jersey,
Ohio, Pennsylvania, Virginia and West Virginia.

POLR.......................... provider of last resort.

PUCT.......................... Public Utility Commission of Texas.

PUHCA......................... Public Utility Holding Company Act of 1935.

QSPE.......................... qualified special purpose entity.

RE BV......................... Reliant Energy Europe B.V., formerly one of our
subsidiaries.

RECE.......................... Reliant Energy Capital (Europe), Inc., one of
our subsidiaries.

Reliant Energy................ Reliant Energy, Incorporated and its
subsidiaries.

Reliant Energy Services....... Reliant Energy Services, Inc., one of our
subsidiaries.

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

REMA.......................... Reliant Energy Mid-Atlantic Power Holdings,
LLC, one of our subsidiaries, and its
subsidiaries.

REPG.......................... Reliant Energy Power Generation, Inc., one of
our subsidiaries.

REPGB......................... Reliant Energy Power Generation Benelux, B.V.,
formerly one of our subsidiaries.

RTO........................... regional transmission organizations.

SCE........................... Southern California Edison Company.

SEC........................... Securities and Exchange Commission.

SFAS.......................... Statement of Financial Accounting Standards.

SFAS No. 123.................. SFAS No. 123, "Accounting for Stock Based
Compensation."

SFAS No. 132.................. SFAS No. 132, "Employers' Disclosures about
Pensions and Other Postretirement Benefits."

SFAS No. 132 (Revised 2003)... SFAS No. 132 (Revised 2003), "Employers'
Disclosures about Pensions and Other
Postretirement Benefits -- An Amendment of FASB
Statements No. 87, 88 and 106."

SFAS No. 133.................. SFAS No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as
amended.

SFAS No. 141.................. SFAS No. 141, "Business Combinations."

SFAS No. 142.................. SFAS No. 142, "Goodwill and Other Intangible
Assets."

SFAS No. 143.................. SFAS No. 143, "Accounting for Asset Retirement
Obligations."

4

SFAS No. 144.................. SFAS No. 144, "Accounting for Impairment or
Disposal of Long-Lived Assets."

SFAS No. 148.................. SFAS No. 148, "Accounting for Stock Based
Compensation -- Transition and Disclosure, an
amendment to SFAS No. 123."

SFAS No. 149.................. SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities."

SO(2)......................... Sulfur dioxide.

Spark spread.................. the difference between power prices and natural
gas fuel costs.

SRP........................... Salt River Agricultural Improvement and Power
District.

Texas electric restructuring
law........................... Texas Electric Choice Plan adopted by the Texas
legislature in June 1999.

Texas Genco................... Texas Genco, LP and its subsidiaries and Texas
Genco Holdings, Inc., and its subsidiaries.

Texas Genco Holdings, Inc..... a majority-owned subsidiary of CenterPoint.

Texas Genco, LP............... a subsidiary of Texas Genco Holdings, Inc.

5

PART I

ITEM 1. BUSINESS.

OUR BUSINESS

GENERAL

"Reliant Resources" refers to Reliant Resources, Inc. and "we," "us" and
"our" refer to Reliant Resources, Inc. and its consolidated subsidiaries, unless
we specify or the context indicates otherwise.

Our business operations consist of two principal business segments:

- Retail energy -- provides electricity and related services to retail
customers primarily in Texas and acquires and manages the electric
energy, capacity and ancillary services associated with supplying these
retail customers; and

- Wholesale energy -- provides electric energy, capacity and ancillary
services in the competitive segments of the United States' wholesale
energy markets.

Our remaining operations include unallocated corporate functions and minor
equity and other investments. For information regarding our corporate history,
including the sale of our European energy operations in 2003, see notes 1 and 22
to our consolidated financial statements.

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. The operations of our
retail energy segment are primarily in Texas. In 2003, we began providing retail
energy products and services to small and large commercial, industrial and
institutional customers in New Jersey and Maryland. In 2004, we intend, to the
extent market conditions are attractive, to begin retail energy sales to
commercial, industrial and institutional customers in other areas of the PJM
Market, including Pennsylvania. We are also evaluating the possibility of making
similar sales to customers in the MISO Market.

RESIDENTIAL AND SMALL COMMERCIAL SERVICES -- SERVICES BUSINESS

In Texas, we provide standardized electricity and related products and
services to residential and small commercial customers with a peak demand for
power up to approximately one MW. As of December 31, 2003, we had approximately
1.6 million residential customers and 210,000 small commercial accounts in
Texas, making us the second largest retail electric provider in the state. The
majority of our customers are in the Houston area, but we also have customers in
other areas, including Dallas and Corpus Christi, Texas.

In the Houston area, the Texas electric restructuring law currently
requires us, as a former affiliate of the transmission and distribution utility
in Houston, to sell electricity to residential customers only at a specified
price, or "price-to-beat." Outside of the Houston area, we are generally
permitted to sell electricity at unregulated prices to residential and small
commercial customers. For information regarding the PUCT regulation of pricing
to residential and small commercial customers, see "-- Regulation" below.

We currently provide retail electric service to residential customers only
in Texas. We have no near-term plans to provide retail electric service to
residential customers outside of Texas.

COMMERCIAL, INDUSTRIAL AND INSTITUTIONAL SERVICES -- SOLUTIONS BUSINESS

In Texas, we market electricity and energy services to large commercial,
industrial and institutional customers, i.e., customers with a peak demand of
greater than approximately one MW. In New Jersey and Maryland, we market
electricity and energy services to commercial, industrial and institutional
customers.

6

Our commercial, industrial and institutional customers include refineries,
chemical plants, manufacturing facilities, hospitals, universities, governmental
agencies, restaurants and other facilities. In general, we sell electricity to
these customers at unregulated prices.

As of December 31, 2003, we had contracts to provide an aggregate of 5,735
MW of electricity to approximately 820 customers in Texas and an aggregate of
490 MW of electricity to approximately 120 customers in the PJM Market. The
terms of our contracts range from 1 to 51 months, with the average term being 21
months. We also provide customized energy solutions, including energy
information services and products, to our commercial, industrial and
institutional customers. For information regarding revenues from end-use retail
customers, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Retail Energy."

RETAIL ENERGY SUPPLY

In Texas, we must purchase from third parties substantially all of the
generation capacity necessary to supply our retail energy business. As of
February 20, 2004, we had entered into contracts to purchase generation capacity
averaging 9,944 MW per month in 2004, 2,914 MW per month in 2005 and 1,000 MW
per month in 2006. Based on current market conditions, existing retail sales
commitments and current load forecasts, we estimate that these contracts will
supply approximately 87% of the current capacity requirements of our retail
energy business for the remainder of 2004 and 47% of our estimated 2005
requirements.

The largest supplier of generation capacity for our Texas retail energy
business was Texas Genco. We expect to continue to contract with third parties,
including Texas Genco, for a significant portion of our Texas retail energy
business' power requirements, including purchases pursuant to power purchase
agreements and auctions of power conducted by Texas generation companies. In
addition, we may seek to supplement our market-based purchases of power over
time with the purchase of individual generation assets.

In January 2004, we elected not to exercise our option to purchase
CenterPoint's ownership interest in Texas Genco. For information regarding our
decision not to exercise the option to purchase CenterPoint's interest in Texas
Genco, see note 4 to our consolidated financial statements.

In states outside of Texas, we generate sufficient capacity to supply our
retail needs.

REGULATION

Texas Public Utility Commission. We are, through our operating
subsidiaries, certified to provide retail electric service to residential, small
commercial and large commercial, industrial and institutional customers in
Texas.

The Texas electric restructuring law currently regulates the prices at
which we can sell electricity to residential and small commercial customers.
Outside of the Houston area, we generally are permitted to sell electricity at
unregulated prices to these customers. However, in the Houston area, we can sell
electricity to residential customers only at a specified price, or
"price-to-beat." This requirement will continue until January 1, 2005, at which
time we will also be able to sell at prices other than the price-to-beat.
Starting January 1, 2007, we will be able to sell without pricing restrictions.

Prior to January 2004, we were required to sell electricity to small
commercial customers in the Houston area only at the price-to-beat. However,
that restriction has expired. We are now able to sell electricity without
pricing restrictions so long as we continue to make the price-to-beat available
as an alternative for Houston area customers until January 1, 2007. As of
December 31, 2003, the prices-to-beat for residential customers and small
commercial customers were 11.05 cents per KWh for a residential customer using
1,000 KWh per month and 8.54 cents per KWh for a small commercial customer using
15,000 KWh per month.

7

The price-to-beat includes a base rate component established by the PUCT in
1999 and an adjustable energy supply component or fuel factor. We can apply for
adjustments in the fuel factor twice a year based on changes in the average
12-month forward price of natural gas or changes in the price of purchased
energy. In 2003, we requested, and the PUCT approved, two adjustments to our
price-to-beat fuel factor resulting in an 18% increase of our residential
price-to-beat in that year. During 2002 and 2003, we requested, and the PUCT
approved, two adjustments in each period to our price-to-beat fuel factor as
follows:

In 2004, the PUCT will determine the "stranded costs" of Texas transmission
and distribution utilities in accordance with procedures established under the
Texas electric restructuring law. Following this determination, we expect that
the PUCT will review our price-to-beat. If at that time the average 12-month
forward price of natural gas is lower than the average price reflected in our
then current price-to-beat fuel factor, we expect the PUCT to lower our
price-to-beat fuel factor. In addition, we expect that the PUCT will adjust at
that time the base rate component of our price-to-beat that reflects the non-
bypassable rates that Texas transmission and distribution utilities charge us to
include any stranded cost charges. Non-bypassable rates include various fixed
charges established by the PUCT under the Texas electric restructuring law. We
estimate that the PUCT review of our price-to-beat will occur in the fourth
quarter of 2004 or the first quarter of 2005. We cannot, however, predict at
this time the outcome of the PUCT's review.

The Texas electric restructuring law requires that we make a payment to
CenterPoint unless, as of December 31, 2003, retail electric providers other
than us supplied 40% or more of the electricity consumed by Houston area
residential customers. We estimate the payment to be $175 million and expect
that the payment will be made in the fourth quarter of 2004. For information
regarding our accruals for this payment, see note 14(d) to our consolidated
financial statements.

ERCOT ISO. We are a member of ERCOT. Members of ERCOT include retail
customers, both investor and municipal owned electric utilities, rural electric
cooperatives, river authorities, independent generators, power marketers and
retail electric providers.

The ERCOT ISO is responsible for maintaining reliable operations of the
bulk electric power supply system in the ERCOT Region. Its responsibilities
include ensuring that information relating to a customer's choice of retail
electric provider is conveyed in a timely manner. It is also responsible for
ensuring that electricity production and delivery are accurately allocated and
settled among the generation resources and wholesale buyers and sellers in the
ERCOT Region.

For additional information regarding ERCOT, including information regarding
problems experienced in ERCOT information systems, see "Management's Discussion
and Analysis of Financial Condition and Results of Operations -- Risk Factors"
in Item 7 of this report.

Regulation in Other States. We are registered to sell electricity to
commercial, industrial and institutional customers in the District of Columbia,
New Jersey, Maryland and Pennsylvania. In each of these states, we are generally
permitted under local public utility commission regulations to sell electricity
at market rates.

8

COMPETITION

For information regarding competitive factors affecting our retail energy
segment, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Risk Factors" in Item 7 of this report.

WHOLESALE ENERGY

We have a portfolio of electric power generation facilities. Because our
facilities are not subject to traditional cost-based regulation, we can
generally sell electricity at market prices. We market electric energy, capacity
and ancillary services. We procure natural gas, coal, fuel oil, natural gas
transportation and storage capacity and other energy-related commodities to
supply and manage our physical assets. In March 2003, we discontinued our
proprietary trading business. Trading positions taken prior to our decision to
exit this business are managed solely for purposes of closing them on economical
terms.

As of December 31, 2003, we owned, had an interest in, or leased 124
operating electric power generation facilities with an aggregate net generating
capacity of 19,442 MW in six regions of the United States. The generating
capacity of our facilities consists of approximately 30% of base-load (5,910
MW), 40% of intermediate (7,689 MW) and 30% of peaking capacity (5,843 MW). As
of December 31, 2003, we had under construction 1,111 MW of additional base-load
net generating capacity. One facility under construction (591 MW) reached
commercial operation in February 2004. The other facility under construction is
expected to reach commercial operation in the third quarter of 2004.

In 2003, we sold one facility having a total net generating capacity of 588
MW and retired from service a total of five power-generating units having a
total net generating capacity of 579 MW. We currently have mothballed four units
having a total net generation capacity of 824 MW. In February 2004, we announced
our plans to mothball and/or retire an additional 20 generating units (727 MW)
from certain peaking plants and units that serve the PJM Market subject to a
review of certain reliability issues with regulators. Depending on future market
conditions in the wholesale power industry, we may sell, retire, mothball or
dispose of additional generation assets.

9

The following table describes our electric power generation facilities and
net generating capacity by region (excluding generation facilities that we
retired from service) as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

(2) We lease a 100%, 16.67% and 16.45% interest in three Pennsylvania facilities
having 614 MW, 1,704 MW and 1,714 MW of net generating capacity,
respectively, through facility lease agreements expiring in 2026, 2034 and
2034, respectively. The table includes our share of the capacity of these
facilities.

(3) We consider a project to be "under construction" once we have acquired the
necessary permits to begin construction, broken ground on the project site
and contracted to purchase machinery for the project, including the
combustion turbines and prior to the commencement of commercial operations.

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

(5) We own a 50% interest in one of these facilities having a net generating
capacity of 108 MW. An unaffiliated party owns the other 50%. The table
includes only our share of the capacity of this facility.

(6) We are party to tolling agreements entitling us to 100% of the capacity of
two Florida facilities having 630 MW and 474 MW of net generating capacity,
respectively. These tolling agreements expire in 2012 and 2007,
respectively, and are treated as operating leases for accounting purposes.

(7) We own a 50% interest in one Nevada facility having a net generating
capacity of 470 MW. An independent third party owns the other 50%. The table
includes our share of the capacity of this facility.

(8) Commenced commercial operation in February 2004.

10

The following table sets forth information regarding our generation output
by dispatch type, fuel type and capacity factor during 2002 and 2003:

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

(1) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

MID-ATLANTIC REGION

As of December 31, 2003, we owned, had an interest in, or leased 21
operating electric power generation facilities with an aggregate net generating
capacity of 5,393 MW located in Pennsylvania, New Jersey and Maryland. The
generating capacity of these facilities consists of approximately 34% of
base-load (1,863 MW), 42% of intermediate (2,243 MW) and 24% of peaking capacity
(1,287 MW).

We are constructing a 520 MW waste coal-fired base-load unit at an existing
facility located in Pennsylvania that is expected to reach commercial operations
in the third quarter of 2004. The 520 MW unit will replace two generating units
at the facility that were retired in 2003. The retired generating units had 197
MW of total net generating capacity.

11

The following table describes the electric power generation facilities we
owned, leased or had under construction in the Mid-Atlantic region (excluding
generation facilities that we retired from service) as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

(2) We announced in February 2004 that we intend to mothball this facility.

(3) We lease a 100% interest in the Shawville Station, a 16.67% interest in the
Keystone Station and a 16.45% interest in the Conemaugh Station under
facility interest lease agreements expiring in 2026, 2034 and 2034,
respectively. The table includes our share of the capacity of these
facilities.

(4) We announced in February 2004 that we intend to mothball approximately 111
MW of net generating capacity at this facility.

(5) PJM has informed us that, due to technical constraints within its
transmission system, our 866 MW generation facility located at Hunterstown,
Pennsylvania, cannot be dispatched during certain periods when high levels
of electricity are flowing on the central interface. These conditions are
generally experienced during periods of moderate electricity demands in the
midwest with higher electricity demands in the east. We are in discussions
with PJM and First EnergyCorp., the utility to which our plant
interconnects, concerning a resolution of this constraint.

(6) In the first quarter of 2004, we retired two units with a total net
generating capacity of 232 MW.

(7) We announced in February 2004 that we intend to retire this facility.

12

The following table sets forth information regarding our generation output
in the Mid-Atlantic region by dispatch type, fuel type and capacity factor
during 2002 and 2003:

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

(1) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

NEW YORK REGION

As of December 31, 2003, we owned 77 operating electric power generation
facilities with an aggregate net generating capacity of 2,932 MW located in New
York. Our generating facilities in the New York region consist of two distinct
groups: (a) intermediate and peaking facilities located in New York City and (b)
73 run-of-river hydro facilities and one gas-fired facility located in central
and northern New York State. The overall generating capacity of these facilities
consists of approximately 21% of base-load (624 MW), 41% of intermediate (1,204
MW) and 38% of peaking capacity (1,104 MW).

The following table describes the electric power generation facilities we
owned or leased in the New York region as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

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

13

The following table sets forth information regarding our generation output
in the New York region by dispatch type, fuel type and capacity factor during
2002 and 2003:

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

(1) Includes generation beginning in February 2002 in connection with our Orion
Power acquisition. See note 5 to our consolidated financial statements.

(2) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

MID-CONTINENT REGION

As of December 31, 2003, we owned nine electric power generation facilities
with an aggregate net generating capacity of 4,473 MW located in Illinois, Ohio,
Western Pennsylvania and West Virginia. The generating capacity of these
facilities consists of approximately 52% of base-load (2,303 MW), 6% of
intermediate (287 MW) and 42% of peaking capacity (1,883 MW).

The following table describes the electric power generation facilities we
owned in the Mid-Continent region as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

14

The following table sets forth information regarding our generation output
in the Mid-Continent region by dispatch type, fuel type and capacity factor
during 2002 and 2003:

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

(1) Includes generation beginning in February 2002 in connection with our Orion
Power acquisition. See note 5 to our consolidated financial statements.

(2) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

SOUTHEAST REGION

As of December 31, 2003, we owned, or had an interest in, six power
generation facilities with an aggregate net generating capacity of 3,010 MW
located in Florida, Mississippi and Texas. Our interest in two of these
facilities (1,104 MW) is in the form of a long-term tolling agreement, as
described in more detail below. The generating capacity of these facilities
consists of approximately 2% of base-load (54 MW), 46% of intermediate (1,387
MW) and 52% of peaking capacity (1,569 MW).

The following table describes the electric power generation facilities we
owned or had an interest in the Southeast region of the United States (excluding
generation facilities that we retired from service) as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

(2) We own a 50% interest in this facility, which has a net generating capacity
of 108 MW. An unaffiliated party owns the other 50%. The table includes only
our share of the capacity of the facility.

(3) We are party to tolling agreements entitling us to 100% of the capacity of
two Florida facilities having 474 MW and 630 MW of net generating capacity,
respectively. These tolling agreements have terms expiring in 2007 and 2012,
respectively, and are treated as operating leases for accounting purposes.

15

The following table sets forth information regarding our generation output
in the Southeast region by dispatch type, fuel type and capacity factor during
2002 and 2003:

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

(1) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

WEST REGION

As of December 31, 2003, we owned, or had an interest in, four operating
electric power generation facilities with an aggregate net generating capacity
of 2,803 MW located in California and Nevada. We have mothballed four units in
this region with an aggregate net generating capacity of 824 MW. The operating
generating capacity of these facilities consists of approximately 8% of
base-load (235 MW), 85% of intermediate (2,384 MW) and 7% of peaking capacity
(184 MW). As of December 31, 2003, we were constructing a 591 MW gas-fired,
base-load and intermediate generation facility in southern Nevada, which
commenced commercial operation in February 2004.

In October 2003, we closed the sale of our 588 MW Desert Basin plant
operations to SRP. See note 23 to our consolidated financial statements.

16

The following table describes the electric power generation facilities we
owned or had under construction in the West region (excluding generation
facilities that we retired from service) as of December 31, 2003:

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

(1) Excludes volumes related to our Desert Basin plant, which was sold in
October 2003 and is classified as discontinued operations. See note 23 to
our consolidated financial statements.

(2) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

17

ERCOT REGION

As of December 31, 2003, we owned seven power generation facilities with an
aggregate net generating capacity of 831 MW located in Texas.

The following table describes the electric power generation facilities we
owned in the ERCOT Region as of December 31, 2003:

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

(1) Generating capacity refers to the average of the facilities' summer and
winter generating capacities net of auxiliary power.

(2) Landfill gas represents six small facilities located in the Houston area
that collect gas emitted from landfills and convert it into electricity.

The following table sets forth information regarding our generation output
in the ERCOT Region by dispatch type, fuel type and capacity factor during 2002
and 2003:

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

(1) Capacity factor is the ratio of the actual net electricity generated to the
energy that could have been generated at continuous full-power operation
during the year.

COMMERCIAL OPERATIONS

Energy. We sell electric energy, generation capacity and ancillary service
products to a variety of power customers including investor-owned utilities,
municipalities, cooperatives and other companies that serve end users. We sell
these products in hour-ahead, day-ahead, forward bilateral and ISO markets. The
following table identifies the principal markets associated with each of our
regional generation assets:

18

Certain of our principal markets (most notably New York and the PJM Market)
have rules that, in certain instances, may impose limits or caps on the price at
which we can sell electricity. In addition, the market authorities in certain
regions have the authority to compel us to operate our generation facilities in
order to maintain the reliability of the local grid system. Under these
circumstances, we are entitled to receive a "mitigated price" for electricity
dispatched into the system that is intended to enable us to recoup our
incremental operating costs plus a designated surcharge.

In addition to standard market products, we also provide full requirements,
POLR, and basic generation service contracts. These non-standard contracts
afford higher margin opportunities than standard market products; however, they
include additional risks that we may not be able to mitigate. These risks are
primarily volumetric uncertainty driven by weather and customer switching. For
information regarding long-term sales arrangements for electric energy, capacity
and ancillary services, see note 14(f) to our consolidated financial statements.

Fuel. To ensure an adequate supply of fuel, we purchase natural gas, coal
and fuel oil for our generation plants from a variety of suppliers under daily,
monthly and forward contracts. These contracts generally include either index or
fixed price provisions. In connection with the operation of our natural gas-
fired plants, we also arrange for, schedule and balance natural gas from our
suppliers and through transporting pipelines. To perform these functions, and
satisfy our electric generation needs, we contract for a variety of
transportation arrangements under short-term, long-term, firm and interruptible
agreements with pipelines and storage facilities. In spite of our efforts, any
given facility may experience supply constraints from time to time.

Risk Management. To manage the risk of our assets we seek to sell energy
and purchase fuel on a forward basis through fixed price or tolling contracts.
We are required, by policy, to maintain a "one-for-one" balance between the
amount of required fuel for each megawatt of power sold off our gas generation
assets. We have similar "one-for-one" hedging policies for the hedging of
certain pipeline and storage positions.

Although we enter into hedging activities related to our generation
facilities, pipelines and storage positions, we do not engage in proprietary
trading with respect to power, fuel, emissions or any other energy commodities.
With respect to positions taken prior to our decision in 2003 to exit
proprietary trading, we are managing such positions solely for the purpose of
closing such positions on economical terms.

REGULATION

Electricity. The FERC has exclusive ratemaking jurisdiction over wholesale
sales of electricity and the transmission of electricity in interstate commerce
by "public utilities." Public utilities that are subject to the FERC's
jurisdiction must file rates with the FERC. The FERC has authorized our
generation subsidiaries to sell electricity and certain related services at
wholesale under market-based rates. In addition, certain ancillary services are
sold at cost-base rates.

Under certain circumstances, the FERC can revoke or limit market-based rate
authority. If the FERC revokes or limits market-based rate authority, the
affected party would be required to obtain approval from the FERC of cost-based
rate schedules in order to make wholesale sales. In addition, the loss of
market-based rate authority could subject the affected party to the accounting,
record keeping and reporting requirements that the FERC imposes on public
utilities with cost-based rate schedules.

In November 2003, the FERC issued new rules intended to prevent market
abuse. The new rules address market manipulation and other abusive practices.
Under the rules, parties found to have engaged in prohibited behavior are
subject to disgorgement of unjust profits and possible revocation of their
market-based rate authority.

The FERC has issued a notice of proposed rules intended to standardize
electricity markets and eliminate discrimination in transmission service by
requiring that all users of the transmission grid take service pursuant to the
same terms and conditions of service, thus eliminating certain preferences
enjoyed
19

by classes of users. The new rules would require transmission-owning public
utilities to join an ISO or RTO. In addition, the FERC seeks to establish
day-ahead and real-time electric energy and ancillary service markets modeled
after the energy markets that currently exist in the northeastern United States.
The rules contemplate the regional adoption of resource adequacy measures and
regional price mitigation measures. It is not possible for us at this time to
predict the timing of the implementation of these rules or their ultimate impact
on our business.

Gas Activities. The FERC has issued a blanket certificate permitting us to
sell natural gas in interstate commerce in connection with the management of our
natural gas positions.

Hydroelectric Facilities. We operate our hydroelectric generation
facilities pursuant to FERC licenses. These licenses, which periodically must be
renewed, typically include conditions regarding the operation of the facility.

SEC. A company engaged exclusively in the business of owning and/or
operating facilities used for the generation of electric energy exclusively for
sale at wholesale and selling electric energy at wholesale may be exempted from
regulation under the PUHCA as an exempt wholesale generator. Our electric
generation subsidiaries either have received determinations of exempt wholesale
generator status from the FERC or are companies that own or operate qualifying
facilities that are exempt from PUHCA. If any of our subsidiaries lose their
exempt wholesale generator status or qualifying facility status, we would have
to restructure our organization or risk being subjected to further regulation by
the SEC.

COMPETITION

For a discussion of competitive factors affecting our wholesale energy
segment, see "Management's Discussion and Analysis of Financial Condition and
Results of Operations -- Risk Factors" in Item 7 of this report.

OTHER OPERATIONS

Our other operations business segment includes primarily unallocated
corporate costs and our minor equity and other investments. As of December 31,
2003, the net book value of these investments was $32 million. Our activities
with respect to these investments are limited to managing and, in some cases,
liquidating our existing portfolio. We have no plans to expand this business.
For additional information regarding this segment, see note 21 to our
consolidated financial statements.

ENVIRONMENTAL MATTERS

We are subject to numerous federal, state and local requirements relating
to the protection of the environment and the safety and health of personnel and
the public. These requirements relate to a broad range of our activities,
including the discharge of compounds into the air, water and soil; the proper
handling of solid, hazardous and toxic materials and waste, noise and safety and
health standards applicable to the workplace. Environmental regulations
affecting us include, but are not limited to:

- The Clean Air Act and the 1990 amendments to the Act, as well as state
laws and regulations impacting air emissions, including State
Implementation Plans related to existing and new national ambient air
quality standards for ozone and fine particulate matter. Owners and/or
operators of air emissions sources are responsible for obtaining permits,
compliance and reporting.

- The Federal Water Pollution Control Act, which requires permits for
facilities that discharge treated wastewater into the environment.

- CERCLA, which can require any individual or entity that may have owned or
operated a disposal site, as well as transporters or generators of
hazardous wastes sent to such site, to share in remediation costs.

20

- The Solid Waste Disposal Act, as amended by the Resource Conservation and
Recovery Act, which requires certain solid wastes, including hazardous
wastes, to be managed pursuant to a comprehensive regulatory regime.

- The National Environmental Policy Act, which requires consideration of
potential environmental impacts by federal agencies in their decisions,
including siting approvals.

- The FERC, which regulates the approval and re-licensing of hydroelectric
facilities.

In order to comply with these requirements, we will, as necessary, spend
substantial funds to construct, modify and retrofit equipment, and clean up or
decommission disposal or fuel storage areas and other locations as necessary. We
anticipate spending approximately $178 million from 2004 through 2008 for
environmental compliance of which $16 million is for remediation. For more
information on environmental matters involving us, including possible liability
and capital costs, see note 15(a) to our consolidated financial statements.

AIR QUALITY MATTERS

The Federal Clean Air Act requires the EPA to define standards for air
quality that are protective of public health. As a result of setting these
standards, the EPA has implemented a number of emission control programs that
affect industrial sources including power plants. In addition, the 1990
Amendments to the Clean Air Act directed EPA to implement programs designed to
control acidic deposition (acid rain), improve visibility in the United States'
pristine areas and national parks (regional haze), and reduce emissions of
hazardous air pollutants.

REGULATION OF NO(X) AND SO(2) EMISSIONS

As a result of the mandates of the Clean Air Act, the EPA has implemented
programs limiting emissions of NO(x) and SO(2), both of which are compounds that
result from the combustion of fossil fuels. NO(x) is a precursor to the
formation of ozone, acid rain, fine particulate matter, and regional haze. SO(2)
is a precursor to the formation of acid rain, fine particulate matter, and
regional haze. In addition to regulations already implemented, the EPA in
December 2003 proposed a new regulation to control emissions of NO(x) and SO(2)
on a broad scale. This new proposed regulation is referred to as the Interstate
Air Quality Rule, and will affect our power generating facilities in the eastern
United States and Texas.

The Interstate Air Quality Rule would require reductions in NO(x) and SO(2)
beyond levels already required in existing federal programs in 29 states in the
eastern United States. The proposed rules will require reductions of NO(x) and
SO(2) in two phases. Although the final form of the proposed regulations is not
yet known, the first phase, which takes effect in 2010, would require
approximately a 50% reduction in SO(2) and NO(x) emissions on an annual basis.
The second phase, which would take effect in 2015, would require approximately a
70% reduction in SO(2) and NO(x) on an annual basis. These reductions would be
achieved through a trading program, allowing reductions to be made at the most
economical locations, and not requiring reductions on a facility-by-facility
basis. The proposed rules would affect primarily our facilities in the eastern
United States (particularly the coal-fired facilities) and Texas. We are unable
at this time to estimate the potential impact on the future operations of our
generation facilities.

REGULATION OF EMISSIONS OF MERCURY AND OTHER HAZARDOUS AIR POLLUTANTS

In December 2003, the EPA also proposed two regulations to control
emissions of mercury from coal-fired power plants in the United States. Only one
of these two regulations will ultimately be adopted in December 2004. The MACT
standard would require reductions on a facility-by-facility basis regardless of
cost. The MACT rule would require reductions to be achieved by 2008. The other
rule, referred to as the cap-and-trade rule, would effect the emission
reductions on a national scale through a trading program, allowing reductions to
be made at the most economical locations, and not requiring reductions on a
facility-by-facility basis. Although the final form of these proposed
regulations is not yet known, the MACT standard would require a reduction of
about 30% from each of our coal fired facilities, which

21

would require the installation of control equipment. The cap-and-trade rule
would require larger reductions, but may be more economical because it allows
trading of emissions among facilities. Like the Interstate Air Quality Rule, the
mercury cap-and-trade rule would be accomplished in two phases, in 2010 and
2018, with reduction levels set at approximately 50% and 70%, respectively. If
the cap-and-trade rule were ultimately adopted, our approach would be to balance
capital expenditures for controls and reliance on allowance markets to achieve
compliance. We are unable at this time to estimate the potential impact on the
future operations of our generation facilities.

In addition to mercury control from coal-fired boilers, the MACT rule, if
adopted, would require the control of nickel emissions from oil-fired
facilities. While the final form of these provisions is uncertain, we do not
expect this provision of the MACT to have a material impact on our operations
since only a small number of our facilities are oil-fired.

The EPA has also proposed or issued MACT standards for sources other than
boilers used for power generation. The MACT rule for combustion turbines was
issued in August 2003 and there is no material impact on existing facilities. We
expect the MACT rulemaking for engines and industrial boilers to be finalized in
early 2004. Based on the current form of the proposed rules for these source
types, we do not anticipate that the rules, if adopted, will have a material
impact on our operations.

CLEAR SKIES ACT

In February 2002, the White House announced its "Clear Skies Initiative".
The proposal is aimed at long-term reductions of multiple pollutants produced
from fossil fuel-fired power plants. Reductions averaging 70% are targeted for
sulfur dioxide, nitrogen oxide and mercury. If approved by the United States
Congress, this program would entail a market-based approach using emission
allowances; compliance with emission limits would be phased in over a period
from 2008 to 2018. The Clear Skies Initiative is similar to the proposed
Interstate Air Quality rule and mercury MACT/cap-and-trade rule.

AIR QUALITY ENFORCEMENT ISSUES

The EPA is conducting a nationwide investigation regarding the historical
compliance of coal-fueled electric generating stations with various permitting
requirements of the Clean Air Act. Specifically, the EPA and the United States
Department of Justice have initiated formal enforcement actions and litigation
against several other utility companies that operate these stations, alleging
that these companies modified their facilities without proper pre-construction
permit authority. Since June 1998, eight of our coal-fired facilities have
received requests for information related to work activities conducted at those
sites. The EPA has not filed an enforcement action or initiated litigation in
connection with these facilities at this time. Nevertheless, any litigation, if
pursued successfully by the EPA, could accelerate the timing of emission
reductions anticipated as a result of proposed regulations, and result in the
imposition of penalties.

The New Jersey Department of Environmental Protection has requested a copy
of all correspondence relating to one of the eight stations from the EPA. The
EPA has also agreed to provide information relating to the New Source Review
investigations discussed above to the New York state attorney general's office
and the Pennsylvania Department of Environmental Protection.

GREENHOUSE GAS EMISSIONS

The Kyoto Protocol, which may become effective in 2004, if ratified by a
sufficient number of nations, would require ratifying nations to achieve
substantial reductions of CO(2) and certain other greenhouse gases between 2008
and 2012. Although the current United States government has indicated that it
does not intend to ratify the treaty at this time, any future limitations on
power plant carbon dioxide emissions could have a material impact on all fossil
fuel fired facilities, including those belonging to us.

There continues to be a debate within the United States over the direction
of domestic climate change policy. The United States Congress is currently
considering several bills that would impose

22

mandatory limitation of CO(2) emissions for the domestic power generation
sector, and several other states, primarily in the northeastern United States,
are considering state-specific or regional legislation initiatives to stimulate
CO(2) emission reductions in the electric utility industry. The specific impact
will depend upon the form of emissions-related legislation or regulations
ultimately adopted by the federal government or states in which our facilities
are located.

In recent years, we have instituted or participated in numerous proactive
projects and programs that go beyond regulatory compliance requirements in an
effort to reduce and remove greenhouse gas emissions. These effective actions
include:

- Participation in the Power Partners Program, designed to encourage and
facilitate industry actions to reduce greenhouse gas intensity as
outlined in President Bush's voluntary global climate change initiative;

- Participation in PowerTree, an entity comprised of a diverse group of
power generators that endeavors to remove CO(2) emissions through
large-scale reforestation projects;

- Independent establishment of a 540-acre arboreal preserve in east Texas
to remove emissions;

- Operation of renewable energy facilities, including, hydro-electric and
landfill gas-to-energy facilities; and

- Recent retirement of CO(2) producing facilities in California, New Jersey
and Pennsylvania.

WATER QUALITY MATTERS

The EPA and states periodically revise water quality criteria and initiate
total maximum daily load determinations under the Clean Water Act. These actions
may result in more stringent wastewater discharge limitations for our power
plants and the need to install additional water treatment systems or control
measures.

On February 16, 2004, the EPA signed final regulations relating to the
design and operation of cooling water intake structures at existing power
plants. While there may be significant compliance costs associated with this
rule, site-specific evaluation of compliance alternatives will be required to
determine the magnitude of those potential costs.

FERC MATTERS

In the course of the FERC licensing proceedings various agencies have
requested increased flow rates downstream of our hydroelectric dams in order to
enhance fish habitats and for other purposes. The FERC has imposed conditions in
the new licenses to increase such flow rates and we expect that the FERC will
also impose similar conditions in the licenses for which applications remain
pending. Increased flow rates may affect revenues for these facilities due to
the loss of use of water for power generation. We do not, however, expect such
lost revenues to be material to the economic viability of such facilities.

OTHER

As a result of their age, many of our facilities contain significant
amounts of asbestos insulation, other asbestos containing materials, as well as
lead-based paint. Existing state and federal rules require the proper management
and disposal of these potentially toxic materials. We have developed a
management plan that includes proper maintenance of existing non-friable
asbestos installations, and removal and abatement of asbestos containing
materials where necessary. We have planned for the proper management, abatement
and disposal of asbestos and lead-based paint at our facilities in our financial
planning.

Under CERCLA and similar state laws, owners and operators of facilities
from or at which there has been a release or threatened release of hazardous
substances, together with those who have transported or arranged for the
disposal of those substances, are liable for the costs of responding to that
release or threatened release, and the restoration of natural resources damaged
by any such release. We are not

23

aware of any liabilities under the act that would have a material adverse effect
on our results of operations, financial position or cash flows.

For information regarding plant remediation activities, see note 15(a) to
our consolidated financial statements.

EMPLOYEES

As of December 31, 2003, we had 5,293 full-time employees. Of these
employees, 1,434 are covered by collective bargaining agreements. The collective
bargaining agreements expire on various dates until April 2008. In 2004, three
of the collective bargaining agreements applicable to certain employees
associated with our facilities in the Mid-Atlantic, New York and Mid-Continent
regions are expected to expire. The following table sets forth the number of our
employees by business segment as of December 31, 2003:

EXECUTIVE OFFICERS

The following table lists our executive officers:

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

(1) Age is as of March 1, 2004.

JOEL V. STAFF has served as our Chairman and Chief Executive Officer since
April 2003. He has served as a Director since October 2002. From May 2001 to May
2002, he was Executive Chairman of National-Oilwell, Inc. From July 1993 to May
2001, Mr. Staff served as Chairman, President and Chief Executive Officer of
National-Oilwell, Inc. He also serves on the board of directors of
National-Oilwell, Inc. and Ensco International, Incorporated.

24

ROBERT W. HARVEY has served as our Executive Vice President, Power
Generation and Supply since January 2004. He served as our Executive Vice
President and Group President, Wholesale from May 2003 to January 2004. He
served as our Executive Vice President and Group President, Retail from January
2002 to May 2003. Mr. Harvey served as Vice Chairman of CenterPoint from June
1999 until the Distribution. From 1982 to June 1999, Mr. Harvey was with the
Houston office of McKinsey & Company. He was a director (senior partner) of the
firm and was the leader of the firm's North American electric power and natural
gas practice.

MARK M. JACOBS has served as our Executive Vice President and Chief
Financial Officer since the Distribution. He served as Executive Vice President
and Chief Financial Officer of CenterPoint from July 2002 until the
Distribution. Mr. Jacobs was employed by Goldman, Sachs & Co. from 1989 to 2002.
He was a Managing Director in the firm's Natural Resources Group.

JERRY J. LANGDON has served as our Executive Vice President, Public and
Regulatory Affairs and Corporate Compliance Officer since January 2004. He
served as our Executive Vice President and Chief Administrative Officer from May
2003 to January 2004. Prior to joining Reliant Resources, Mr. Langdon served as
President of EPGT Texas Pipeline, L.P. from June 2001 until May 2003. He served
as the Managing Partner and Chief Operating Officer of CARLANG Partners, L.P.

KAREN DYSON has served as our Senior Vice President, Human Resources and
Administration since December 2003. She served as Vice President, Human
Resources from February 2003 to December 2003, Vice President, Administration,
Wholesale Group from October 1998 to February 2003 and Vice President, Planning
and Procurement for the former Reliant Energy Trading and Transportation from
February 1996 to October 1998.

MICHAEL L. JINES has served as our Senior Vice President, General Counsel
and Corporate Secretary since May 2003. He served as our Deputy General Counsel
and Senior Vice President and General Counsel, Wholesale Group from March 2002
to May 2003. Mr. Jines served as Deputy General Counsel of Reliant Energy and
Senior Vice President and General Counsel of our Wholesale Group until the
Distribution.

SUZANNE L. KUPIEC has served as our Senior Vice President, Risk and
Structuring since January 2004. She served as our Vice President and Chief Risk
and Corporate Compliance Officer from June 2003 to January 2004. Prior to
joining Reliant Resources, Ms. Kupiec was a partner at Ernst & Young, LLP,
leading the firm's Energy Trading and Risk Management Practice serving both
audit and advisory service clients. Ms. Kupiec was a firm specialist in the use
of financial instruments and complex derivatives for the energy industry.

BRIAN LANDRUM has served as our Senior Vice President, Customer Operations
and Information Technology since January 2004. He was our President, Reliant
Energy Retail Services from June 2003 to January 2004, Senior Vice President,
Retail Operations from August 2001 to May 2003, and Vice President, Internet and
Ebusiness from November 1999 to August 2001. Before joining Reliant Resources,
Mr. Landrum was employed at Compaq Computer Corporation as General Manager of
its Worldwide Commercial Displays business unit.

JAMES B. ROBB has served as our Senior Vice President, Retail Marketing
since January 2004. He served as our Senior Vice President, Performance
Management from November 2002 to January 2004. Prior to joining Reliant
Resources, Mr. Robb was a partner with McKinsey & Company in San Francisco,
California and Seattle, Washington, focusing on service to energy and natural
resources clients on issues related to corporate and business unit strategy and
fundamental performance improvement. He led McKinsey & Company's West Coast
Energy and Resources Practice from 1998 until 2002.

THOMAS C. LIVENGOOD has served as our Vice President and Controller since
August 2002. From 1996 to August 2002, he served as Executive Vice President and
Chief Financial Officer of Carriage Services, Inc.

25

AVAILABLE INFORMATION

Our executive offices are located at 1000 Main, Houston, Texas 77002
(telephone number is 713-497-7000).

We make available free of charge on our website
(http://www.reliantresources.com):

- our corporate governance guidelines;

- our audit committee, compensation committee, and nominating and corporate
governance committee charters;

- our annual reports on Form 10-K, quarterly reports on Form 10-Q, current
reports on Form 8-K and amendments to those reports; and

- our business ethics policy and any amendments to, or waivers from, a
provision of our policy that applies to our principal executive officer,
principal financial officer, principal accounting officer or controller,
or persons performing similar functions.

Additionally, you may request a copy of any of these items, at no cost, by
writing or telephoning us at the address or number above and requesting the
investor relations department. Annual reports, quarterly reports and current
reports are made available on our website as soon as reasonably practicable
after we file such reports with, or furnish them, to the SEC.

STOCKHOLDER COMMUNICATIONS WITH THE BOARD OF DIRECTORS

We have established several means for stockholders or others to communicate
their concerns to the Board of Directors.

- If the concern relates to our financial statements, accounting practices
or internal controls, the concern should be submitted in writing to the
Chairman of the Audit Committee in care of the following address:

Reliant Resources Compliance Hotline
P.M.B. 3767
Pinkerton Compliance Services
13950 Ballantyne Corporate Place
Charlotte, North Carolina 28277

- If the concern relates to our governance practices, business ethics or
corporate conduct, the concern may be submitted in writing to the
Chairman of the Nominating & Governance Committee in care of our
Corporate Secretary at 1000 Main, Houston, Texas 77002. If the
stockholder is unsure as to which category his or her concern relates, he
or she may communicate it to any one of the independent directors in care
of the Corporate Secretary.

- Our "whistleblower" policy prohibits us or any of our employees from
retaliating or taking any adverse action against anyone for raising a
concern. We have established and published on our website mailing and
e-mail addresses and a 24-hour, toll-free telephone hotline for receiving
complaints regarding accounting issues from employees and others. The
mailing address is:

Corporate Compliance Officer
Reliant Resources, Inc.
P.O. Box 1384
Houston, Texas 77251-1384

The email address is: CORPCOMOFFICER@RELIANT.COM.

26

ITEM 2. PROPERTIES.

Our corporate offices occupy approximately 520,000 square feet of leased
office space in Houston, Texas. Our lease expires in 2018, subject to two
five-year renewal options.

In addition to our corporate offices, we lease or own various real property
and facilities relating to our generation assets, retail operations and retail
activities. Our principal generation facilities are generally described under
"Our Business -- Wholesale Energy" in Item 1 of this report. We believe we have
satisfactory title to our facilities in accordance with standards generally
accepted in the electric power industry, subject to exceptions, which, in our
opinion, would not have a material adverse effect on the use or value of the
facilities.

ITEM 3. LEGAL PROCEEDINGS.

For a description of certain legal and regulatory proceedings affecting us,
see note 15 to our consolidated financial statements.

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

No matters were submitted to a vote of our security holders during the
fourth quarter of the year ended December 31, 2003.

PART II

ITEM 5. MARKET FOR OUR COMMON EQUITY AND RELATED STOCKHOLDER MATTERS.

As of March 1, 2004, our common stock was held by approximately 50,426
stockholders of record. Our common stock is listed on the New York Stock
Exchange and is traded under the symbol "RRI." The following table sets forth
the high and low sales prices of our common stock on the New York Stock Exchange
composite tape during the periods indicated, as reported by Bloomberg:

The closing market price of our common stock on December 31, 2003 was $7.36
per share.

We have not paid or declared any dividends since our formation and do not
currently intend to pay or declare any dividends in the immediate future. Any
future dividends will be subject to determination based upon our results of
operations and financial condition, our future business prospects, any
applicable contractual restrictions, including the restriction on our ability to
pay dividends under our March 2003 credit facilities and our senior secured
notes and other factors that our board of directors considers relevant.

Sales of Unregistered Securities. In June and July 2003, we sold $275
million of our convertible senior subordinated notes in a private placement
pursuant to Rule 144A and Regulation S to qualified

27

institutional buyers. The primary underwriters were Banc of America Securities
LLC, Deutsche Bank Securities Inc. and Goldman Sachs & Co. We received net
proceeds of $266 million, which we ultimately used to prepay debt under our
March 2003 credit facilities. In December 2003, we registered these convertible
senior subordinated notes and the common stock issuable upon conversion in order
that the original holders may transfer such securities. In July 2003, we sold
$1.1 billion of our senior secured notes in a private placement pursuant to Rule
144A and Regulation S to qualified institutional buyers. The primary
underwriters were Banc of America Securities LLC, Deutsche Bank Securities Inc.,
Goldman Sachs & Co. and Barclays Capital Inc. We received net proceeds of $1.056
billion, which we used to prepay $1.056 billion of senior secured term loans
under our March 2003 credit facilities. In January 2004, we exchanged these
senior secured notes for registered notes that were identical in all material
respects, but did not contain terms restricting their transfer. See note 9 to
our consolidated financial statements.

28

ITEM 6. SELECTED FINANCIAL DATA.

The following tables present our selected consolidated financial data for
1999 through 2003. The data set forth below should be read together with
"Management's Discussion and Analysis of Financial Condition and Results of
Operations," our historical consolidated financial statements and the notes to
those statements included in this report. The historical financial information
may not be indicative of our future performance and does not reflect what our
financial position and results of operations would have been had we operated as
a separate, stand-alone entity prior to September 30, 2002, when CenterPoint
ceased to be our parent company. See note 1 to our consolidated financial
statements. The financial data for 1999 and 2000 are derived from the
consolidated historical financial statements of CenterPoint.

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

(1) Our results of operations include the results of the following acquisitions,
all of which were accounted for using the purchase method of accounting,
from their respective acquisition dates: a generating facility in Florida
acquired in October 1999, the REMA acquisition that occurred in May 2000 and
the Orion Power acquisition that occurred in February 2002. See note 5 to
our consolidated financial statements for further information about the
Orion Power acquisition. In December 2003, we sold our European energy
operations. In the first quarter of 2003, we began to report the results of
our European energy operations as discontinued operations in accordance with
SFAS No. 144 and accordingly, reclassified amounts from prior periods. See
note 22 to our consolidated financial statements. In October 2003, we sold
our Desert Basin plant operations and in accordance with SFAS No. 144,
effective July 2003, we began to report the results of our Desert Basin
plant operations as discontinued operations and accordingly, reclassified
amounts from prior periods. See note 23 to our consolidated financial
statements.

(2) Effective January 1, 2001, we adopted SFAS No. 133 which established
accounting and reporting standards for derivative instruments. See notes
2(d) and 7 to our consolidated financial statements.

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

(4) We adopted EITF No. 02-03 effective January 1, 2003, which affected our
accounting for electricity sales to large commercial, industrial and
institutional customers under executed contracts and our accounting for
trading and hedging activities. It also impacted these contracts executed
after October 25, 2002 in 2002. See note 2(d) to our consolidated financial
statements.

(5) During the third quarter of 2003, we performed a goodwill impairment
analysis of our wholesale energy reporting unit and recognized an impairment
charge of $985 million. See note 6 to our consolidated financial statements.

(6) In July 2003, the EITF issued EITF No. 03-11, which became effective October
1, 2003. At that time, we began reporting prospectively the settlement of
sales and purchases of fuel and purchased power related to our non-trading
commodity derivative

31

activities that were not physically delivered on a net basis in our results
of operations based on the item hedged pursuant to EITF No. 03-11. This
resulted in decreased revenues and decreased fuel and cost of gas sold and
purchased power of $834 million for the fourth quarter of 2003. We believe
the application of EITF No. 03-11 will continue to result in a significant
amount of our non-trading commodity derivative activities being reported on
a net basis prospectively that were previously reported on a gross basis. We
did not reclassify amounts for periods prior to October 1, 2003. See note
2(d) to our consolidated financial statements.

(7) These amounts exclude volumes associated with our Desert Basin plant
operations and our European energy operations, which are classified as
discontinued operations.

(8) Includes physically delivered volumes, physical transactions that are
settled prior to delivery and non-trading derivative activity related to our
power generation portfolio.

(9) 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. As a result,
as of January 1, 2003, we increased our property, plant and equipment by
$1.3 billion and increased our secured debt obligations by $1.3 billion. See
notes 2(c), 9(a) and 14(b) to our consolidated financial statements.

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS
OF OPERATIONS.

OVERVIEW

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. Our
segments include retail energy, wholesale energy and other operations. For
additional information about our segments, see "Business" in Item 1 of this
report and note 21 to our consolidated financial statements.

We have three key objectives and strategies:

- We seek to be a highly efficient, customer-focused competitor. To achieve
this objective, we intend to (a) effect significant reductions in our
overhead and operating costs, (b) implement process efficiencies and
reduce costs, (c) mothball/retire marginal assets and (d) establish an
environment conducive to the development of a highly focused and
motivated team.

- We intend to strengthen our balance sheet by (a) enhancing our
profitability, (b) divesting non-strategic assets and (c) accessing the
capital markets to repay bank debt with the proceeds from offerings of
fixed income or equity securities.

- In order to capitalize on our competitive advantages, we intend to focus
on regions where we believe the rules support competitive markets, to
link our generation assets to customer loads and to capitalize on our
unique retail skill set.

Our ability to achieve our strategies and objectives are subject to a
number of factors some of which we may not be able to control. See "Cautionary
Statement Regarding Forward-Looking Information" and "-- Risk Factors."

In 2003 and 2004, we have taken a number of actions intended to reduce our
debt, strengthen our balance sheet and allow us to focus on our core
business -- generating, supplying and marketing electricity to customers.

- In March 2003, we discontinued our proprietary trading activities (see
note 7(b) to our consolidated financial statements).

- In March 2003, we refinanced $5.9 billion of bank credit facilities with
new facilities that mature in approximately four years (see note 9(a) to
our consolidated financial statements).

- In June and July 2003, we issued $1.1 billion in senior secured notes and
$275 million in convertible senior subordinated notes and used the net
proceeds of the senior secured notes to prepay debt thereby satisfying
the only mandatory principal payment required under our March 2003 credit
facilities prior to maturity.

32

- In August 2003, we reviewed our internal cost structure and identified
$140 million of annualized savings opportunities of which $25 million was
realized in 2003 and $125 million is expected to be realized in 2004.

- As part of our ongoing evaluation of our wholesale energy business, we
(a) recognized an impairment of $985 million of goodwill in this segment,
(b) retired 489 MW of plant assets and mothballed 824 MW of plant assets
in 2003 that no longer made economic sense to currently operate and (c)
sold our 588 MW Desert Basin plant operations and recorded an after-tax
loss on the sale of $75 million (see notes 6 and 23 to our consolidated
financial statements). In February 2004, we announced our plans to
mothball and/or retire an additional 727 MW from certain peaking plants
and units that serve the PJM Market subject to a review of certain
reliability issues with regulators.

- We (a) settled investigations by the CFTC relating to certain trading and
price reporting issues, (b) settled all inquiries, investigations and
proceedings instituted by the FERC involving us in connection with the
FERC's ongoing review of western energy markets (except the pending FERC
refund proceeding) and (c) settled an investigation by the SEC concerning
allegations of violations of federal securities law. See note 15 to our
consolidated financial statements.

- In December 2003, we completed the sale of our European energy operations
(and recognized a loss on sale of $310 million) in order to reduce debt
and allow us to focus exclusively on our United States operations (see
note 22 to our consolidated financial statements).

- In December 2003, we finalized a second amendment to our March 2003
credit facilities. In connection with the amendment, we used $917 million
that had accumulated in an escrow account, including (a) the net sale
proceeds of our Desert Basin plant, (b) a portion of the net sale
proceeds of our European energy operations and (c) the net proceeds of
our convertible senior subordinated notes to prepay debt under our March
2003 credit facilities. The amendment will give us greater flexibility to
purchase selected generating assets to support our retail business in
Texas. In connection with this amendment, we also canceled our $300
million senior priority facility. See note 9(a) to our consolidated
financial statements.

- In January 2004, we made the decision to not exercise our option to
purchase CenterPoint's 81% ownership interest in Texas Genco in favor of
pursuing a strategy of contracting for a significant portion of our
retail energy supply requirements, and over time, pursuing potential
acquisitions of individual generation assets.

- Consistent with our business objectives and strategies, in February 2004
we announced that we intend to reduce our net debt-to-adjusted EBITDA
ratio significantly by the end of 2006. Consistent with this plan, we
have targeted an additional $200 million in cost reductions. These
reductions are in addition to our $140 million cost reduction plan
discussed above.

Although we have taken a number of actions in 2003 and early 2004 to
restructure our business to meet current market conditions, we continue to face
a number of near and long-term challenges. The operations of our wholesale
energy segment continue to be negatively affected by depressed market
conditions. These, and other factors, are discussed in more detail in "-- Risk
Factors" and other sections below.

As part of our efforts to simplify the corporate structure to reflect a
single operating company, we are evaluating a possible change in our reportable
segments in future reporting periods.

33

CONSOLIDATED RESULTS OF OPERATIONS

2003 COMPARED TO 2002

Net Loss. We reported $1.3 billion consolidated net loss, or $4.57 loss
per share, for 2003 compared to $560 million consolidated net loss, or $1.92
loss per diluted share, for 2002. The $782 million increase in net loss is
detailed as follows (in millions):

Wholesale energy segment EBIT............................... $ 964
Interest expense............................................ 249
Retail energy segment EBIT.................................. (101)
Other operations segment EBIT............................... (59)
Discontinued operations, net of tax......................... (33)(1)
Income tax expense.......................................... (26)
Interest income............................................. (7)
Other, net.................................................. 5
-----
Net increase before cumulative effect of accounting
changes................................................ 992
Cumulative effect of accounting changes in 2003, net of
tax....................................................... 24(2)
Cumulative effect of accounting change in 2002, net of
tax....................................................... (234)(3)
-----
Net increase in loss...................................... $ 782
=====

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

(1) See notes 22 and 23 to our consolidated financial statements.

(2) See notes 2(c), 2(d) and 2(q) to our consolidated financial statements.

(3) See note 6 to our consolidated financial statements.

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

Interest Expense. We incurred $516 million of interest expense to third
parties during 2003 compared to $267 million in 2002. The $249 million increase
in interest expense to third parties is detailed as follows (in millions):

Interest expense on third-party debt........................ $166(1)
Write-off of deferred financing costs....................... 55(2)
Amortization of deferred financing costs.................... 47(2)
Bank and facility fees...................................... 34
Unrealized loss on de-designated interest rate caps......... 9(3)
Amortization of warrants.................................... 7(4)
Amortization of adjustments to fair value of interest rate
swaps..................................................... 7(1)
Capitalized interest........................................ (57)(5)
Reclass from other comprehensive loss for terminated
interest rate swaps....................................... (16)(3)
Offsets to interest expense for amortization of adjustments
to fair value of debt..................................... (3)(1)
----
Net increase in expense................................... $249
====

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

(1) See note 9 to our consolidated financial statements.

(2) See note 2(r) to our consolidated financial statements.

(3) See note 9(c) to our consolidated financial statements.

(4) See note 9(b) to our consolidated financial statements.

(5) See note 2(i) to our consolidated financial statements.

34

Interest Income. We recognized interest income from third parties of $35
million for 2003 as compared to $28 million for 2002. The increase is primarily
due to interest income of $13 million recorded during 2003 compared to $5
million recorded during 2002, recognized on receivables related to energy sales
in California (see note 15(b) to our consolidated financial statements).

Income Tax Expense. During 2002, our effective tax rate was 46.2%. Our
effective tax rate for 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 $26 million for 2002. These items primarily related to state income
taxes and an increase in valuation allowances primarily due to the impairment of
certain venture capital investments. Our reconciling items from the federal
statutory rate of 35% to the effective tax rate totaled $23 million, excluding
the goodwill impairment charge, for 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. See note
13 to our consolidated financial statements.

2002 COMPARED TO 2001

Net Loss. We reported $560 million consolidated net loss, or $1.92 loss
per diluted share, for 2002 compared to $563 million consolidated net income, or
$2.03 earnings per share, for 2001. The $1.1 billion decrease in net income is
detailed as follows (in millions):

Wholesale energy segment EBIT............................... $ (883)
Discontinued operations, net of tax......................... (548)(1)
Interest expense............................................ (251)
Retail energy segment EBIT.................................. 533
Income tax benefit/expense.................................. 184
Other operations segment EBIT............................... 80
Interest income............................................. 6
Other, net.................................................. (7)
-------
Net decrease before cumulative effect of accounting
changes................................................ (886)
Cumulative effect of accounting change in 2002, net of
tax....................................................... (234)(2)
Cumulative effect of accounting change in 2001, net of
tax....................................................... (3)(3)
-------
Net decrease in income.................................... $(1,123)
=======

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

(1) See notes 22 and 23 to our consolidated financial statements.

(2) See note 6 to our consolidated financial statements.

(3) See notes 2(d) and 7 to our consolidated financial statements.

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

35

Interest Expense. We incurred $267 million of interest expense to third
parties during 2002 compared to $16 million in 2001. The $251 million increase
in interest expense to third parties is detailed as follows (in millions):

Interest expense on debt related to Orion Power acquisition,
including amortization of adjustments..................... $207(1)
Other interest expense on third-party debt.................. 24(2)
Reclass from other comprehensive loss for terminated
interest rate swaps in 2002............................... 16(2)
Capitalized interest on third-party debt.................... 11(3)
Bank and facility fees...................................... 4
Amortization of deferred financing costs.................... 2
Interest on margin deposits................................. (13)
----
Net increase in expense................................... $251
====

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

(1) See notes 5 and 9 to our consolidated financial statements.

(2) See note 9 to our consolidated financial statements.

(3) See note 2(i) to our consolidated financial statements.

Interest Income. We recognized interest income from third parties of $28
million for 2002 compared to $22 million for 2001. The increase is primarily due
to interest income of $5 million recorded during 2002, recognized on receivables
related to energy sales in California (see note 15(b) to our consolidated
financial statements).

Income Tax Expense. During 2001 and 2002, our effective tax rate was 38.7%
and 46.2%, respectively. Our reconciling items from the federal statutory rate
of 35% to the effective tax rate totaled $28 million for 2001. These items
primarily related to state income taxes and goodwill amortization. Our
reconciling items from the federal statutory rate of 35% to the effective tax
rate totaled $26 million for 2002. See discussion above for 2002 reconciling
items. See note 13 to our consolidated financial statements.

EBIT BY BUSINESS SEGMENT

The following tables present operating income (loss) and EBIT for each of
our business segments for 2001, 2002 and 2003. The primary performance measure
used by management to evaluate segment performance is EBIT from continuing
operations, which at the segment level represents all profits or losses from
continuing operations (both operating and non-operating) before deducting
interest and taxes. Management believes EBIT is a good indicator of each
segment's operating performance as it represents the results of operations
without regard to financing methods or capital structure. In addition, we
believe EBIT from continuing operations is used by our investors as a
supplemental financial measure in the evaluation of our consolidated results of
operations. 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 below.

36

The following tables set forth our operating income (loss) and EBIT by
segment for 2001, 2002 and 2003 reconciled to our consolidated net income
(loss):

RETAIL ENERGY

Our retail energy segment provides electricity products and services to
customers, ranging from residential and small commercial customers to large
commercial, industrial and institutional customers. For a description of our
retail energy segment, see "Our Business -- Retail Energy" in Item 1 of this
report and note 21 to our consolidated financial statements.

In 2002 and 2003, our retail energy segment was the largest contributor of
income and cash flow. We view the retail business as relatively stable in the
current competitive environment. We expect, given current trends in the
wholesale energy markets, that this segment will be the primary contributor to
our consolidated operating results in 2004. As the competitive market place in
Texas evolves, we expect to lose residential and small commercial market share
in the Houston market. We expect, based on current trends, that these customer
losses will be partially offset by gains in residential and small commercial
market share in other areas. Our efforts to gain customers outside of the
Houston area may require us to increase our spending for marketing and
advertising. Although our retail energy segment has recently expanded operations
to focus on gaining commercial, industrial and institutional customers in the
PJM Market, its primary market continues to be Texas. We expect to continue to
renew contracts with a significant portion of our large commercial, industrial
and institutional customers in the Texas and PJM markets, and where possible,
add new customer contracts. For information regarding Texas price-to-beat
regulations and other factors that could have a material impact on the results
of operations of our retail energy segment, see "Our Business -- Retail Energy"
and "-- Risk Factors."

We estimate a portion of our retail electricity sales and services and our
energy supply costs. See "Critical Accounting Estimates" within this section.
During 2003, we revised our estimates and assumptions related to 2002 and
accordingly, recognized $39 million of income in our results of operations in
2003 related to 2002. 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.

38

As a part of our February 2004 cost reduction plan, we expect to
restructure certain aspects of this segment, which may result in charges to
earnings reflecting severance and other restructuring costs.

The following table provides summary data, including EBIT, of our retail
energy segment for 2001, 2002 and 2003:

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

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

As described in note 2(d) to our consolidated financial statements,
effective January 1, 2003, we discontinued the use of mark-to-market accounting
for electricity sales to large commercial, industrial and institutional
customers under executed contracts (and the related energy supply contracts) for
contracts executed prior to October 25, 2002. The discontinuation of
mark-to-market accounting was a result of our adoption of EITF No. 02-03. In
addition, beginning October 1, 2003, we adopted EITF No. 03-11, which requires
us to report a significant amount of our non-trading commodity hedging
activities on a net, as opposed to a gross, basis. Accordingly, our financial
results are not comparable between 2002 and 2003.

39

We must contract with other generators/suppliers to supply the majority of
our obligations. We purchase and sell electricity supply in the market as a
means to manage our energy supply. 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. Prior to October 1, 2003,
these transactions are recorded as gross revenues and purchased power and are
disclosed in "revenues from resales of purchased power and other hedging
activities" and "purchased power and delivery fees," as applicable.

2003 COMPARED TO 2002

EBIT. Our retail energy segment's EBIT was $621 million for 2003 compared
to $520 million for 2002. The increase of $101 million is detailed as follows
(in millions):

Gross margins............................................... $125
Accrual for payment to CenterPoint.......................... 81
Operation and maintenance and selling, general and
administrative............................................ (69)
Loss on sale of receivables................................. (27)
Depreciation and amortization............................... (9)
----
Net increase in income.................................... $101
====

Total Revenues. Total revenues increased $1.6 billion during 2003 compared
to 2002. However, as discussed above, the results of operations are not
comparable between 2002 and 2003. The following table reconciles reported
revenues to revenues from end-use customers on a comparable basis for 2002 and
2003 considering the impacts of applying EITF No. 02-03 and EITF No. 03-11:

The following details our gross revenues from end-use retail customers by
customer class:

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

(1) With respect to our customers in Texas, we experience seasonal peak loads in
the months of June, July and August due to the weather.

40

The $942 million increase in revenues from end-use retail customers is due
to (a) increases in the price-to-beat for residential and small commercial
customers in the Houston area, (b) 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, (c) a 9%
increase in residential customers and sales volumes and (d) an increase in sales
volumes to large commercial, industrial and institutional customers. These
increases were partially offset by a decrease in small commercial customers. Our
revenues from resales of purchased power and other hedging activities decreased
due to changes in our strategies for risk management and hedging our electric
energy supply.

Purchased Power and Delivery Fees. Purchased power and delivery fees
increased $1.5 billion during 2003 compared to 2002. However, as discussed
above, the results of operations are not comparable between 2002 and 2003. The
following table reconciles reported purchased power and delivery fees to
purchased power and delivery fees attributable to end-use customers on a
comparable basis for 2002 and 2003 considering the impacts of applying EITF No.
02-03 and EITF No. 03-11:

The $817 million increase in purchased power and delivery fees attributable to
end-use retail customers is detailed as follows (in millions):

Higher energy costs primarily due to higher natural gas
prices (see above) and increased volumes.................. $778
Increase in rates for ERCOT ISO load related fees........... 39
----
Net increase in expense................................... $817
====

Our costs of purchased power subsequently resold and other hedging activities
decreased due to changes in our strategies for risk management and hedging our
electric energy supply.

Gross Margins. Our retail energy segment's gross margins increased $125
million in 2003 compared to 2002. The increase is detailed as follows (in
millions):

Higher revenue rates and volumes partially offset by higher
purchased power and delivery fees......................... $182(1)
Revised estimates for electric sales and supply costs
related to prior periods.................................. 39
Change in accounting method (EITF No. 02-03)................ (57)
Increase in rates for ERCOT ISO load related fees........... (39)
----
Net increase in income.................................... $125
====

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

(1) Increase due to timing of price-to-beat fuel factor rate increases compared
to higher fuel costs from changes in natural gas prices. Increase also due
to higher customer count for residential and large commercial, industrial
and institutional customers, as well as increased volumes for residential
customers, partially offset by the impact of sales volumes for large
commercial, industrial and institutional customers.

Accrual for Payment to CenterPoint. We will be required to make a payment
to CenterPoint estimated to be due in the fourth quarter of 2004 related to
residential customers. As of December 31,
41

2003, we estimate the payment to be $175 million. We accrued $128 million during
2002 and $47 million during 2003, for a total accrual of $175 million. See note
14(d) to our consolidated financial statements.

Operation and Maintenance and Selling, General and Administrative.
Operation and maintenance expenses and selling, general and administrative
expenses increased $69 million in 2003 compared to 2002. The increase is
detailed as follows (in millions):

Employee-related, customer-related and other administrative
costs..................................................... $36(1)
Corporate overhead charges.................................. 26(2)
Marketing costs............................................. 14(3)
Bad debt expense............................................ (7)(4)
---
Net increase in expense................................... $69
===

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

(1) Increase due to increasing costs during 2002 to reach the normal operational
level to serve customers in the Texas retail market.

(2) Increase due to (a) compensation, severance and benefit costs, (b) higher
insurance costs, including property insurance and directors' and officers'
insurance and (c) expenses associated with our corporate office move and
related costs. In addition, our retail energy segment's proportion of the
corporate overhead charges increased due to the increased support for this
segment, which had increased operations in 2003 compared to 2002.

(3) Increase due to costs of additional marketing and other costs associated
with obtaining new customers in areas outside of the Houston market.

(4) Decrease due to changes in regulations in September 2002, which allowed us
to disconnect customers for non-payment of their electric bills.

Depreciation and Amortization. Depreciation and amortization expense
increased $9 million in 2003 compared to 2002. The increase is primarily due to
depreciation related to the information systems developed and placed in service
during the first quarter of 2002.

Loss on Sale of Receivables. Loss on sale of receivables increased $27
million in 2003 compared to 2002. The increase is due to additional sales of
receivables and increase in the discount factor pursuant to our receivables
factoring facility. For additional information on our receivables facility, see
note 16 to our consolidated financial statements.

2002 COMPARED TO 2001

EBIT. Our retail energy segment's EBIT was $520 million for 2002 compared
to a $13 million loss for 2001. The $533 million increase in EBIT was primarily
due to the commencement of full competition, which began January 1, 2002 and
resulted in increased margins related to retail electric sales to residential,
small commercial and large commercial, industrial and institutional customers.
The increase in margins was partially offset by increased operating expenses as
further discussed below.

Total Revenues. Total revenues increased $4.2 billion in 2002 compared to
2001. The increase is due to (a) retail electric sales in the Texas retail
market to residential, small commercial and large commercial, industrial and
institutional customers in the Houston area in connection with full competition,
which began January 1, 2002 and (b) our revenues from resales of purchased power
and other hedging activities.

In addition, $53 million of revenues for 2001 were recorded for billing,
customer service, credit and collection and remittance services charged to
CenterPoint. The associated costs are included in operation and maintenance
expenses and selling, general and administrative expenses. Our retail energy
segment charged for these services provided at cost. The service agreement
governing these services terminated on December 31, 2001.

Purchased Power and Delivery Fees. Purchased power expense and delivery
fees increased $3.2 billion in 2002 compared to 2001. The increase is due to
costs associated with retail electric sales and costs of purchased power
subsequently resold and other hedging activities.

42

Gross Margins. Our retail energy segment's gross margins increased $946
million in 2002 compared to 2001. The increase is primarily due to the opening
of the Texas market to full competition in January 2002. During 2002, the retail
energy segment recognized $152 million of margins related to commercial,
industrial and institutional electricity contracts (including $6 million of
unrealized losses) compared to $74 million (including $73 million of unrealized
gains) in 2001. For information regarding the accounting for electricity sales
to large commercial, industrial and institutional customers, see note 2(d) to
our consolidated financial statements.

Operation and Maintenance and Selling, General and
Administrative. Operation and maintenance expenses and selling, general and
administrative expenses increased $260 million in 2002 compared to 2001. The
increase is detailed as follows (in millions):

Employee-related, customer-related and other administrative
costs..................................................... $111(1)
Bad debt expense............................................ 69(2)
Gross receipt taxes......................................... 59(3)
Corporate overhead charges.................................. 44(4)
Marketing costs, primarily in Texas......................... 23(1)
General and administrative costs charged to CenterPoint in
2001...................................................... (53)(5)
Other, net.................................................. 7
----
Net increase in expense................................... $260
====

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

(1) Increase primarily due to the Texas retail market opening to full
competition in January 2002.

(2) Increase associated with the start-up of the retail electric market and
regulations which, until September 2002, did not allow us to disconnect
customers for non-payment of their electric bills.

(3) Increase relates to increased retail electric sales.

(4) Increase due to higher information technology costs, advisory fees, legal
costs and insurance to support this segment.

(5) See discussion above.

Depreciation and Amortization. Depreciation and amortization expense
increased $15 million in 2002 compared to 2001. The increase is detailed as
follows (in millions):

Information systems......................................... $17
Goodwill amortization in 2001............................... (2)(1)
---
Net increase in expense................................... $15
===

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

(1) See note 6 to our consolidated financial statements.

Loss of Sale of Receivables. Loss on sale of receivables increased $10
million in 2002 compared to 2001 reflecting the establishment of our receivables
facility in 2002. See note 16 to our consolidated financial statements.

WHOLESALE ENERGY

As of December 31, 2003, our wholesale energy segment owned or leased
electric power generation facilities with an aggregate net operating generating
capacity of 19,442 MW (exclusive of units retired or mothballed). For a
description of the wholesale energy segment, see "Our Business -- Wholesale
Energy" in Item 1 of this report and note 21 to our consolidated financial
statements.

The EBIT of our wholesale energy segment has declined significantly since
2001 primarily as a function of depressed market conditions. In 2003, the EBIT
of this segment was also negatively affected by an $80 million trading loss in
the first quarter of that year. In March 2003, we discontinued our proprietary
trading business.

43

In 2003, we (a) recognized an impairment of $985 million of goodwill in
this segment, (b) retired 489 MW of plant assets and mothballed 824 MW of plant
assets and (c) sold our 588 MW Desert Basin plant (see notes 6 and 23 to our
consolidated financial statements). In February 2004, we announced our plans to
mothball and/or retire an additional 727 MW from certain peaking plants and
units that serve the PJM Market subject to a review of certain reliability
issues with regulators.

Based on current trends, we do not anticipate that conditions in the
wholesale energy markets are likely to improve significantly in 2004. However,
we believe that the wholesale energy market is cyclical and that conditions will
ultimately improve. For information regarding factors that could have a material
impact on the results of operations of our wholesale energy segment, see
"-- Risk Factors."

As part of our February 2004 cost reduction plan, we expect to restructure
certain aspects of this segment, which may result in charges to earnings
reflecting severance and other restructuring costs.

The following table provides summary data, including EBIT, of our wholesale
energy segment for 2001, 2002 and 2003:

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

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

44

(2) In July 2003, the EITF issued EITF No. 03-11, which became effective October
1, 2003. At that time, we began reporting prospectively the settlement of
sales and purchases of fuel and purchased power related to our non-trading
commodity derivative activities that were not physically delivered on a net
basis in our results of operations based on the item hedged pursuant to EITF
No. 03-11. This resulted in decreased revenues and decreased fuel and cost
of gas sold and purchased power of $666 million for the fourth quarter of
2003. We believe the application of EITF No. 03-11 will continue to result
in a significant amount of our non-trading commodity derivative activities
being reported on a net basis prospectively that were previously reported on
a gross basis. We did not reclassify amounts for periods prior to October 1,
2003. See note 2(d) to our consolidated financial statements.

(3) Total revenues less fuel and cost of gas sold and purchased power.

(4) These amounts exclude volumes associated with our Desert Basin plant
operations, which are classified as discontinued operations.

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

2003 COMPARED TO 2002

EBIT. Our wholesale energy segment's EBIT was a loss of $934 million for
2003 compared to earnings of $30 million for 2002. The decrease of $964 million
is detailed as follows (in millions):

Goodwill impairment......................................... $(985)(1)
Trading margins............................................. (185)
Operation and maintenance expense........................... (57)
Depreciation and amortization............................... (26)
Income/loss of equity investments........................... (20)
Power generation margins.................................... 244
General, administrative and development expense............. 71
Other, net.................................................. (6)
-----
Net decrease in income.................................... $(964)
=====

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

(1) See note 6 to our consolidated financial statements.

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, decreased $1.1 billion in 2003 compared to 2002. The decrease is
primarily due to (a) the application of EITF No. 03-11, which reduced 2003
revenues by $666 million (see note 2(d) to our consolidated financial
statements) and (b) a 14% decrease in power sales volumes. The decrease is
partially offset by (a) a 4% increase in prices for power sales partially due to
increased gas costs, (b) $209 million of changes in our refund obligation and
credit reserves for energy sales in California (see note 15(b) to our
consolidated financial statements) and (c) $184 million due to the inclusion of
a full year's results of Orion Power's operations in 2003 as the acquisition
occurred in February 2002. Our revenues from power sales and other hedging
activities decreased due to changes in our strategies and our liquidity
constraints for risk management, hedging and optimizing of our generation
portfolio.

Fuel and Cost of Gas Sold and Purchased Power. Our wholesale energy
segment's fuel and cost of gas sold and purchased power decreased $1.3 billion
in 2003 compared to 2002. The decrease is primarily due to (a) the application
of EITF No. 03-11, which reduced 2003 fuel and cost of gas sold and purchased
power by $666 million (see note 2(d) to our consolidated financial statements)
and (b) decreased purchased power volumes and a decrease in prices of purchased
power as a result of our hedging activities (see above).

Trading Margins. Trading margins decreased $185 million in 2003 compared
to 2002. The decrease is 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. 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

45

totaling $11 million recorded during 2003. See "Quantitative and Qualitative
Disclosures About Market Risk" in Item 7A of this report.

Power Generation Margins. Our wholesale energy segment's power generation
margins increased $244 million in 2003 compared to 2002. The increase is
detailed as follows (in millions):

California energy sales refund provision charges in 2002.... $176(1)
California energy sales refund provision reversals in
2003...................................................... 110(1)
Mid-Continent and New York regions -- full year for Orion
Power..................................................... 70(2)
Mid-Atlantic region, excluding expiration of capacity
contract.................................................. 64(3)
ERCOT Region................................................ 29(4)
Margins associated with CenterPoint......................... 18(5)
FERC settlement recorded in 2002............................ 14(6)
Margins resulting from a terminated counterparty............ 12
Mid-Atlantic region -- expiration of capacity contract...... (66)
California energy sales credit provision reversals in
2002...................................................... (62)(1)
West region................................................. (56)(7)
FERC settlement in October 2003............................. (37)(6)
New York region............................................. (22)(8)
California energy sales credit provisions in 2003........... (15)(1)
Other, net.................................................. 9
----
Net increase in income.................................... $244
====

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

(1) See note 15(b) to our consolidated financial statements.

(2) Increase due to the inclusion of a full year's results of Orion Power's
operations in 2003, as the acquisition occurred in February 2002.

(3) Increase primarily due to increased margins from our coal plants due to
higher power prices driven by increased natural gas prices.

(4) Increase primarily due to increased steam sales at the Channelview facility.

(5) Increase 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 3 to our
consolidated financial statements).

(6) See note 15(a) to our consolidated financial statements.

(7) Decrease due to (a) lower spark spreads during 2003, (b) settlement of 2002
electric energy hedges entered into at higher prices and (c) an increase in
losses due to hedge ineffectiveness.

(8) Decrease as a result of increased fuel costs due to unhedged fuel positions
and forward power sales.

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $57 million in 2003 compared to 2002. The
increase is detailed as follows (in millions):

Full year for Orion Power................................... $37
Facilities reaching commercial operation in 2002 and 2003... 16(1)
Other, net.................................................. 4
---
Net increase in expense................................... $57
===

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

(1) Increase due to the Hunterstown and Choctaw facilities reaching commercial
operation in 2003 and the Channelview and Liberty facilities reaching
commercial operation in 2002.

46

General, Administrative and Development. General, administrative and
development expenses decreased $71 million in 2003 compared to 2002. The
decrease is detailed as follows (in millions):

Development costs........................................... $(41)(1)
Consulting fees and legal costs............................. (27)
Severance expense related to restructuring in 2002.......... (20)
Other salary and incentive costs............................ (14)
Provision for doubtful accounts............................. (12)
CFTC settlement in November 2003............................ 18(2)
Corporate overhead allocations.............................. 18(3)
Other, net.................................................. 7
----
Net decrease in expense................................... $(71)
====

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

(1) Decrease due to direct write-offs of development costs due to the
cancellation of power generation projects in 2002 and less development
activity in 2003.

(2) See note 15(a) to our consolidated financial statements.

(3) Increase due to (a) compensation, severance and benefit costs, (b) higher
insurance costs, including property insurance and directors' and officers'
insurance and (c) expenses associated with our corporate office move and
related costs. This increase was partially offset for our wholesale energy
segment as a higher proportion of the corporate overhead charges were
allocated to our retail energy segment, which had increased operations in
2003 compared to 2002.

Depreciation and Amortization. Depreciation and amortization expense
increased $26 million in 2003 compared to 2002. The increase is detailed as
follows (in millions):

Full year for Orion Power................................... $ 21
Amortization of emission allowances due to higher average
prices of allowances used................................. 14
Early retirement of certain units at Sayreville and Etiwanda
facilities in 2003........................................ 14
Two power generation facilities reaching commercial
operation in 2003......................................... 14
Write-down of office building to fair value less costs to
sell in 2003.............................................. 7
Impairment charges related to turbines and generators in
2002...................................................... (37)(1)
Early retirement of certain units at the Warren facility in
2002...................................................... (15)
Other, net.................................................. 8
----
Net increase in expense................................... $ 26
====

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

(1) See note 14(c) to our consolidated financial statements.

Income (Loss) of Equity Investments. The equity income/loss in both years
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
$21 million in 2003 compared to 2002, primarily due to receipts of $22 million
of business interruption and property/casualty insurance settlements during
2002.

47

2002 COMPARED TO 2001

EBIT. Our wholesale energy segment's EBIT was $30 million for 2002
compared to $913 million for 2001. The decrease of $883 million is detailed as
follows (in millions):

Power generation margins.................................... $(807)(1)
Trading margins............................................. (172)(1)
General, administrative and development expense............. (89)(1)
Depreciation and amortization............................... (73)(1)
Orion Power acquisition in 2002............................. 224
Operation and maintenance expense........................... 13(1)
Other, net.................................................. 21(1)
-----
Net decrease in income.................................... $(883)
=====

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

(1) Excludes effects of the Orion Power acquisition, which occurred in February
2002. See note 5 to our consolidated financial statements.

Revenues. Our wholesale energy segment's revenues, excluding trading
margins, increased $1.1 billion in 2002 compared to 2001. The increase is
primarily due to (a) $2.2 billion in the Mid-Atlantic region as a result of
hedging activities and (b) $1.1 billion related to the Orion Power acquisition
in February 2002. The increase was partially offset by a $2.4 billion decrease
in the West region as a result of reduced generation, reduced hedging activities
and lower 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 increased $1.3 billion
in 2002 compared to 2001. The increase is primarily due to (a) $2.3 billion in
the Mid-Atlantic region as a result of hedging activities and (b) $444 million
due to the Orion Power acquisition. The increase was partially offset by a $1.7
billion reduction of generation volumes, reduced hedging activities and lower
prices for fuel in the West region.

Trading Margins. Trading margins decreased $168 million in 2002 compared
to 2001. The decrease is primarily due to lower commodity volatility in the
power markets, reduced market liquidity driven by the industry's restructuring
and the reduction of our trading activities as a result of our restructuring in
2002.

Power Generation Margins. Our wholesale energy segment's power generation
margins decreased $200 million in 2002 compared to 2001. The decrease is
detailed as follows (in millions):

West region................................................. $(641)(1)
California energy sales refund provision charges in 2002.... (176)(2)
Mid-Atlantic region......................................... (68)(3)(4)
Other regions............................................... (54)(4)(5)
Ineffectiveness of cash flow hedges......................... (28)(4)(6)
Orion Power acquisition in 2002............................. 608
Provision for Enron receivables and derivative assets....... 63(7)()
California energy sales credit provision reversals in
2002...................................................... 62(2)
ERCOT Region................................................ 29(8)
Other, net.................................................. 5(4)
-----
Net decrease in income.................................... $(200)
=====

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

(1) Decrease due to (a) the loosening of tight supply and demand conditions that
existed in the first half of 2001, (b) a full year of energy price caps
which were initially implemented in June 2001 and (c) other regulatory
provisions that suppressed ancillary services revenues.

(2) See note 15(b) to our consolidated financial statements.

48

(3) Decrease due to a decline in power prices and reduced capacity revenues as a
result of the expiration of a large capacity contract and lower capacity
market conditions, which were primarily a result of increased generation
supply in the region as well as regulatory intervention.

(4) Excludes effects of the Orion Power acquisition, which occurred in February
2002. See note 5 to our consolidated financial statements.

(5) Decrease primarily due to decreases in power prices, losses on our tolling
contracts and increased gas transportation costs in 2002.

(6) Decrease due to $27 million gain in 2001 primarily related to the California
market compared to $1 million loss in 2002. See note 7(a) to our
consolidated financial statements.

(7) See note 15(a) to our consolidated financial statements.

(8) These assets began commercial operation in the last half of 2001 and in June
2002.

Operation and Maintenance. Operation and maintenance expenses for our
wholesale energy segment increased $240 million in 2002 compared to 2001. The
increase is detailed as follows (in millions):

Orion Power acquisition in 2002............................. $254
Lower maintenance and outage costs.......................... (27)(1)
Other, net.................................................. 13(1)
----
Net increase in expense................................... $240
====

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

(1) Excludes effects of the Orion Power acquisition, which occurred in February
2002. See note 5 to our consolidated financial statements.

General, Administrative and Development. General, administrative and
development expenses increased $89 million in 2002 compared to 2001. The
increase is detailed as follows (in millions):

Development write-offs in 2002.............................. $27
Corporate overhead allocations.............................. 26(1)
Severance expense related to restructuring in 2002.......... 20
Consulting costs related to restructuring in 2002........... 11
Bad debt expense............................................ 9
Development cost write-offs in 2001......................... (9)
Other, net.................................................. 5
---
Net increase in expense................................... $89
===

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

(1) Increase due to higher information technology costs, advisory fees, legal
costs and insurance.

Depreciation and Amortization. Depreciation and amortization expense
increased $210 million in 2002 compared to 2001. The increase is detailed as
follows (in millions):

Orion Power acquisition in 2002............................. $137
Impairment charges related to turbines and generators in
2002...................................................... 37
Information technology systems placed in service in the
third quarter of 2002..................................... 16
Early retirement of certain units at the Warren facility in
2002...................................................... 15
Generating plants placed in service during second half of
2001 and in June 2002..................................... 14
Emissions credit amortization............................... (15)(1)(2)
Goodwill amortization in 2001............................... (4)(3)
Other, net.................................................. 10(2)
----
Net increase in expense................................... $210
====

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

(1) Decrease primarily due to higher amortization in the West region in 2001 due
to increased power generation levels and higher prices for emission credits.

49

(2) Excludes effects of the Orion Power acquisition, which occurred in February
2002. See note 5 to our consolidated financial statements.

(3) See note 6 to our consolidated financial statements.

Income of Equity Investments. Our wholesale energy segment's income of
equity investments increased $11 million in 2002 compared to 2001. The equity
income in both years primarily resulted from an investment in an electric
generation plant in Boulder City, Nevada. The increase is detailed as follows
(in millions):

Business interruption and property/casualty insurance
settlements receipts in 2002.............................. $22
Decreases in margins due to lower prices realized in 2002... (5)
Other, net.................................................. (6)
---
Net increase in income.................................... $11
===

Other Income, net. Other income, net increased $13 million in 2002
compared to 2001. The increase is primarily due to billings for software
services to support the operations of generating facilities of Texas Genco.

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 2001, 2002 and 2003:

50

2003 COMPARED TO 2002

Other operation's loss before interest and income taxes was $28 million for
2003 compared to $87 million for 2002. The decrease of $59 million is detailed
as follows (in millions):

Pre-tax, non-cash accounting settlement charge in 2002 for
certain benefit obligations associated with our separation
from CenterPoint.......................................... $(47)(1)
Impairment of certain venture capital investments in 2002... (32)(2)
Texas franchise taxes....................................... 8
Unallocated corporate costs associated with our discontinued
European energy operations................................ 7
Change in gains/losses from investments..................... 8
Other, net.................................................. (3)
----
Net decrease in loss...................................... $(59)
====

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

(1) See note 12 to our consolidated financial statements.

(2) See note 2(o) to our consolidated financial statements.

2002 COMPARED TO 2001

Other operation's loss before interest and income taxes was $87 million for
2002 compared to $167 million for 2001. The decrease of $80 million is detailed
as follows (in millions):

Pre-tax, non-cash charge recorded in 2001 relating to the
redesign of some of CenterPoint's benefit plans in
anticipation of our separation from CenterPoint........... $(100)(1)
Restructuring charges in connection with exiting our
communications business in 2001........................... (35)(2)
Goodwill impairment related to the exiting of our
communications business in 2001........................... (19)(2)
Operating loss for our communications business in 2001...... (18)
Pre-tax, non-cash accounting settlement charge in 2002 for
certain benefit obligations associated with our separation
from CenterPoint.......................................... 47(1)
Impairment of certain venture capital investments in 2002... 32(3)
Other, net.................................................. 13
-----
Net decrease in loss...................................... $ (80)
=====

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

(1) See note 12 to our consolidated financial statements.

(2) See note 17 to our consolidated financial statements.

(3) See note 2(o) to our consolidated financial statements.

RISK FACTORS

The following risk factors should be considered carefully together with the
risk factors and contingencies described in "Business" in Item 1 of this report,
"-- Liquidity and Capital Resources" below, and notes 14 and 15 to our
consolidated financial statements. The risks described in this section are not
the only ones we face. Additional risks and uncertainties not presently known to
us or that we currently believe to be immaterial could also have a material
impact on our business operations.

RISKS RELATING TO SELLING ELECTRICITY

THE WHOLESALE AND RETAIL ELECTRICITY MARKETS ARE HIGHLY COMPETITIVE.

The market for wholesale and retail electricity customers is very
competitive. In certain markets, our principal competitors include the local
regulated electric utility or its non-regulated affiliate. In other markets, we
face competition from independent electric providers, independent power
producers and

51

wholesale power providers. In many cases, our competitors have the advantage of
long-standing relationships with customers, longer operating histories and/or
larger and better capital resources.

In general, we compete on the basis of price, our commercial and marketing
skills relative to other market participants, service and our financial
position. Other factors affecting our competitive position include our ability
to obtain at competitive prices fuel supplies to operate our generation plants,
electricity for resale and related transportation/transmission services. Since
many of our energy customers, suppliers and transporters require financial
guarantees and other assurances regarding contract performance, our access to
credit support is another factor affecting our ability to compete in the market.

Our largest market for residential electricity customers is the Houston
market. As a former affiliate of CenterPoint, we are required by the PUCT to
sell electricity to residential customers at a specified price, or
"price-to-beat." If competing electric suppliers are able to sell electricity at
prices below the price-to-beat, we risk losing a significant number of our
residential customers to other providers. See "-- Special Risks Relating to the
Texas Market" below and "Our Business -- Retail Energy -- Regulation" in Item 1
of this report.

OUR BUSINESS IS SUBJECT TO MARKET RISKS, THE IMPACT OF WHICH WE CANNOT FULLY
MITIGATE.

Unlike a traditional regulated electric utility, we are not guaranteed a
rate of return on our capital investments. We sell electric energy, capacity and
ancillary services and purchase fuel under short and long-term contractual
obligations and through various spot markets. Our results of operations,
financial condition and cash flows depend, in large part, upon prevailing market
prices for electricity and fuel in our markets. Market prices may fluctuate
substantially over relatively short periods of time, potentially adversely
affecting our results of operations, financial condition and cash flows. Changes
in market prices for electricity and fuel may result from the following factors
among others:

- weather conditions;

- seasonality;

- demand for energy commodities and general economic conditions;

- forced or unscheduled plant outages;

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

- addition of generating capacity;

- availability of competitively priced alternative energy sources;

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

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

- the financial position of market participants;

- changes in market liquidity;

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

- governmental regulation and legislation.

We operate a significant number of power generation plants. To operate
these plants, we must enter into commitments with various terms for fuel and
transmission capacity or services. Although we attempt to hedge these purchases
against our commitments to sell in the future, it is not possible to hedge all
of our generation plant output beyond certain defined periods and, thus, changes
in commodity prices could negatively impact our results of operations, financial
condition and cash flows.

52

IN MARKETING OUR PRODUCTS, WE RELY ON POWER TRANSMISSION FACILITIES THAT WE DO
NOT OWN OR CONTROL. IF THESE FACILITIES FAIL TO PROVIDE US WITH ADEQUATE
TRANSMISSION CAPACITY, WE MAY NOT BE ABLE TO DELIVER POWER TO OUR CUSTOMERS.

We depend on power transmission and distribution facilities owned and
operated by utilities and others to deliver energy products to our customers. If
transmission or transportation is inadequate or disrupted, our ability to sell
and deliver our products may be hindered. Any infrastructure failure that
interrupts or impairs delivery of electricity or natural gas could have a
material adverse effect on our business.

WE ARE DEPENDENT ON METERING SYSTEMS THAT WE DO NOT OWN OR CONTROL. FAILURE TO
RECEIVE ACCURATE AND TIMELY INFORMATION COULD HAVE A MATERIAL ADVERSE IMPACT
ON OUR BUSINESS.

We are dependent on the transmission and distribution utilities for reading
our customers' energy meters. We also rely on the local transmission and
distribution utility or, in some cases, the independent system operator, to
provide us with our customers' information regarding energy usage, and we may be
limited in our ability to confirm the accuracy of the information. If we receive
incorrect or untimely information from the transmission and distribution
utilities, we will have difficulty properly billing our customers and collecting
amounts owed to us. Failure to receive correct and timely information could have
a material adverse effect on our results of operations, financial condition and
cash flows. For information regarding data collection and other billing risks,
see "-- Special Risks Relating to the Texas Market" below and "Critical
Accounting Estimates" below.

RISKS RELATING TO OWNERSHIP OF GENERATION ASSETS

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

As of December 31, 2003, we own an interest in, or lease, 124 operating
electric generation facilities. Our operation of generation assets exposes us to
risks relating to the breakdown of equipment, fuel supply interruptions,
shortages of equipment, material and labor and other operational risks. In
addition, significant portions of our facilities were constructed many years
ago. Older generating equipment, even if maintained in accordance with good
engineering practices, may require significant capital expenditures to add to or
upgrade equipment to maintain efficiency, to comply with changing environmental
requirements or to provide reliable operations. Such expenditures affect our
operating costs. Any unexpected failure to produce power, including failure
caused by breakdown or forced outage, could have a material adverse effect on
our results of operations, financial condition and cash flows.

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

We have insurance coverage, subject to various limits and deductibles,
covering our generation facilities, including property damage insurance and
general liability insurance in amounts that we consider appropriate.

However, we cannot assure you that insurance coverage will be available in
the future on commercially reasonable terms or that the insurance proceeds
received for any loss of or any damage to any of our generation facilities will
be sufficient to restore the loss or damage without negative impact on our
results of operations and financial condition. The costs of our insurance
coverage have increased significantly during recent years and may continue to
increase in the future.

REGULATORY RISKS

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

We operate in a regulatory environment that is undergoing significant
changes as a result of varying restructuring initiatives at both the state and
federal levels. We cannot predict the future direction of these
53

initiatives or the ultimate effect that this changing regulatory environment
will have on our business. Moreover, existing regulations may be revised or
reinterpreted and new laws and regulations may be adopted or become applicable
to our facilities or our commercial activities. Such future changes in laws and
regulations may have a detrimental effect on our business. For additional
information, see "Our Business -- Retail Energy -- Regulation" and "Our
Business -- Wholesale Energy -- Regulation" in Item 1 of this report and note 15
to our consolidated financial statements.

The FERC and independent system operators have imposed and may continue to
impose price limitations, bidding rules and other mechanisms in an attempt to
address some of the price volatility in these markets. Additionally, federal
legislative initiatives have been introduced to address the problems being
experienced in some power markets. We cannot predict whether such proposals will
be adopted or their impact on industry restructuring. If the trend towards
competitive restructuring of the wholesale power markets is reversed,
discontinued or delayed, our business growth prospects and financial results
could be adversely affected.

IF WE FAIL TO OBTAIN OR MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR
APPROVAL, WE MAY NOT BE ABLE TO OPERATE OUR PLANTS.

The ownership and operation of power generation facilities require numerous
permits, approvals and certificates from federal, state and local governmental
agencies. The operation of our generation facilities must also comply with
environmental protection and other legislation and regulations. Most of our
generation facilities are exempt wholesale generators that sell electricity
exclusively into the wholesale market. These facilities are subject to
regulation by the FERC regarding rate matters. Although the FERC has authorized
us to sell electricity produced from these facilities at market prices, the FERC
retains the authority to modify or withdraw our market-based rate authority and
to impose "cost of service" rates. Any reduction by the FERC of the rates we may
receive for our generation activities may adversely affect our business, results
of operations, financial condition and cash flows.

OUR COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND THE COST
OF COMPLIANCE WITH NEW ENVIRONMENTAL LAWS COULD ADVERSELY AFFECT OUR RESULTS
OF OPERATIONS AND CASH FLOWS.

Our generation facilities, in particular our coal-fired plants, are subject
to extensive environmental regulation by federal, state and local authorities.
We are required to comply with numerous environmental laws and regulations and
to obtain numerous governmental permits in operating our facilities. We may
incur significant costs to comply with these requirements. If we fail to comply
with these requirements, we could be subject to civil or criminal penalties
including fines. Existing environmental regulations can be revised,
reinterpreted or become applicable to our facilities or new laws and regulations
could be adopted. If any of these events occur, our business, results of
operations, financial condition and cash flows could be materially adversely
affected. For more information regarding compliance with environmental laws, see
"Our Business -- Environmental Matters" and note 15 to our consolidated
financial statements.

SPECIAL RISKS RELATING TO THE TEXAS MARKET

OUR RESULTS OF OPERATIONS COULD BE MATERIALLY AFFECTED BY DECISIONS OF THE
PUCT REGARDING THE "PRICE-TO-BEAT" AND RELATED REGULATORY MATTERS.

The PUCT-approved price, or "price-to-beat," that we are required to charge
for residential electricity sales and must make available to small commercial
customers in the Houston area includes a component to reflect the market price
of fuel and purchased power costs. This component, commonly known as the fuel
factor, was originally established in 2001 and is fixed until such time as the
PUCT grants an adjustment. Under current PUCT rules, we can apply for an
adjustment not more than twice a year if we can demonstrate there have been
significant changes in the market price of natural gas or purchased energy to
serve retail customers. To the extent that there are significant changes in the
market price of natural gas or purchased energy and we do not adjust the fuel
factor or there is a significant delay in the

54

timing of these adjustments, our results of operations, financial condition and
cash flows could be materially adversely affected.

The PUCT and the ERCOT ISO, which oversees the ERCOT Region, have and may
continue to modify the market structure and other market mechanisms, seek to
revise and/or modify or reinterpret existing regulations in ways that could have
a material impact on our business in the Texas market. In addition, we may be
subject to new state laws and regulations that are adopted or become applicable
to our commercial activities in this region. Any of these actions could have a
material adverse effect on our business.

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

We do not own sufficient generating resources in Texas to supply all of the
electricity requirements of our retail business in this market. Our inability to
contract for our supply requirements, or the failure of our suppliers to perform
their contractual obligations, could have a material adverse effect on our
business. For additional information, see "Our Business -- Retail
Energy -- Retail Energy Supply" and note 4 to our consolidated financial
statements.

THE ERCOT ISO HAS EXPERIENCED A NUMBER OF PROBLEMS WITH ITS INFORMATION
SYSTEMS SINCE THE ADVENT OF COMPETITION IN THE TEXAS MARKET. OUR OPERATING
RESULTS MAY BE ADVERSELY AFFECTED IF THESE PROBLEMS ARE NOT ALLEVIATED.

The ERCOT ISO's responsibilities include ensuring that information relating
to a customer's choice of retail electric provider, including data needed for
ongoing servicing of customer accounts, is conveyed in a timely manner to the
appropriate parties.

Problems in the flow of information between the ERCOT ISO, the transmission
and distribution utilities and the retail electric providers have resulted in
delays and other problems in enrolling and billing customers. When all involved
parties do not successfully process customer enrollment transactions, ownership
records in the various systems supporting the market are not synchronized
properly and subsequent transactions for billing and settlement are adversely
affected. The impact can include us not being the electric provider-of-record
for intended or agreed upon time periods, delays in receiving customer
consumption data that is necessary for billing, as well as the incorrect
application of rates or prices and wholesale imbalances in our electricity
supply and actual sales.

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

See "Critical Accounting Estimates" in this section of the report for
additional information.

PAYMENT DEFAULTS BY OTHER RETAIL ELECTRIC PROVIDERS TO ERCOT COULD HAVE A
MATERIAL ADVERSE EFFECT ON OUR BUSINESS.

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

55

RISKS RELATED TO OUR CAPITAL STRUCTURE

WE HAVE SIGNIFICANT DEBT THAT COULD NEGATIVELY IMPACT OUR BUSINESS.

As of December 31, 2003, we had total consolidated debt of $6.1 billion.
Our high level of debt could:

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

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

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

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

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

DESPITE CURRENT INDEBTEDNESS LEVELS, WE AND OUR SUBSIDIARIES MAY STILL BE ABLE
TO INCUR SUBSTANTIALLY MORE DEBT.

As of December 31, 2003, our credit and other debt agreements permitted us
to incur additional borrowings of up to $1.1 billion. If new debt is added to
our current debt levels, the related risks that we now face could increase. See
note 9 to our consolidated financial statements.

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

Our ability, and the ability of our subsidiaries, to pay principal and
interest on debt depends on our or our subsidiaries' future operating
performance. If our or our subsidiaries' cash flows and capital resources are
insufficient to allow us, or our subsidiaries, to make scheduled payments on the
debt, we may have to reduce or delay capital expenditures, sell assets, seek
additional capital, restructure or refinance the debt or sell equity. We cannot
assure you that the terms of our debt will allow these alternative measures or
that such measures would satisfy our scheduled debt service obligations.

If we default:

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

- our secured debt lenders and bondholders could terminate their
commitments and commence foreclosure proceedings against our assets; and

- we could be forced into bankruptcy or liquidation.

WE MAY NOT HAVE ADEQUATE LIQUIDITY TO POST REQUIRED AMOUNTS OF ADDITIONAL
COLLATERAL.

If commodity prices increase substantially in the near term, our liquidity
could be severely strained by requirements under our commodity agreements to
post additional collateral.

In certain cases, our counterparties have elected not to require us to post
collateral to which they are otherwise entitled under certain agreements.
However, these counterparties retain the right to request such collateral.
Factors that could trigger increased demands for collateral include additional
adverse changes in our industry, negative regulatory or litigation developments
and/or changes in commodity prices. Based on current commodity prices, we
estimate that as of February 20, 2004, we could be contractually required to
post additional collateral of up to $243 million related to our operations.

THE TERMS OF OUR DEBT MAY SEVERELY LIMIT OUR ABILITY TO RESPOND TO CHANGES IN
OUR BUSINESS.

Our credit facilities and other debt instruments restrict our ability to
take specific actions in responding to changes in our business without the
consent of our debt holders, even if such actions may be in our best interest.
56

Our credit facilities also require us to maintain specified financial
ratios and meet specific financial tests.

In addition, our credit facilities and other debt instruments contain
covenants that, among other things, restrict our ability to:

- pay dividends and other distributions;

- incur additional indebtedness and issue preferred stock;

- enter into asset sales;

- enter into transactions with affiliates;

- grant liens on assets to secure debt;

- engage in certain business activities; and

- engage in mergers or consolidations and transfers of assets.

FAILURE TO COMPLY WITH THE COVENANTS IN OUR CREDIT FACILITIES AND OTHER DEBT
INSTRUMENTS COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR RESULTS OF OPERATIONS
AND CASH FLOWS.

Our ability to comply with these covenants may be affected by many events
beyond our control and our future operating results may make it impossible for
us to comply with the covenants, or in the event of a default, to remedy that
default. Our failure to comply with these financial covenants or with the other
restrictions in our credit facilities and other debt instruments could result in
a default, which could cause the applicable debt holders to declare that
indebtedness to become immediately due and payable. If we are unable to repay
those amounts, the holders of our debt could proceed against the collateral
granted to them to secure the related indebtedness and take other legal action
against us. If those lenders accelerate the payment of our debt, we cannot
assure you that we could pay that indebtedness immediately and continue to
operate our business.

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

As of December 31, 2003, we had $4.0 billion of outstanding floating rate
debt. Any increase in short-term interest rates would result in higher interest
costs and could adversely affect our results of operations, financial condition
and cash flows. While we may seek to use interest rate swaps or other derivative
instruments to hedge portions of our floating-rate exposure, we may not be
successful in obtaining hedges on acceptable terms.

OUR NON-INVESTMENT GRADE CREDIT RATINGS AND THE PERCEIVED NEGATIVE CREDIT
WORTHINESS OF MERCHANT ENERGY COMPANIES IN THE FINANCIAL MARKETS COULD
ADVERSELY AFFECT OUR ABILITY TO ACCESS CAPITAL ON ACCEPTABLE TERMS,
COMMERCIALIZE OUR ASSETS AND ENGAGE IN HEDGING ACTIVITIES.

Our credit ratings are below investment grade and are likely to remain
below investment grade for the foreseeable future. Our non-investment grade
credit ratings may continue to limit our ability to refinance our debt
obligations and access the capital markets on terms that are favorable to us. In
addition, to the extent that our credit ratings remain below investment grade,
we are required under many commercial contracts to pledge cash collateral, post
letters of credit or provide other similar credit support. These requirements
constitute a significant constraint on our liquidity and cash resources, may
negatively impact our ability to operate our business and could adversely affect
our results of operations, financial condition and cash flows.

57

GENERAL BUSINESS RISKS

OUR STRATEGIC PLANS MAY NOT BE SUCCESSFUL.

Our future results of operations are dependent on the success of our
strategic plans as discussed in "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Overview."

In restructuring our operations, we may encounter certain risks. For
example, in exiting certain markets and business activities, we may forego
opportunities to participate in potential business opportunities. In addition,
as we review and make changes in our internal cost structure, we likely will
incur increased short-term costs due to severance payments and restructuring
processes. It is also possible that in restructuring and simplifying our
operations we may increase the risk of an impairment of certain assets, such as
information technology systems, to the extent that changes in our business
eliminate the need for such assets.

As part of our cost-reduction efforts, we intend to consolidate a number of
our internal risk controls and other support functions and make significant
reductions in our corporate overhead. There is a potential that control systems
designed for our previous operational structure may prove inadequate for our new
operational structure and have to be redesigned. In addition, new risks may be
encountered for which we have no existing control system. We believe that our
internal controls will continue to be effective and adequate for our
restructured operations, although there could be increased risks as a result of
reduced personnel and changing processes, including information technology
systems.

Although we believe that the wholesale energy market is cyclical, and that
conditions will ultimately improve, there can be no assurance regarding the
certainty, timing or magnitude of such improvement.

THE ULTIMATE OUTCOME OF LAWSUITS AND REGULATORY PROCEEDINGS TO WHICH WE ARE A
PARTY COULD HAVE A MATERIAL ADVERSE EFFECT ON OUR RESULTS OF OPERATIONS,
FINANCIAL CONDITION AND CASH FLOWS.

We are party to numerous lawsuits and regulatory proceedings relating to
our historical trading and wholesale energy activities. In addition, various
state and federal governmental agencies have commenced investigations relating
to these activities, including the California Attorney General, the FERC, and
criminal investigations by the United States Attorneys for the Northern District
of California and the State of Texas. The ultimate disposition of some of these
matters could have a material adverse effect on our results of operations,
financial condition and cash flows. For additional information, see note 15 to
our consolidated financial statements.

OUR RESULTS OF OPERATIONS AND OUR ABILITY TO ACCESS CAPITAL AND INSURANCE
COULD BE ADVERSELY AFFECTED BY TERRORIST ATTACKS OR RELATED ACTS OF WAR.

The uncertainty associated with the military activity of the United States
and other nations and the risk of future terrorist activity may affect our
results of operations and financial condition in unpredictable ways. These
actions could result in adverse changes in the insurance markets and disruptions
of power and fuel markets. In addition, our generation facilities or the power
transmission and distribution facilities could be targets of terrorist activity.
The risk of terrorist attacks or acts of war could also adversely affect the
United States economy, create instability in the financial markets and, as a
result, adversely affect our ability to access capital on terms and conditions
acceptable to us.

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

Our operations are exposed to the risk that counterparties who owe us money
or physical commodities and services, such as power, natural gas or coal, will
not perform their obligations. Many of our counterparties in the energy markets
have below-investment grade credit rankings. If these counterparties fail to
perform, we might be forced to seek alternative hedging arrangements or replace
the underlying commitment at then-current market prices. In this event, we might
incur additional losses. See "Quantitative and Qualitative Disclosures about
Non-Trading and Trading Activities and Related Market Risks -- Credit Risk" in
Item 7A of this report.
58

LIQUIDITY AND CAPITAL RESOURCES

In this section, we discuss the principal sources of capital resources
required for us to operate our business. We also identify known trends, demands,
commitments, events or uncertainties that may affect our current and future
liquidity or capital resources. In the last part of this section, we provide
information regarding our historical cash flows.

SOURCES OF LIQUIDITY AND CAPITAL RESOURCES

Our principal sources of liquidity and capital resources are cash flows
from operations, borrowings under our various revolving credit facilities,
proceeds from certain debt offerings and equity offerings and securitization of
assets.

Cash Flows from Operations. All of our operations are conducted by our
subsidiaries. As a result, Reliant Resources' cash flow is dependent upon the
receipt from its subsidiaries of cash dividends, distributions or other
transfers of cash generated by their operations. In 2002 and 2003, the primary
source of cash flows from operations was from our retail energy segment. We
expect that our retail operations will continue to be our primary source of
operating cash flows through at least 2004. For a description of factors that
could affect the cash flows from operations, see "-- Risk Factors" above and
notes 2(l) and 9 to our consolidated financial statements.

Credit Capacity, Cash and Cash Equivalents. The following table summarizes
our credit capacity, cash and cash equivalents and current restricted cash at
December 31, 2003:

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

(1) As of December 31, 2003, we had consolidated current and long-term debt
outstanding of $6.1 billion. As of December 31, 2003, $157 million of our
committed credit facilities are to expire by December 31, 2004. For a
discussion of our credit facilities, bonds, notes and other debt, see note
9(a) to our consolidated financial statements.

(2) As discussed in notes 9(a) and 15(c) to our consolidated financial
statements, $5 million of the unused capacity relates to Liberty's working
capital facility, which is currently not available to Liberty.

(3) Current restricted cash includes cash at certain subsidiaries, the transfer
or distribution of which is effectively restricted by the terms of financing
agreements but is otherwise available to the applicable subsidiary for use
in satisfying certain of its obligations.

All of our major credit and other debt agreements contain restrictive
covenants. Failure to comply with these covenants could have a number of
effects, including limitations on our ability to make additional borrowings
under our credit facilities, increases in borrowing costs and the acceleration
of indebtedness. For additional information regarding these covenants, and the
impact of a default under these covenants on our ability to borrow funds, see
"-- Risk Factors" and note 9 to our consolidated financial statements.

Shelf Registration. We currently have an effective shelf registration that
allows us to issue up to an aggregate of $3.5 billion in securities. We have not
yet issued any securities under this registration statement. However, we may,
from time to time, sell any combination of debt securities, common stock,
preferred stock and warrants in one or more offerings up to $3.5 billion.

59

Factors affecting Future Sources of Liquidity and Capital
Resources. Although we are committed to identifying opportunities through
restructuring our business operations and otherwise to reduce our liquidity
needs, it is possible that we may need to incur additional debt or to issue
equity or convertible instruments (subject to restrictions contained in our
credit facilities and other debt agreements), to meet future obligations. Our
ability to supplement our liquidity and capital resources could be affected by a
number of factors, including those discussed under "-- Risk Factors" above. In
particular, the following factors could affect our ability to raise additional
financings:

- general economic conditions, including economic conditions in the
financial and capital markets and the availability of credit in such
markets;

- the financial markets' expectations regarding:

- the current and future performance and cash flows of our retail energy
and wholesale energy operations;

- the success of our efforts to reduce our cost structure and restructure
our operations; and

- our ability to successfully manage regulatory, litigation and other
risks;

- the financial market's expectations regarding any plans we may have to
issue additional equity or incur additional debt for purposes of
acquiring individual ERCOT generating plants; and

- our credit ratings (as discussed in more detail below).

Although we have completed a number of financing transactions in 2003, we
anticipate that continuing depressed conditions within the wholesale electric
markets, our sub-investment grade credit ratings and other uncertainties will
continue to have an impact on our ability to borrow funds on acceptable terms.
If we require, but are unable to obtain, additional sources of financing to meet
our future capital requirements, our financial condition and future results of
operations could be materially adversely affected.

Our long-term credit ratings are, and are likely to remain for the next few
years, below investment grade. Our long-term credit ratings are:

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

(1) Each of the ratings assigned to us by Moody's, Standard & Poor's and Fitch
are sub-investment grade.

(2) Moody's rating description represents its opinion regarding the likely
direction of a rating over an approximately 18-month horizon. A stable
outlook indicates that no change is expected. Standard & Poor's rating
description accesses the potential direction of a credit rating over the
intermediate to long term. A negative outlook means that a rating may be
lowered. Fitch's rating description indicates the direction a rating is
likely to move over a one to two-year period. A stable outlook indicates
that no change is expected.

The ratings of our convertible senior subordinated notes and senior secured
notes are:

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. For a discussion of the impact of previous
downgrades in our credit ratings on our capital requirements, see
"-- Contractual Obligations and Contractual Commitments" below.

LIQUIDITY AND CAPITAL REQUIREMENTS

Our liquidity and capital requirements are primarily a function of our
working capital needs, capital expenditures, debt service requirements and
collateral requirements. Examples of working capital needs include purchases of
fuel and electricity, plant maintenance costs (including required environmental
expenditures) and corporate costs such as payroll.

In 2003, we began a review of our operating structure with the objective of
reducing our costs. During 2003, we identified $140 million of annualized
savings opportunities of which $25 million was realized in 2003 and $125 million
is expected to be realized in 2004. Consistent with our business objectives and
strategies described in "-- Overview," in February 2004 we announced that we
intend to reduce our net debt-to-adjusted EBITDA ratio significantly by the end
of 2006. Consistent with this plan, we have targeted an additional $200 million
in cost reductions. In addition, we have curtailed plans to construct any new
generation plants (apart from the completion of projects that we are
contractually committed to complete), retired or mothballed generation units
that are no longer economic to operate and have sold non-core business
operations and assets (e.g., our European energy operations). With the
implementation of these strategies, we are seeking to restructure our operations
and business with the objective of achieving by the end of 2006 credit metrics
consistent with those that rating agencies currently ascribe to companies with
investment grade status. Our ability to achieve this objective is subject to a
number of assumptions, including our future economic performance. See "-- Risk
Factors."

In 2004, we intend to continue to identify and pursue opportunities to
restructure our business operations in order to reduce our costs and our
liquidity and capital requirements. However, our ability to reduce our cost
structure, while maintaining prudent operating standards, is limited. In
addition, we may incur short-term costs in the form of severance payments and
other restructuring costs as part of our efforts to reduce our cost structure.
Finally, there is a risk that, in restructuring our operations to focus on our
core markets, we may be precluded from exploring business opportunities in other
markets.

61

Capital Expenditures. The following table sets forth the capital
expenditures we incurred in 2003 and the estimates of these expenditures for
2004 through 2006 (in millions):

The future expenditures described in this table include the following
expenditures:

- Generating Projects. As of December 31, 2003, we had two generating
facilities under construction. We completed one in February 2004 and
expect to complete the other in the third quarter of 2004. Total
estimated cost of constructing these facilities is $1.2 billion. As of
December 31, 2003, we had incurred $1.1 billion in construction costs,
property, plant and equipment and spare parts inventory on these
projects, which was funded from debt.

- Environmental Expenditures. We anticipate spending up to $122 million in
capital expenditures from 2004 through 2006 for environmental compliance,
totaling approximately $31 million, $22 million and $69 million for 2004,
2005 and 2006, respectively. In addition, we anticipate spending $40
million in capital expenditures for environmental compliance in 2007.

We have no further capital expenditure commitments in 2007 and 2008.

In addition, we expect to spend $16 million for 2004 through 2008 for
pre-existing environmental conditions and remediations, all of which have been
provided for in our consolidated balance sheet as of December 31, 2003 and are
excluded from the table above.

Major Maintenance Expenses. The following table sets forth the major
maintenance expenses we incurred in 2003 and the estimates of these expenses for
2004 through 2008 (in millions):

Contractual Obligations and Contractual Commitments. In the following
table, we provide disclosure concerning our obligations and commitments to make
future payments under contracts, such as debt and lease agreements and purchase
obligations, as of December 31, 2003 for 2004 through 2009 and thereafter:

62

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

(1) See note 9 to our consolidated financial statements.

(2) See note 14(a) to our consolidated financial statements.

(3) See note 7 to our consolidated financial statements.

(4) See note 14(f) to our consolidated financial statements.

(5) See note 14(d) to our consolidated financial statements.

(6) Included in this amount is $1.1 billion of Orion MidWest and Orion NY credit
maturities (October 2005). Prior to their maturities, we believe that Orion
MidWest's and Orion NY's future cash flows from operations will be
sufficient to meet the scheduled principal payments and required
prepayments. We anticipate refinancing any remaining outstanding borrowings
prior to or upon maturity.

As a result of our March 2003 refinancing and our June and July 2003
capital markets debt issuances, our interest expense has increased
substantially. For additional information, see note 9 to our consolidated
financial statements.

In most cases involving our commercial contracts and/or guarantees, the
impact of further rating downgrades is negligible. The following table details
our cash collateral posted and letters of credit outstanding as of February 20,
2004:

In certain cases, our counterparties have elected not to require us to post
collateral to which they are otherwise entitled under certain agreements.
However, these counterparties retain the right to request such collateral.
Factors that could trigger increased demands for collateral include additional
adverse changes in our industry, negative regulatory or litigation developments
and/or changes in commodity prices. Based on current commodity prices, we
estimate that as of February 20, 2004, we could be contractually required to
post additional collateral of up to $243 million related to our operations. As
of February 20, 2004, we had $31 million in unrestricted cash and cash
equivalents and $959 million available under committed corporate facilities.

We are involved in a number of legal, environmental and other proceedings
before courts and governmental agencies. We are also subject to ongoing
investigations by various governmental agencies. Although we cannot predict the
outcome of these proceedings, many of these matters involve substantial claim
amounts which, in the event of an adverse judgment, could have a material
adverse effect on our results of operations, financial condition and cash flows.
For additional information, see note 15 to our consolidated financial
statements.

OFF-BALANCE SHEET ARRANGEMENTS

In this section we discuss our off-balance sheet arrangements that have or
are reasonably likely to have a current or future material effect on our
financial condition, changes in financial condition, revenues or expenses,
results of operations, liquidity, capital expenditures or capital resources. An
off-balance sheet arrangement is any transaction, agreement or other contractual
arrangement involving an unconsolidated entity under which a company has (a)
made guarantees, (b) a retained or a contingent interest in

63

transferred assets, (c) an obligation under derivative instruments classified as
equity or (d) any obligation arising out of a material variable interest in an
unconsolidated entity that provides financing, liquidity, market risk or credit
risk support to the company, or that engages in leasing, hedging or research and
development arrangements with the company.

In 2002, we formed a qualified special purpose entity as a bankruptcy
remote subsidiary and entered into a receivables facility arrangement, which we
amended in 2003. This arrangement with certain financial institutions allows
them to purchase up to $350 million of undivided interests in our accounts
receivable from certain retail customers (see notes 2(c) and 16 to our
consolidated financial statements). We believe it improves cash flows while
serving as a source of liquidity for our operations.

In 2000, we established three separate sale-leaseback transactions in
connection with the acquisition of the REMA facilities. We used this off-balance
sheet arrangement to finance, in part, the acquisition of these facilities (see
notes 2(c) and 14(a) to our consolidated financial statements).

Certain off-balance sheet transactions that we do not expect to have a
current or future material effect on our results of operations, financial
condition or cash flows are disclosed in notes 8 and 14(e) to our consolidated
financial statements. We also discuss certain arrangements to facilitate the
development, construction, financing and leasing of three power generation
projects, which we consolidated the subsidiaries effective January 1, 2003, in
notes 2(c), 9 and 14(b) to our consolidated financial statements.

HISTORICAL CASH FLOWS

The following table provides an overview of cash flows relating to our
operating, investing and financing activities in 2001, 2002 and 2003:

CASH FLOWS -- OPERATING ACTIVITIES

2003 Compared to 2002 and 2002 Compared to 2001. Net cash provided by
operating activities increased $350 million in 2003 compared to 2002. Net cash
provided by operating activities increased $671 million in 2002 compared to
2001. The increases are detailed as follows:

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

(1) Decrease in net cash outflows from $568 million in 2001 to $246 million in
2002 due to decrease in cash used to meet working capital and other assets
and liabilities requirements. See further analysis below.

(2) Increase in net cash inflows from $612 million in 2001 to $789 million in
2002 due primarily to cash flows provided by our retail energy segment for
retail sales in 2002 due to the Texas retail market opening to full
competition in January 2002, partially offset by a decline in cash flows of
our wholesale energy segment due to a decline in operating results.

64

(3) Change in net cash outflows from $246 million in 2002 to net cash inflows of
$67 million in 2003 due to decrease in cash used to meet working capital and
other assets and liabilities requirements. See further analysis below.

(4) Decrease in net cash inflows from $789 million in 2002 to $775 million in
2003.

Year Ended December 31, 2003. Net cash provided by our operations in 2003
is detailed as follows (in millions):

Net cash flows from continuing operations, excluding changes
in working capital and other assets and liabilities....... $ 775(1)
Reduced cash requirements for margin deposits............... 221(2)
Decrease in accounts receivable............................. 98(3)
Settlement of volumes delivered............................. 66(4)
Changes in income tax receivables, net...................... 56(5)
Net proceeds from receivables facility...................... 23(6)
Decrease in accounts payable................................ (191)(7)
Net option premiums purchased............................... (101)(8)
Increase in restricted cash................................. (68)(9)
Net purchases of emissions credits.......................... (65)
Purchase of interest rate caps.............................. (29)(10)
Increase in lease payments related to REMA.................. (18)(11)
Discontinued operations..................................... 27
Other, net.................................................. 75
-----
Cash provided by operating activities..................... $ 869
=====

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

(1) Due to both our retail energy segment's and wholesale energy segment's
results of operations. See "-- EBIT by Business Segment."

(2) Cash inflows related to our trading and hedging activities, as margin
deposits were primarily replaced with letters of credit.

(3) Decrease primarily related to decrease in power sales volumes in our
wholesale energy segment.

(4) Relates to 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(d) to our consolidated financial statements).

(5) Decrease primarily due to net tax refunds, primarily federal, of $75
million received in 2003.

(6) See note 16 to our consolidated financial statements.

(7) Decrease primarily associated with the decrease in purchased power and fuel
purchases in our wholesale energy segment as a result of decreased hedging
activities.

(8) Purchases relate to our retail energy segment's hedging activities.

(9) Increase primarily related to funds dedicated for the support of lease
obligations of REMA and activities of Orion NY. See note 2(l) to our
consolidated financial statements.

(10) See note 9(c) to our consolidated financial statements.

(11) See note 14(a) to our consolidated financial statements.

65

Year Ended December 31, 2002. Net cash provided by our operations in 2002
is detailed as follows (in millions):

Net cash flows from continuing operations, excluding changes
in working capital and other assets and liabilities....... $ 789(1)
Decrease in restricted cash................................. 282(2)
Decrease in collateral deposits related to an operating
lease..................................................... 136(3)
Two structured transactions settled in 2002................. 121(4)
Net proceeds from receivables facility...................... 95(5)
Decrease in accounts payable................................ (239)(6)
Increase in margin deposits paid............................ (193)(7)
Increase in accounts receivable............................. (136)(8)
Increase in lease payments related to REMA.................. (79)(9)
Increase in inventory....................................... (74)(10)
Settlement of forward starting swaps........................ (55)(11)
Discontinued operations..................................... (24)
Other, net.................................................. (104)
-----
Cash provided by operating activities..................... $ 519
=====

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

(1) Due to both our retail energy segment's and wholesale energy segment's
result of operations. See "-- EBIT by Business Segment."

(2) Decrease primarily attributable to REMA's funds becoming effectively
unrestricted pursuant to REMA's lease obligations, partially offset by
Orion Power's operations.

(3) See note 14(c) to our consolidated financial statements.

(4) See note 7(a) to our consolidated financial statements.

(5) See note 16 to our consolidated financial statements.

(6) Decrease primarily due to timing of cash payments of our wholesale energy
segment.

(7) Cash outflows for margin deposits are related to our trading and hedging
activities and increased partially due to downgrades in our credit ratings
in 2002.

(8) Increase 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.

(9) See note 14(a) to our consolidated financial statements.

(10) Increase due primarily to fuel inventory related to our wholesale energy
segment.

(11) See note 9(c) to our consolidated financial statements.

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Year Ended December 31, 2001. Net cash used in our operations in 2001 is
detailed as follows (in millions):

Net cash outflows from continuing operations, excluding
changes in working capital and other assets and
liabilities............................................... $ 612(1)
Decrease in accounts payable................................ (1,112)(2)
Increase in lease payments related to REMA.................. (181)(3)
Deposits in a collateral account related to an operating
lease..................................................... (145)(4)
Increase in restricted cash primarily related to REMA....... (117)(5)
Two structured transactions entered into in 2001............ (117)(6)
Decrease in accounts receivable............................. 809(7)
Decrease in margin deposits paid............................ 167(8)
Change in intercompany balances with CenterPoint............ 94
Discontinued operations..................................... (196)
Other, net.................................................. 34
-------
Cash used in operating activities......................... $ (152)
=======

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

(1) Due primarily to our wholesale energy segment's results of operations. See
"-- EBIT by Business Segment."

(2) Decrease primarily due to decline in average price paid for gas purchases
related to our wholesale energy segment.

(3) See note 14(a) to our consolidated financial statements.

(4) Net collateral deposits paid by us. See note 14(c) to our consolidated
financial statements.

(5) See notes 2(l) and 9 to our consolidated financial statements.

(6) See note 7(a) to our consolidated financial statements.

(7) Decrease due to decline in revenues due to lower power prices coupled with
timing of cash receipts related to our wholesale energy segment.

(8) Decrease related to reduced net margin deposits on energy trading and
hedging activities as a result of reduced commodity volatility and relative
price levels of natural gas and power.

CASH FLOWS -- INVESTING ACTIVITIES

2003 Compared to 2002. Net cash provided by/used in investing activities
changed by $4.5 billion in 2003 compared to 2002, primarily due to the
acquisition of Orion Power for $2.9 billion in 2002. In addition, cash flows
provided by investing activities of our discontinued operations increased $1.5
billion in 2003 compared to 2002. See below.

2002 Compared to 2001. Net cash used in investing activities increased
$2.6 billion in 2002 compared to 2001, primarily due to the acquisition of Orion
Power for $2.9 billion in 2002. In addition, cash flows from investing
activities of our discontinued operations changed by $231 million in 2002
compared to 2001.

Year Ended December 31, 2003. Net cash provided by investing activities
during 2003 was $1.0 billion, primarily due to cash inflows of $1.6 billion from
our discontinued operations primarily due to net proceeds from the sales of our
Desert Basin plant operations ($285 million) and our European energy operations
($1.4 billion). See notes 22 and 23 to our consolidated financial statements.
This was offset by cash outflows due to capital expenditures of $587 million
primarily related to our power generation operations and development of power
generation projects.

Year Ended December 31, 2002. Net cash used in investing activities during
2002 was $3.5 billion, primarily due to the acquisition of Orion Power for $2.9
billion in February 2002 and $640 million in capital expenditures primarily
related to our power generation operations and development of power generation
projects. This was offset by cash inflows of $119 million from our discontinued
operations primarily due to a $137 million cash dividend from our discontinued
European energy operation's equity investment in NEA.

67

Year Ended December 31, 2001. Net cash used in investing activities during
2001 was $838 million, primarily due to $728 million of capital expenditures
primarily related to our power generation operations and to a lesser extent by
cash outflows of $112 million from our discontinued operations.

CASH FLOWS -- FINANCING ACTIVITIES

2003 Compared to 2002. Net cash used in/provided by financing activities
during 2003 changed by $6.9 billion compared to 2002. See below for discussion.

2002 Compared to 2001. Net cash provided by financing activities during
2002 increased by $3.0 billion compared to 2001. See below for discussion.

Year Ended December 31, 2003. Net cash used in financing activities in
2003 is detailed as follows (in millions):

Prepayments of senior secured term loans.................... $(2,048)(1)
Net payments of senior secured revolving credit facility.... (1,108)(1)
Prepayment of senior revolving credit facility in
conjunction with March 2003 refinancing................... (350)(1)
Payments of financings costs................................ (184)(2)
Net payments on Orion MidWest and Orion NY term loans and
revolving working capital facilities...................... (153)
Net proceeds from senior secured notes issued July 2003..... 1,056(1)
Net proceeds from convertible senior subordinated notes
issued June and July 2003................................. 266(1)
Net proceeds from additional PEDFA bond issuance for Seward
generation plant.......................................... 99(1)
Net borrowings under a financing commitment................. 95(3)
Draws under letters of credit to provide support for REMA's
lease obligations......................................... 42(1)
Discontinued operations..................................... (734)(4)
Other, net.................................................. 131
-------
Cash used in financing activities......................... $(2,888)
=======

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

(1) See note 9 to our consolidated financial statements.

(2) See note 2(r) to our consolidated financial statements.

(3) Net borrowings due to construction agency financing commitment for the
construction of three power generation facilities in the first quarter of
2003 prior to the March 2003 refinancings. See notes 9(a) and 14(b) to our
consolidated financial statements.

(4) See note 22 to our consolidated financial statements.

Year Ended December 31, 2002. Net cash provided by financing activities
during 2002 of $4.0 billion is primarily due 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 increased
due to decreased investments of excess cash in an affiliate of CenterPoint.
These cash inflows were partially offset by (a) the purchase of $200 million in
principal amount of the Orion Power Holdings 4.5% convertible senior notes and
(b) the payment of $145 million under our Orion MidWest and Orion NY credit
agreements. See note 9(a) to our consolidated financial statements.

Year Ended December 31, 2001. Net cash provided by financing activities
during 2001 of $1.0 billion is primarily due to net proceeds from the IPO of
$1.7 billion, offset by $731 million of changes in notes with affiliated
companies and a $189 million treasury stock purchase. Pursuant to the terms of
the master separation agreement with CenterPoint, we used $147 million of the
net IPO proceeds to repay certain indebtedness owed to CenterPoint. Proceeds not
initially utilized from the IPO during 2001 were advanced on a short-term basis
to CenterPoint, which provided a cash management function. As of December 31,
2001, we had $390 million of outstanding advances to CenterPoint. During 2001
and 2002, the IPO

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proceeds were used for repayment of third party borrowings, repurchase of our
common stock, capital expenditures and payment of taxes, interest and other
payables. In May 2001, prior to the closing of the IPO, CenterPoint converted to
equity or contributed to us an aggregate of $1.7 billion of indebtedness owed by
us to CenterPoint of which $35 million was related accrued intercompany interest
expense. Following the IPO, CenterPoint no longer provided financing or credit
support for us, except for specified transactions or for a limited period of
time.

NEW ACCOUNTING PRONOUNCEMENTS, SIGNIFICANT ACCOUNTING POLICIES AND CRITICAL
ACCOUNTING ESTIMATES

NEW ACCOUNTING PRONOUNCEMENTS

For discussion regarding new accounting pronouncements that will impact us,
see note 2(v) to our consolidated financial statements.

SIGNIFICANT ACCOUNTING POLICIES

For discussion regarding our significant accounting policies, see note 2 to
our consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

As required by GAAP, we make a number of estimates and judgments in
preparing our consolidated financial statements. These estimates, to the extent
they differ from actual results, can have a significant impact on our recorded
assets, liabilities, revenues and expenses and related disclosure of contingent
assets and liabilities. In this section, we discuss those estimates that we deem
to be "critical accounting estimates." We consider an estimate to be a material
"critical accounting estimate" due to either (a) the level of subjectivity or
judgment necessary to account for highly uncertain matters or (b) the
susceptibility of such matters to change, and that have a material impact on the
presentation of our financial condition or results of operations. The audit
committee of our board of directors reviews each critical accounting estimate
with our senior management.

GOODWILL.

As of November 1 of each year, we test goodwill for each of our segments.
In addition, we test goodwill if an event occurs indicating that an asset
carrying value may not be recoverable. The following table shows net goodwill by
reportable segment for the indicated period:

In 2001, we determined goodwill associated with our communications business
was impaired and recorded a goodwill impairment of $19 million that was reported
in amortization expense. In 2002, we recognized impairment charges totaling $716
million related to our European energy segment goodwill ($234 million reported
as a cumulative effect of a change in accounting principle and $482 million
reported as a component of loss from discontinued operations). In 2003, we
recognized impairment charges totaling $985 million related to our wholesale
energy reporting unit. For information regarding impairment charges reflected in
the reported periods in our consolidated financial statements, see note 6 to our
consolidated financial statements.

We estimate the fair value of our wholesale energy segment based on a
number of subjective factors, including: (a) appropriate weighting of valuation
approaches (income approach, market approach and comparable public company
approach), (b) projections about future power generation margins,

69

(c) estimates of our future cost structure, (d) discount rates for our estimated
cash flows, (e) selection of peer group companies for the public company
approach, (f) required level of working capital, (g) assumed terminal value and
(h) time horizon of cash flow forecasts.

We consider the estimate of fair value to be a critical accounting estimate
for our wholesale energy segment because (a) a potential goodwill impairment
could have a material impact on our financial position and results of operations
and (b) the estimate is based on a number of highly subjective judgments and
assumptions. We do not consider the estimate of fair value and goodwill of our
retail energy segment to be a critical accounting estimate as our prior
estimates of fair value for that reporting unit significantly exceeded the
carrying value.

In determining the fair value of our wholesale energy segment in 2003, we
made the following key assumptions: (a) the markets in which we operate will
continue to be deregulated; (b) demand for electricity will grow, which will
result in lower reserve margins; (c) there will be a recovery in electricity
margins over time to a level sufficient such that companies building new
generation facilities can earn a reasonable rate of return on their investment
and (d) the economics of future construction of new generation facilities will
likely be driven by regulated utilities. As part of our process, we modeled all
of our power generation facilities and those of others in the regions in which
we operate. The following table summarizes certain of these significant
assumptions:

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

(1) The numbers of years used in the internal cash flow analysis changed from 5
years in the January 2002 test to 15 years due to the fact that five years
in the forecast did not capture the full impact of the cyclical nature of
our wholesale energy operations. Additional periods were included in the
forecasts to derive an appropriate forecast period, which was used to
determine the estimated terminal value. As of January 2002, based on current
market conditions in the wholesale energy industry, management did not
believe additional periods beyond five years in the forecast were required.

(2) The EBITDA multiple for terminal values changed from 6.0 in the January 2002
test to 7.0 to 7.5 in the November 2002 test and from 7.0 to 7.5 in the
November 2002 test to 7.5 in the 2003 tests due to the independent
appraiser's updated analysis of the public guideline companies that
indicated higher multiples were appropriate to calculate the terminal values
at the applicable dates.

(3) Depending on the region, the specific rate is projected to be somewhat
higher or lower.

(4) Based on our assumption in 2003 that regulated utilities will be the primary
drivers underlying the construction of new generation facilities, we have
assumed that the after-tax return on investment will yield a return
representative of a regulated utility's cost of capital (7.5%) rather than
that of an independent power producer (9.0%). Based on changes in assumed
market conditions, including regulatory rules, we have changed the projected
time horizon for substantially achieving the after-tax return on investment
to 2008 -- 2012 (depending on region). Formerly, we had assumed that the
time horizon for substantially achieving this rate of return was
2006 -- 2010.

Because we recognized a goodwill impairment in 2003, in the near future, if
our wholesale energy market outlook changes negatively, we could have additional
impairments of goodwill that would need to be recognized. In addition, our
ongoing evaluation of our wholesale energy business could result in decisions to
mothball, retire or dispose of additional generation assets, any of which could
result in additional impairment charges related to goodwill, impact our fixed
assets' depreciable lives or result in fixed asset impairment charges.

CALIFORNIA NET RECEIVABLES.

As described in note 15(b) to our consolidated financial statements, we
have recorded a $189 million net receivable, included in the $242 million below,
as of December 31, 2003 for energy sales in California during the period from
October 2, 2000 through June 20, 2001. The receivable is an estimate based on a

70

number of assumptions regarding (a) the outcome of a FERC refund proceeding and
(b) the realizability of the receivables due to creditworthiness issues.

We consider this estimate, which affects only our wholesale energy segment,
to be a critical accounting estimate because (a) changes in this estimate can
have a material impact on our financial position and results of operations and
(b) the estimate of the net receivable is based on a number of highly subjective
judgments and assumptions. In estimating the net receivable, we have made a
number of assumptions, as set forth in the following table, regarding (a) the
estimated refund obligation, (b) the credit reserve and (c) the interest
receivable:

For information regarding related changes in our estimates, see note 15(b)
to our consolidated financial statements.

PROPERTY, PLANT AND EQUIPMENT.

We evaluate our property, plant and equipment for impairment if events
indicate that the carrying value of these assets may not be recoverable. If the
sum of the undiscounted expected future cash flows from an asset is less than
the carrying value of the asset, we recognize an impairment by subtracting the
fair value of the asset from its carrying value. We consider the fair value
estimate to be a critical accounting estimate because (a) an impairment can have
a material impact on our financial position and results of operations and (b)
the highly subjective nature of the many judgments and assumptions used in the
estimate. The estimate of carrying value primarily affects our wholesale energy
segment, which holds approximately 97% of our total net property, plant and
equipment.

In determining the existence of an impairment in carrying value, we make a
number of subjective assumptions as to: (a) whether an indicator of impairment
has occurred, (b) the grouping of assets, (c) the intention of "holding" versus
"selling" an asset, (d) the forecast of undiscounted expected future cash flow
over the asset's estimated useful life and (e) if an impairment exists, the fair
value of the asset or asset group. If our wholesale energy market outlook
changes negatively, we could have additional impairments of our property, plant
and equipment in future periods. Additionally, future decisions to mothball,
retire or dispose of assets could result in impairment charges. It is also
possible that in restructuring and simplifying our operations in the future as
discussed in "-- Overview" of this section, we may increase the risk of an
impairment of certain assets, such as information technology systems, to the
extent that changes in our business eliminate the need for such assets.

During 2001, we decided to exit our communications business and recorded
fixed asset impairments of $22 million, which is recorded in depreciation
expense (see note 17 to our consolidated financial statements). During 2002, we
recognized a $37 million impairment recorded in depreciation expense related to
steam and combustion turbines and two heat recovery steam generators (see note
14(c) to our consolidated financial statements). During 2003, we recognized
depreciation expense of $7 million related to the write-down of an office
building to its fair value less cost to sell, which was determined with the
assistance of an independent appraiser.

For information concerning the possible impairment of our Liberty plant,
see note 15(c) to our consolidated financial statements.

71

DEPRECIATION EXPENSE.

As of December 31, 2003, approximately 73% of our total gross property,
plant and equipment was comprised of electric generation facilities and
equipment. We estimate depreciation expense using the straight-line method based
on projected useful lives. We consider these estimates, which affect primarily
our wholesale segment, to be critical accounting estimates because (a) they
require subjective judgments regarding the estimated useful lives of property,
plant and equipment and (b) changes in the estimates could affect future
depreciation expense and hence our results of operations.

In 2002, we recognized $15 million in depreciation expense for the early
retirement of power generation units at the Warren facility. During 2003, we
recognized $14 million in depreciation expense for the early retirement of power
generation units at two facilities. For additional information regarding
depreciation expense, see note 2(f) to our consolidated financial statements.

For power generation facilities purchased in acquisitions, we estimate
useful life based on: (a) the condition of the acquired facilities, (b) the fuel
type of the generation facilities, (c) future environmental requirements, (d)
projected maintenance and (e) projected future cash flows. For power generation
facilities that we construct, we use the design life provided in the
construction contract. In the absence of a specified design life, we estimate
the weighted average life of the components of a power generation unit of a
facility.

Significant portions of our facilities were constructed many years ago.
Older generating equipment may require significant upgrades, which could affect
judgments to their useful life. In addition, alternative technologies could
reduce the useful lives of portions of these facilities.

If we had assumed that our gross property, plant and equipments' lives had
decreased by 10% from the estimated lives used in our calculation of
depreciation expense for 2003, our depreciation expense would have been
approximately $399 million or 11% higher.

TRADING AND DERIVATIVE ACTIVITIES.

Legacy Trading Positions. We report our legacy trading positions on our
consolidated balance sheets at fair value. As discussed in Item 7A "Quantitative
and Qualitative Disclosures about Non-Trading and Trading Activities and Related
Market Risks" of this report, we determine the fair value of our trading
assets/liabilities based on (a) prices actively quoted, (b) prices provided by
other external sources or (c) prices based on models and other valuation
methods.

We consider the fair values of our trading assets/liabilities to be a
critical accounting estimate because they are highly susceptible to change from
period to period and are dependent on many subjective factors, including (a)
estimated forward market price curves; (b) valuation adjustments relating to
time value; (c) liquidity valuation adjustments, calculated by utilizing
observed market price liquidity, which represent the estimated impact on fair
values resulting from the widening of bid/ask spreads for transactions occurring
further in the future; (d) costs of administering future obligations under
existing contracts and (e) credit adjustments based on estimated defaults by
counterparties that are calculated using historical default probabilities for
corporate bonds for companies with similar credit ratings. These estimates
affect our wholesale energy segment and, prior to 2003, our retail energy
segment.

To determine the fair value for energy trading derivatives where there are
no market quotes or external valuation services, we rely on modeling techniques.
In certain circumstances, prices are modeled using a variety of techniques such
as moving averages, calibration models and other time series techniques, market
equilibrium analysis, extrapolation/interpolation, a range of contingent claims
valuation methods and volumetric risk modeling. There is inherent risk in
valuation modeling given the complexity and volatility of energy markets.
Therefore, it is possible that results in future periods may be materially
different as contracts are ultimately settled.

Non-Trading Derivative Activities. We report our non-trading derivative
assets/liabilities on our consolidated balance sheets at fair value. As
discussed in Item 7A "Quantitative and Qualitative

72

Disclosures about Non-Trading and Trading Activities and Related Market Risks"
of this report, we estimate the fair value of our non-trading derivative
assets/liabilities based on (a) prices actively quoted, (b) prices provided by
other external sources or (c) prices based on models and other valuation
methods. The fair values and deferred gains and losses of our non-trading
derivative instruments and contractual commitments qualifying and designated as
hedges are based on the same valuation techniques described above for energy
trading activities.

We consider the fair values of our non-trading derivative instruments to be
a critical accounting estimate due to the same factors applicable to our legacy
trading activities. We also believe estimates regarding the probability that
hedged forecasted transactions will occur by the end of the time period
specified in the original hedging documentation to be a critical accounting
estimate. These estimates affect all of our reportable operating segments.

For additional information regarding our legacy trading positions and
non-trading derivative activities, see notes 2(d), 7 and 9(c) to our
consolidated financial statements and Item 7A "Quantitative and Qualitative
Disclosures about Non-Trading and Trading Activities and Related Market Risks."
Item 7A includes value-at-risk information related to our legacy trading
positions and an analysis of the impact a 10% hypothetical adverse change on the
fair value of our non-trading derivatives at December 31, 2002 and 2003.\

RETAIL ENERGY SEGMENT ESTIMATED REVENUES AND ENERGY SUPPLY COSTS.

Accrued Unbilled Revenues. In 2003, accrued unbilled revenues of $290
million represented approximately 3% of our consolidated revenues and 5% of our
retail energy segment's revenues. In 2002, accrued unbilled revenues of $216
million represented approximately 2% of consolidated revenues and 5% of our
retail energy segment's revenues.

Accrued unbilled revenues are based on our estimate of the amount of energy
delivered to customers since the date of the last meter reading and on customer
metering information (which we have limited ability to confirm) furnished to us
by the ERCOT ISO. In estimating electricity usage volumes, we rely upon daily
forecasted volumes, estimated customer usage by class and applicable customer
rates based on analyses reflecting significant historical trends and experience.
Volume estimates by customers are then multiplied by our estimated rate by
customer class to calculate the unbilled revenues to be recorded. We record the
unbilled revenues in the current reporting period and then reverse it in the
subsequent reporting period when actual usage and rates are known and billed.

We consider our estimate of accrued unbilled revenue to be a critical
accounting estimate because of (a) the uncertainty inherent in estimating
customer volumes, (b) the problems or delays in the flow of information between
the ERCOT ISO, the transmission and distribution utilities and us and other
retail electric providers, (c) the potential negative impact on our business,
results of operation and cash flows based on the receipt of inaccurate or
delayed information from the transmission and distribution utilities or the
ERCOT ISO and (d) the fact that as additional information becomes available, the
impact of recognizing revised estimates in subsequent periods relating to a
previous period can be material to our retail energy segment's and our
consolidated results of operations. If our estimate of either electricity usage
volumes or estimated rates were to increase or decrease by 3%, our accrued
unbilled revenues at December 31, 2003 would have increased or decreased by
approximately $9 million. A 3% increase or decrease in both our estimated
electricity usage and estimated rates would have increased or decreased our
accrued unbilled revenues at December 31, 2003 by approximately $17 million.

Estimated Energy Supply Costs. We record energy supply costs for
electricity sales and services to retail customers based on estimated supply
volumes and an estimated rate per MWh for the applicable reporting period. We
consider this accounting estimate to be a critical accounting estimate because
of (a) the uncertainty inherent in estimating both the supply volumes and the
rate per MWh and (b) the uncertainty related to the ERCOT ISO settlement process
(as discussed below) and (c) the fact that, as additional information becomes
available, the impact of recognizing revised estimates in subsequent periods

73

relating to a previous period can be material to our retail energy segment's and
our consolidated results of operations.

In 2002 and 2003, a portion of our energy supply costs ($61 million and $53
million, respectively) consisted of estimated transmission and distribution
charges not billed by the transmission and distribution utilities.

In estimating supply volumes, we consider the effects of historical
customer volumes, weather factors and usage by customer class. We estimate our
transmission and distribution delivery fees using the same method that we use
for electricity sales and services to retail customers. In addition, we estimate
ERCOT ISO fees based on historical trends, estimated supply volumes and initial
ERCOT ISO settlements. Volume estimates are then multiplied by the estimated
rate and recorded as purchased power expense in the applicable reporting period.
If our estimate of electricity usage volumes increased or decreased by 3%, our
energy supply costs would have increased or decreased by approximately $6
million. Changes in our volume usage would have resulted in a similar offsetting
change in billed volumes, thus partially mitigating our energy supply costs.

Changes in Estimates. During 2003, we revised our estimates and
assumptions related to retail energy revenues and energy supply costs in 2002.
The revisions resulted in the recognition in 2003 of $39 million of income. As
additional information becomes available, we may recognize additional income or
losses.

Dependence on ERCOT ISO Settlement Procedures. In Texas, our primary
retail energy market, the ERCOT ISO is responsible for scheduling and settling
all electricity volumes and related fees. As part of settlement, the ERCOT ISO
communicates actual volumes compared to 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' administrative fees; reliability must run contract fees; out of
merit energy fees and out of merit capacity fees. The ERCOT ISO allocates these
and other fees to market participants based on each market participant's share
of the total load. We may not know about these fees, which are generally outside
of our control, until the ERCOT ISO bills them. If the ERCOT ISO's records
indicate that our volumes delivered were greater than the volumes our records
indicate, we may be billed a larger than expected share of these total fees.

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 12 months after electricity is delivered. We record our
estimated supply costs and related fees using estimated supply volumes, as
discussed above, and adjust those costs upon receipt of the ERCOT ISO
information. Delays in settlements could materially affect the accuracy of our
recorded energy supply costs and related fees.

The ERCOT ISO volume settlement process has been delayed on several
occasions because of operational problems with data management among 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 2001 to December 2001. The ERCOT
ISO then temporarily suspended true-up settlement calculations 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. In 2003,
the ERCOT ISO prepared true-up settlement calculations for the period January
2002 through December 2002. The ERCOT ISO has scheduled to resume true-up
settlement calculations for 2003 in April 2004.

These settlement calculations indicate that our customers utilized greater
volumes of electricity than our records indicated. We have invoked the ERCOT
ISO's dispute resolution process for settlement calculations for the period from
January 2002 to date. As of December 31, 2003, the amount in dispute with the
ERCOT ISO is $11 million due to differences in volumes partially offset by
unaccounted-for-energy costs variances.

74

LOSS CONTINGENCIES.

We record a loss contingency when it is probable that a liability has been
incurred and the amount of the loss can be reasonably estimated. We regularly
analyze current information and, as necessary, provide accruals for probable
liabilities on the eventual disposition of those matters that can be estimated.
We consider these estimates to be critical accounting estimates because (a) they
entail significant judgment by us regarding probabilities and ranges of
exposure, (b) the ultimate outcome of the proceedings relating to these
contingencies is unknown and (c) the ultimate outcome could have a material
adverse effect on our results of operations, financial condition and cash flows.
Estimates of contingent losses affect all our reportable segments. For a
discussion of these contingencies, see note 15 to our consolidated financial
statements.

DEFERRED TAX ASSETS VALUATION ALLOWANCE AND TAX LIABILITIES.

We estimate (a) income taxes in each of the jurisdictions in which we
operate, (b) net deferred tax assets based on expected future taxable benefits
in such jurisdictions and (c) valuation allowance for deferred tax assets. For
additional information regarding these estimates, which affect all of our
reportable segments, see note 13 to our consolidated financial statements. We
consider these estimates to be a critical accounting estimate because (a) they
require estimates of projected future operating results (which are inherently
imprecise) and (b) they depend on assumptions regarding our ability to generate
future taxable income during the periods in which temporary differences are
deductible.

In addition, we recognize contingent tax liabilities through tax expense
and tax expense for discontinued operations for estimated exposures related to
our current tax positions. We evaluate the need for contingent tax liabilities
on a quarterly basis and any change in the amount will be recorded in our
results of operations, as appropriate. It could take several years to resolve
certain of these contingencies.

RELATED PARTY TRANSACTIONS

For a discussion of related party transactions, see notes 3 and 4 to our
consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT NON-TRADING AND TRADING
ACTIVITIES AND RELATED MARKET RISKS.

MARKET RISK AND RISK MANAGEMENT

We are exposed to various market risks. These risks arise from the
ownership of our assets and operation of our business. Most of the revenues,
expenses, 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.

During the normal course of business, we review our hedging strategies and
determine the hedging approach we deem appropriate based upon the circumstances
of each situation. We frequently utilize derivative instruments to execute our
risk management and hedging strategies. Derivative instruments are instruments,
such as futures, forward contracts, swaps or options that derive their value
from underlying assets, indices, reference rates or a combination of these
factors. These derivative instruments include negotiated contracts, which are
referred to as over-the-counter derivatives, and instruments that are listed and
traded on an exchange.

We primarily use derivative instruments to manage and hedge exposures, such
as exposure to changes in electricity and fuel prices and interest rate risk on
our floating-rate borrowings. We believe that the associated market risk of
these instruments can best be understood relative to the underlying assets or
risk being hedged and our hedging strategy.

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. In March 2003,
we discontinued our proprietary trading business. Trading positions taken prior
to our decision to exit this business are managed solely for purposes of closing
them on economical terms.

We have a risk control framework designed to monitor, measure and define
appropriate transactions to hedge and manage the risk in our existing portfolio
of assets and contracts and to authorize new transactions. These risks fall into
three different categories: market risk, credit risk and operational risk. We
believe that we have effective procedures for evaluating and managing these
risks to which we are exposed. Key risk control activities include definition of
appropriate transactions for hedging, credit review and approval, credit and
performance risk measurement and monitoring, validation of transactions,
portfolio valuation and daily portfolio reporting including mark-to-market
valuation, value-at-risk and other risk measurement metrics. We seek to monitor
and control our risk exposures through a variety of separate but complementary
processes and committees, which involve business unit management, senior
management and our board of directors.

The effectiveness of our policies and procedures for managing risk exposure
can never be completely estimated or fully assured. For example, we could
experience losses, which could have a material adverse effect on our results of
operations, financial condition or cash flows from unexpectedly large or rapid
movements or disruptions in the energy markets, from regulatory-driven market
rule changes and/or bankruptcy of customers or counterparties.

Given our current credit and liquidity situation and other factors, we have
reduced our 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.

See notes 2(d) and 7 to our consolidated financial statements for the
accounting for these types of transactions.

NON-TRADING MARKET RISK

Commodity Price Risk. Commodity price risk is an inherent component of
wholesale and retail electric businesses. Prior to the energy delivery period,
we attempt to hedge, in part, the economics of our

76

wholesale and retail electric businesses. Derivative instruments are used to
mitigate exposure to variability in future cash flows from probable, anticipated
future transactions attributable to a commodity risk.

The following table sets forth the fair values of the contracts related to
our net non-trading derivative assets and liabilities as of December 31, 2003:

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

(1) Represents our NYMEX futures positions in natural gas and crude oil. NYMEX
has quoted prices for natural gas and crude oil for the next 72 and 30
months, respectively.

(2) Represents our forward positions in natural gas and power at points for
which OTC broker quotes are available, which on average, extend 36 and 24
months into the future, respectively. Positions are valued against
internally developed forward market price curves that are frequently
validated and recalibrated against OTC broker quotes. This category also
includes some transactions whose prices are obtained from external sources
and then modeled to hourly, daily or monthly prices, as appropriate.

(3) Represents the value of (a) our valuation adjustments for liquidity, credit
and administrative costs, (b) options or structured transactions not quoted
by an exchange or OTC broker, but for which the prices of the underlying are
available and (c) transactions for which an internally developed price curve
was constructed as a result of the long-dated nature of the transaction or
the illiquidity of the market point.

The fair values in the above table are subject to significant changes based
on fluctuating market prices and conditions. Changes in our 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 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.

We assess the risk of our non-trading derivatives using a sensitivity
analysis method. 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
December 31, 2003 levels would have decreased the fair value of our non-trading
energy derivatives by $70 million. Of this amount, $63 million relates to a loss
in fair value of our non-trading derivatives that are designated as cash flow
hedges and $7 million relates to a loss in earnings of our economic hedges. A
decrease of 10% in the market prices of energy commodities from their December
31, 2002 levels would have decreased the fair value of our non-trading energy
derivatives by $38 million.

The above analysis of the non-trading energy derivatives utilized for
hedging purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas and electric power to which the hedges relate. Furthermore, the non-
trading energy derivative portfolio is managed to complement our asset
portfolio, thereby reducing overall risks. Therefore, the adverse impact to the
fair value of the portfolio of non-trading energy derivatives held

77

for hedging purposes associated with the hypothetical changes in commodity
prices referenced above would be offset by a favorable impact on the underlying
hedged physical transactions, assuming:

- the non-trading energy derivatives are not closed out in advance of their
expected term;

- the non-trading energy derivatives continue to function effectively as
hedges of the underlying risk;

and

- as applicable, anticipated underlying transactions settle as expected.

If any of the above-mentioned assumptions cease to be true, a loss on the
derivative instruments may occur, or the options might be worthless as
determined by the prevailing market value on their termination or maturity date,
whichever comes first. Non-trading energy derivatives, which qualify as cash
flow hedges, and which are effective as hedges, may still have some percentage
that is not effective. The change in value of the non-trading energy
derivatives, which represents the ineffective component of the cash flow hedges,
is recorded in our results of operations. During 2001, 2002 and 2003, we
recognized a gain of $28 million, a loss of $17 million and a loss of $20
million, respectively, in our results of operations due to hedge
ineffectiveness.

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. In addition, we have entered into interest
rate swap and interest rate cap agreements to mitigate our exposure to interest
rate fluctuations associated with certain of our variable rate debt instruments.
We assess interest rate risks using a sensitivity analysis method. The table
below provides information concerning our financial instruments as of December
31, 2002 and 2003, that are sensitive to changes in interest rates:

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

(1) See note 18 to our consolidated financial statements for further discussion
on the fair market value of our financial instruments.

(2) Excludes adjustment to fair value of our interest rate swaps.

(3) Excludes Liberty's debt.

(4) As of December 31, 2002, we had floating rate debt with a carrying value of
$5.9 billion, excluding adjustment to fair value of interest rate swaps and
Liberty's debt. There was no active market for our floating rate debt
obligations as of December 31, 2002.

78

(5) These derivative instruments qualify for hedge accounting under SFAS No. 133
and the periodic settlements are recognized as an adjustment to interest
expense in our results of operations over the term of the related agreement.
As of December 31, 2002 and 2003, these swaps have negative termination
values (i.e., we would have to pay). See note 9(c) to our consolidated
financial statements.

TRADING MARKET RISK

In our results of operations, historically, our trading activities included
(a) transactions establishing open positions in the energy markets, primarily on
a short-term basis and (b) energy price risk management services to customers
primarily related to natural gas, electric power and other energy-related
commodities. We provided these services by utilizing a variety of derivative
instruments. We accounted for these transactions under mark-to-market accounting
and continue to account for the remaining legacy positions under mark-to-market
accounting. Our electricity sales to large commercial, industrial and
institutional customers under contracts executed before October 25, 2002 were
accounted for under the mark-to-market method of accounting upon contract
execution. For further discussion of these activities, see notes 2(d) and 7 to
our consolidated financial statements.

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

The following table sets forth the fair values of the contracts related to
our legacy net trading assets and liabilities as of December 31, 2003:

For information regarding "prices actively quoted," "prices provided by
other external sources" and "prices based on models and other valuation
methods," see discussion above related to non-trading derivative assets and
liabilities.

The fair values in the above table are subject to significant changes based
on fluctuating market prices and conditions. For further discussion of items
resulting in changes in the valuation of the portfolio of trading contracts, see
discussion above related to non-trading derivative assets and liabilities.

79

The following table sets forth our consolidated realized and unrealized
trading margins for 2001, 2002 and 2003:

Below is an analysis of our net consolidated trading assets and liabilities
for 2001, 2002 and 2003.

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

(1) See note 2(d) to our consolidated financial statements.

Fair Value of New Contracts -- General. The fair value of retail energy
segment electric sales contracts with large commercial, industrial and
institutional customers was determined by comparing the contract price to an
estimate of the market cost of delivered retail energy and applying the
estimated volumes under the provisions of these contracts. The calculation of
the estimated cost of energy involves estimating the customer's anticipated load
volume, and using forward ERCOT OTC commodity prices, adjusted for the
customer's anticipated load characteristics. The delivery costs were estimated
at the time sales contracts were executed. These costs were based on published
rates and our experience of actual delivery costs. The fair values of these
energy supply contracts were estimated using ERCOT OTC forward price and
volatility curves and correlations among power and fuel prices specific to the
ERCOT Region, net of credit risk. The fair values of new wholesale energy
contracts at inception are estimated using OTC forward price and volatility
curves and correlation among power and fuel prices, net of estimated credit
risk.

Fair Value of New Contracts -- 2002. During 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 2002, we recognized total fair value of $43 million for these contracts
at the inception dates. We entered into energy supply contracts to substantially
hedge the economics of these contracts. These contracts had an aggregate fair
value of $8 million at the contract inception dates. The remaining fair value of
contracts entered into during 2002 recorded at inception of $6 million primarily
relates to natural gas transportation contracts entered into by our wholesale
energy segment.

80

Changes in Fair Values Attributable to Changes in Valuation Techniques and
Assumptions -- 2002. During 2002, the following changes in valuation techniques
and assumptions were made:

- 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.

- 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 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 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 believed the unaccounted-for-energy factor was
effectively 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 assets by $9 million.

Changes in Fair Values Attributable to Changes in Valuation Techniques and
Assumptions -- 2003. During 2003, the following changes in valuation techniques
and assumptions were made:

- We modified our estimated probabilities of counterparty default and
considered master netting agreements, which resulted in a decrease in
credit reserves of $10 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.

- We modified our assumptions for liquidity reserves to consider the
widening of bid/ask spreads for transactions occurring further into the
future, which resulted in an increase in the liquidity reserves of $5
million.

- We adjusted our discount rate used in valuing derivative transactions to
a risk-free United States treasury rate from an investment-grade utility
rate, which resulted in an increase in fair value of $4 million.

We employ a risk management system to mitigate the risks associated with
our legacy trading activities. These activities involve market risk associated
with managing these energy commodities. Historically, our trading activities
depended on price and volatility changes to create business opportunities, but
within authorized limits.

We primarily assess the risk of our legacy trading 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

81

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.

Our value-at-risk limits are set by the audit committee of our board of
directors. Risk limits for our legacy trading activities include both
value-at-risk as well as other non-statistical measures of portfolio exposure.
The risk management process supplements the measurement and enforcement of the
limit metrics with additional analyses including stress testing the portfolio
for extreme events and back-testing the value-at-risk model.

Our value-at-risk model utilizes four major parameters: confidence level,
volatility, correlation and holding period.

- Confidence level: Natural gas and petroleum products have a confidence
interval of 95% and power products have a confidence interval of 99%. The
confidence level for power products is higher in order to capture the
non-normality of power price behavior.

- Volatility: Calculated daily from historical forward prices using the
exponentially weighted moving average method.

- Correlation: Calculated daily from daily volatilities and historical
forward prices using the exponentially weighted moving average method.
This parameter is included to account for the diversification of the
portfolio.

- Holding period: Natural gas and petroleum products generally have one day
holding periods for 2002 and two day holding periods for 2003. Power
products have holding periods of 1 to 20 days for 2002 and 5 to 20 days
for 2003 based on the risk profile of the portfolio. The holding periods
for power products reflect our efforts to appropriately account for
possible liquidation periods of more than one or five days, as
applicable, which is reasonable for some non-standard products. The
change in assumptions for the holding periods for natural gas and
petroleum products and power products in 2003 did not have a material
impact on the value-at-risk calculation.

Assuming a confidence level of 95% and a one-day holding period, if
value-at-risk is calculated at $10 million, we may state that there is a one in
20 chance that if prices move against our consolidated diversified positions,
our pre-tax loss in liquidating or offsetting with hedges, our applicable
portfolio in a one-day period would exceed $10 million.

While we believe that our assumptions and approximations are reasonable for
calculating value-at-risk, there is no uniform industry methodology for
estimating value-at-risk, and different assumptions and/or approximations could
produce materially different value-at-risk estimates.

An inherent limitation of value-at-risk is that past market risk may not
produce accurate predictions of future market risk. Moreover, value-at-risk
calculated for a specified holding period does not fully capture the market risk
of positions that cannot be liquidated or offset with hedges within that
specified period. Future transactions, market volatility, reduction of market
liquidity, failure of counterparties to satisfy their contractual obligations
and/or a failure of risk controls could result in material losses from our
legacy trading activities.

The following table presents the daily value-at-risk for substantially all
of our legacy trading positions for our continuing operations for 2002 and 2003:

82

During 2003, average value-at-risk exposure was lower compared to 2002 due
to certain power trading activities in ERCOT related to our retail energy
segment no longer being accounted for on a mark-to-market method of accounting.
See note 2(d) to our consolidated financial statements. Lower overall trading
volumes during 2003 due to discontinuing proprietary trading activities 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 in the first quarter of 2003.

CREDIT RISK

Credit risk relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. Credit risk is inherent in our
commercial activities. See note 7(c) to our consolidated financial statements
for a discussion of our credit risk and policies.

The following table includes: trading and derivative assets, accounts
receivable, after taking into consideration netting within each contract and any
master netting contracts with counterparties, as of December 31, 2003:

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

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

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

Trading and derivative assets and accounts receivable are presented
separately in our consolidated balance sheets. The trading and derivative assets
and accounts receivable are set-off separately in our consolidated balance
sheets although in most cases contracts permit the set-off of trading and
derivative assets and accounts receivable with a given counterparty. For the
purpose of disclosing the credit risk, all assets and liabilities with a given
counterparty were set-off if the counterparty has entered into a contract with
us that permits such set-off.

The above table excludes amounts related to contracts classified as
"normal" in accordance with SFAS No. 133 and non-derivative contractual
commitments that are not recorded in our consolidated balance sheets, except for
any related accounts receivable. Such contractual commitments contain credit
risk and economic risk in the case of nonperformance by a counterparty.
Nonperformance by counterparties under these contractual commitments could have
a material adverse impact on our future results of operations, financial
condition and cash flows.

For information regarding credit risk related to one counterparty
representing more than 10% of our total credit exposure, see note 7(c) to our
consolidated financial statements.

* * *

83

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

INDEX TO FINANCIAL STATEMENTS

RELIANT RESOURCES, INC. AND SUBSIDIARIES

Responsibility for Financial Reporting...................... F-2
Independent Auditors' Report................................ F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-4
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-6
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) for the
Years Ended December 31, 2001, 2002 and 2003................ F-7
Notes to Consolidated Financial Statements.................. F-10
Supplementary Data.......................................... F-107

F-1

RESPONSIBILITY FOR FINANCIAL REPORTING

The accompanying consolidated financial statements of Reliant Resources,
Inc. and subsidiaries were prepared by management, which is responsible for
their integrity and objectivity. The statements were prepared in accordance with
accounting principles generally accepted in the United States of America and
include amounts that are based on management's best judgments and estimates.

Reliant Resources, Inc.'s system of internal controls is designed to
provide reasonable assurance as to the reliability of financial records and
reporting and the protection of assets. The system of controls provides for
appropriate division of responsibility and the application of policies and
procedures that are consistent with applicable standards of accounting and
administration. Internal controls are monitored through recurring internal audit
programs and are updated as our businesses and business conditions change.

The Audit Committee, composed solely of outside directors, determines that
management is fulfilling its financial responsibilities by meeting periodically
with management, the independent auditors and Reliant Resources, Inc.'s internal
auditors, to review internal accounting control and assess the effectiveness of
our disclosure controls and procedures. The Audit Committee is responsible for
appointing the independent auditors and reviewing the scope of all audits and
the accounting principles applied in our financial reporting. Deloitte & Touche
LLP has been engaged as independent auditors to audit the accompanying
consolidated financial statements and issue their report thereon, which appears
on the following page.

To ensure complete independence, our internal auditors and Deloitte &
Touche LLP have full and free access to meet with the Audit Committee, without
management present, to discuss the results of their audits, the quality of our
financial reporting and the adequacy of our internal controls and disclosure
controls and procedures.

We believe that Reliant Resources, Inc.'s system of internal controls,
combined with the activities of the internal auditors and the Audit Committee,
provides reasonable assurance of the integrity of our financial reporting.

/s/ JOEL V. STAFF /s/ MARK M. JACOBS
- -------------------------------------------- --------------------------------------------
Joel V. Staff Mark M. Jacobs
Chairman and Executive Vice President and
Chief Executive Officer Chief Financial Officer

F-2

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Stockholders of
Reliant Resources, Inc. and Subsidiaries
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant
Resources, Inc. and subsidiaries (the "Company"), as of December 31, 2002 and
2003, and the related consolidated statements of operations, stockholders'
equity and comprehensive income (loss), and cash flows for each of the three
years in the period ended December 31, 2003. Our audits also included the
financial statement schedules (Schedule I and Schedule II) listed in the Index
at Item 15(a)(2). These financial statements and financial statement schedules
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements and financial statement
schedules based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2002 and 2003, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, present fairly
in all material respects the information set forth therein.

As discussed in notes 2, 6 and 7 to the consolidated financial statements,
the Company changed its accounting for asset retirement obligations, energy
trading contracts, consolidation of variable interest entities and its
presentation of revenues and costs of sales associated with non-trading
commodity derivative activities in 2003; its method of presenting trading and
marketing activities from a gross to a net basis and its accounting for goodwill
and other intangibles in 2002; and its accounting for derivative contracts and
hedging activities in 2001.

DELOITTE & TOUCHE LLP

Houston, Texas
March 5, 2004

F-3

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS)

See Notes to our Consolidated Financial Statements
F-4

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)

See Notes to our Consolidated Financial Statements
F-5

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)

See Notes to our Consolidated Financial Statements
F-6

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)
(THOUSANDS OF DOLLARS)

F-7

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(LOSS) -- (CONTINUED)
(THOUSANDS OF DOLLARS)

F-8

RELIANT RESOURCES, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME
(LOSS) -- (CONTINUED)
(THOUSANDS OF DOLLARS)

See Notes to our Consolidated Financial Statements

F-9

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

"Reliant Resources" refers to Reliant Resources, Inc. and "we," "us" and
"our" refer to Reliant Resources, Inc. and its consolidated subsidiaries, unless
we specify or the context indicates otherwise.

Our business operations consist of two principal business segments:

- Retail energy -- provides electricity and related services to retail
customers primarily in Texas and acquires and manages the electric
energy, capacity and ancillary services associated with supplying these
retail customers; and

- Wholesale energy -- provides electric energy, capacity and ancillary
services in the competitive segments of the United States' wholesale
energy markets.

Our remaining operations include unallocated corporate functions and minor
equity and other investments.

Reliant Resources, Inc., a Delaware corporation, was incorporated in August
2000 with 1,000 shares of common stock which were owned by Reliant Energy,
Incorporated (Reliant Energy). 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 provided for retail electric competition 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 successor to
Reliant Energy. 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 regulated energy
services and 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 (Distribution). The Distribution completed the
separation of Reliant Resources and CenterPoint into two separate publicly held
companies.

BASIS OF PRESENTATION

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 CenterPoint and directly charged to us based
on usage or other allocation factors prior to the Distribution. The results of
operations in these consolidated financial statements also include general
corporate expenses allocated by CenterPoint to us prior to the Distribution. All
of the allocations in the consolidated 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.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) RECLASSIFICATIONS.

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

F-10

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(B) USE OF ESTIMATES AND MARKET RISK AND UNCERTAINTIES.

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. Our critical accounting estimates include: (a) goodwill, (b)
California net receivables, (c) property, plant and equipment, (d) depreciation
expense, (e) trading and derivative activities, (f) retail energy segment
estimated revenues and energy supply costs, (g) contingencies and (h) deferred
tax assets valuation allowance and tax liabilities.

We are subject to the risk associated with price movements of energy
commodities and the credit risk associated with our commercial activities. For
additional information regarding these risks, see notes 2(d) and 7. We are
subject to risks relating to the reliability of the systems, procedures and
other infrastructure necessary to operate our business. We are also subject to
risks relating to changes in laws and regulations; the outcome of pending
lawsuits, governmental proceedings and investigations; the effects of
competition; liquidity concerns in our markets; changes in interest rates; the
availability of adequate supplies of fuel and transportation; weather
conditions; financial market conditions and our access to capital; the
creditworthiness or financial distress of our counterparties; actions by rating
agencies with respect to us or our competitors; political, legal, regulatory and
economic conditions and developments; the successful operation of deregulating
power markets and other items.

(C) PRINCIPLES OF CONSOLIDATION.

Our accounts and those of our wholly-owned and majority-owned subsidiaries
are included in the consolidated financial statements. All significant
intercompany transactions and balances are eliminated in consolidation.

We do not, or did not until the indicated date, consolidate the following
interests:

- a receivables facility arrangement, which involves a qualified special
purpose entity (QSPE) formed as a bankruptcy remote subsidiary in 2002,
that we entered into with financial institutions that purchase undivided
interests in our accounts receivable from certain retail customers (see
note 16);

- sale-leaseback transactions involving three power generating facilities
entered into in 2000 (see note 14(a));

- two equity investments (see below and note 8); and

- until January 1, 2003, arrangement to facilitate the development,
financing, construction and leasing of three power generation projects
beginning in 2001 (see below and notes 9(a) and 14(b)).

We use the equity method of accounting for investments in entities in which
we have an ownership interest between 20% and 50% and exercise significant
influence primarily through representation on management committees. For our
equity method accounting investments, our representation on management
committees does not enable us to control the investments' management and
operating decisions. The allocation of profits and losses is based on our
ownership interest. For additional information regarding investments recorded
using the equity method of accounting, see note 8. Other investments, excluding
marketable securities, are carried at cost. For these other investments, we do
not exercise significant influence. For additional information regarding these
investments, see note 2(o).

In January 2003, the Financial Accounting Standards Board (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

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, receives a majority of the
entity's expected residual returns, or both. 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 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 9(a).

In December 2003, the FASB released FASB Interpretation No. 46 (revised
December 2003) "Consolidation of Variable Interest Entities, an Interpretation
of ARB No. 51" (FIN No. 46R), which replaces FIN No. 46 and modified certain
criteria in determining which entities should be considered as variable interest
entities. We do not believe the application of FIN No. 46R will have a material
impact to our consolidated financial statements. The application of FIN No. 46R
continues to evolve as the FASB continues to address issues submitted for
consideration. We will continue to assess our application of clarified or
revised guidance related to FIN No. 46R.

(D) REVENUES AND ACCOUNTING FOR HEDGING AND TRADING ACTIVITIES.

Power Generation Revenues. We record gross revenues for energy sales and
services related to our electric power generation facilities under the accrual
method and these revenues generally are recognized upon delivery. Electric power
and other energy services are sold at market-based prices through existing power
exchanges or through third-party contracts. Energy sales and services related to
our electric power generation facilities not billed by month-end are accrued
based upon estimated energy and services delivered. See below for the discussion
of the impact of implementation of Emerging Issues Task Force (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).

Retail Energy Revenues. We record gross revenues for energy sales and
services to residential, small commercial and large commercial, industrial and
institutional retail electric customers that have not executed a contract under
the accrual method and these revenues generally are recognized upon delivery.
Our electricity sales to large commercial, industrial and institutional
customers under contracts executed after October 25, 2002 are typically
accounted for under the accrual method and these gross revenues are generally
recognized upon delivery.

Our electricity sales to large commercial, industrial and institutional
customers under contracts executed before October 25, 2002 were accounted for
under the mark-to-market method of accounting upon contract execution. See
further discussion below of the impact of implementation of EITF Issue No.
02-03, "Issues Related to Accounting for Contracts Involved in Energy Trading
and Risk Management Activities," (EITF No. 02-03) rescinding EITF Issue No.
98-10, "Accounting for Contracts Involved in Energy Trading and Risk Management
Activities," (EITF No. 98-10).

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The determination of retail energy sales is based on the reading of
customer meters by the transmission and distribution utilities. The transmission
and distribution utilities in Texas send the information to the Electric
Reliability Council of Texas (ERCOT) Independent System Operator (ERCOT ISO),
which in turn sends the information to us. We may be limited in our ability to
confirm the accuracy of such information. This activity occurs on a systematic
basis throughout the month. 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. Unbilled revenue is
estimated each month based on estimated volumes for each customer class and
derived from weather factors and analyses of historical trends and experience.
As of December 31, 2002 and 2003, our retail energy segment had accrued unbilled
revenues of $216 million and $290 million, respectively. As additional
information becomes available, we revise our estimated revenues related to prior
periods and record the results in subsequent periods. We believe that the
estimates and assumptions utilized to recognize revenues are reasonable and
represent our best estimates. However, actual results can differ from those
estimates.

Hedging Activities. Effective January 1, 2001, we adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended (SFAS No. 133), which
establishes accounting and reporting standards for derivative instruments.
Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in
net income of $3 million and a cumulative after-tax increase in accumulated
other comprehensive loss of $439 million. During 2001, $230 million of the
initial after-tax transition adjustment recorded in accumulated other
comprehensive loss was recognized in net income.

If certain conditions are met, we may designate a derivative instrument as
hedging (a) the exposure to variability in expected future cash flows (cash flow
hedge), (b) the exposure to changes in the fair value of an asset or liability
(fair value 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.
Derivative commodity contracts for the physical delivery of purchase and sale
quantities transacted in the normal course of business are designated as normal
purchases and sales exceptions and are not reflected in our consolidated balance
sheets at fair value. 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.

We designate our derivatives utilized in non-trading activities as cash
flow hedges only if there is a high correlation between price movements in the
derivative and the item designated as being hedged. This correlation is measured
both at the inception of the hedge and on an ongoing basis, with an acceptable
level of correlation of at least 80% to 125% for hedge designation. The gains
and losses related to derivative instruments designated as cash flow hedges are
deferred in accumulated other comprehensive income (loss), net of tax, to the
extent the contracts are effective as hedges, and then are recognized in our
results of operations in the same period as the settlement of the underlying
hedged transactions. Once the anticipated transaction occurs, the accumulated
deferred gain or loss recognized in accumulated other comprehensive income
(loss) is reclassified and included in our consolidated statements of operations
(a) prior to October 1, 2003, under the captions (i) fuel expenses, in the case
of hedging activities related to physical natural gas purchases, (ii) purchased
power, in the case of hedging activities related to physical power purchases,
(iii) revenues, in the case of hedging activities related to physical power and
natural gas sales transactions and financial transactions and (iv) interest
expense, in the case of interest rate hedging activities and (b) effective
October 1, 2003, under the captions (i) fuel expenses, in case of hedging
activities related to physical natural gas purchases and physical natural gas
sales transactions that do not physically flow, (ii) purchased power, in the
case of hedging activities related to physical power purchases that do
physically flow, (iii) revenues, in the case of hedging activities related to
financial transactions, physical power sales transactions, physical power
purchases that do not physically flow and natural gas

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

sales transactions that do physically flow and (iv) interest expense, in the
case of interest rate hedging activities.

For a derivative not designated as a hedge, changes in fair value are
recorded as unrealized gains or losses in our results of operations. The impact
of our derivative instruments hedging foreign currency exposures are reported in
discontinued operations in our consolidated financial statements. If and when
correlation ceases to exist at an acceptable level, hedge accounting ceases and
changes in fair value are recognized currently in our results of operations. If
it becomes probable that a forecasted transaction will not occur, we immediately
recognize the respective deferred gains or losses in our results of operations.
The associated hedging instrument is then marked to market through our results
of operations for the remainder of the contract term unless a new hedging
relationship is redesignated. Prior to October 1, 2003, revenues, fuel and cost
of gas sold, and purchased power related to sale and purchase contracts
designated as hedges were generally recorded on a gross basis in the delivery
period. In July 2003, the EITF issued EITF No. 03-11, which stated 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. Reclassification of prior year amounts is not required. On
October 1, 2003, we began reporting prospectively the settlement of sales and
purchases of fuel and purchased power related to our non-trading commodity
derivative activities that were not physically delivered on a net basis in our
consolidated statement of operations based on the item hedged. This change
resulted in decreased revenues and a corresponding decrease in fuel and cost of
gas sold and purchased power of $834 million for the fourth quarter of 2003. We
believe the application of EITF No. 03-11 will continue to result in a
significant amount of our non-trading commodity derivative activities being
reported on a net basis prospectively that were previously reported on a gross
basis. EITF No. 03-11 has no impact on margins or net income. Comparative
financial statements for prior periods have not been reclassified to conform to
this presentation, as it is not required. In addition, it is not practicable for
us to determine sales and purchases of fuel and purchased power in 2001, 2002
and the nine months ended September 30, 2003 that would have been shown net if
EITF No. 03-11 had been applied to our results of operations historically.

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. 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.

For additional discussion of derivative and hedging activities, see note 7.

Trading Activities. In March 2003, we discontinued our proprietary trading
business. Trading positions taken prior to our decision to exit this business
are managed solely for purposes of closing them on economical terms. See note
7(b) for discussion of the types of activities that were classified as trading
activities in our historical results of operations.

In 2002, the EITF 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. Beginning in the quarter ended
September 30, 2002, we report all energy trading activities on a net basis in
the consolidated statements of operations. Comparative financial statements for
prior periods were reclassified to conform to this presentation.

Furthermore, in 2002, the EITF 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

F-14

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 our trading activities. This transition was effective for us
(a) on January 1, 2003 for contracts executed prior to October 25, 2002 and (b)
on October 25, 2002 for contracts executed on or after that date. 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 share, effective January 1, 2003, related to
EITF No. 02-03. The cumulative effect reflects the fair value, as of January 1,
2003, of contracts executed prior to October 25, 2002 that had been marked to
market under EITF No. 98-10 that did not meet the definition of a derivative
under SFAS No. 133.

Our historical legacy energy trading activities and certain power
origination activities are accounted for under the mark-to-market method of
accounting. Under the mark-to-market method of accounting, net changes in the
fair value of derivative instruments are recognized in our consolidated
statements of operations as revenues in the period of change. The recognized,
unrealized balances are recorded at fair value in trading and derivative
assets/liabilities in the consolidated balance sheets. Trading revenues related
to the sale of natural gas, electric power and other energy related commodities
are recorded on a net basis, as discussed above.

Prior to 2003, our electricity sales to large commercial, industrial and
institutional customers under executed contracts (and the related energy supply
contracts) for contracts executed prior to October 25, 2002 were accounted for
under the mark-to-market method of accounting pursuant to EITF No. 98-10.
Accordingly, these contractual commitments were recorded at fair value in
revenues on a net basis upon contract execution. As of December 31, 2002, the
recognized, unrealized balances were recorded at fair value in trading and
derivative assets/liabilities in the consolidated balance sheet. 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 and the related energy supply agreements and began
utilizing accrual accounting. The related revenues and energy supply costs are
recorded on a gross basis in our results of operations. The results of
operations related to our electricity sales to large commercial, industrial and
institutional customers for contracts executed prior to October 25, 2002 are not
comparable between 2001, 2002 and 2003 because of this change. During 2001 and
2002, we recognized $73 million and $(6) million, respectively, of unrealized
net gains (losses) related to our electricity sales to large commercial,
industrial and institutional customers and the related energy supply contracts.
During 2003, volumes were delivered under electricity sales to large commercial,
industrial and institutional customers under executed contracts and the related
energy supply contracts for which $66 million was previously recognized as
unrealized earnings. As of December 31, 2003, we have unrealized gains that have
been previously recorded in our results of operations of $27 million that will
be realized upon delivery of the electricity ($21 million in 2004 and $6 million
in 2005). These unrealized gains are recorded in trading and derivative
assets/liabilities in our consolidated balance sheet as of December 31, 2003 and
the related contracts are accounted for as cash flow hedges or normal purchases
and sales contracts under SFAS No. 133.

During 2001 and 2002, we recorded $119 million and $57 million,
respectively, of fair value at the contract inception related to trading
activities, including our electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts. Inception gains
recorded were evidenced by quoted market prices and other current market
transactions for energy trading contracts with similar terms and counterparties.

For additional discussion regarding trading revenue recognition and the
related estimates and assumptions that can affect reported amounts of such
revenues, see note 7.

Classification of Economic Hedges. Effective January 1, 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;
F-15

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

however, such transactions were entered into to economically hedge commodity
risk associated with our wholesale energy power generation operations. As of
January 1, 2003, the amounts of non-trading derivative assets and liabilities
previously classified as trading assets and liabilities were $52 million and $44
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.

Set-off of Trading and Derivative Assets and Liabilities. Where trading
and derivative instruments are subject to a master netting agreement and the
criteria of FASB Interpretation No. 39, "Offsetting of Amounts Related to
Certain Contracts," are met, we present our trading and derivative assets and
liabilities on a net basis in our consolidated balance sheets. Trading and
derivative assets/liabilities and accounts receivable/payable are presented
separately in our consolidated balance sheets. The trading and derivative
assets/liabilities and accounts receivable/payable are set-off separately in our
consolidated balance sheets although in certain cases contracts permit the
set-off of trading and derivative assets/liabilities and accounts
receivable/payable with a given counterparty.

(E) GENERAL, ADMINISTRATIVE AND DEVELOPMENT EXPENSES.

The general and administrative expenses in the consolidated statements of
operations include (a) employee-related costs of the trading and risk management
services activities, (b) certain contractor costs, (c) advertising, (d) bad debt
expense, (e) marketing and market research, (f) corporate and administrative
services (including management services, financial and accounting, cash
management and treasury support, legal, information technology system support,
office management and human resources) and (g) certain benefit costs. Some of
these expenses were allocated from CenterPoint prior to the Distribution as
further discussed in notes 1 and 3.

(F) PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION EXPENSE.

We record property, plant and equipment at historical cost. We recognize
repair and maintenance costs incurred in connection with planned major
maintenance, such as turbine and generator overhauls, under the
"accrue-in-advance" method for our power generation operations acquired or
developed prior to December 31, 1999. Planned major maintenance cycles primarily
range from two to 12 years. Under the accrue-in-advance method, we estimate the
costs of planned major maintenance and accrue the related expense over the
maintenance cycle. As of December 31, 2002 and 2003, our major maintenance
reserve was $7 million and $10 million, respectively, of which $1 million and
$0, respectively, were included in other current liabilities. We expense all
other repair and maintenance costs as incurred. For power generation operations
acquired or developed subsequent to January 1, 2000, we expense all repair and
maintenance costs as incurred, including planned major maintenance. Depreciation
is computed using

F-16

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the straight-line method based on estimated useful lives. Property, plant and
equipment includes the following:

We periodically evaluate property, plant and equipment for impairment when
events or changes in circumstances indicate that the carrying value of these
assets may not be recoverable. The determination of whether an impairment has
occurred is based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. A resulting impairment
loss is highly dependent on the underlying assumptions. During 2001, we
determined equipment associated with our communications business was impaired
and accordingly recognized $22 million of equipment impairments (see note 17).
During 2002, we determined that steam and combustion turbines and two heat
recovery steam generators purchased in September 2002 were impaired and
accordingly recognized a $37 million impairment loss (see note 14(c)). During
2002, we also recognized $15 million in depreciation expense for the early
retirement of power generation units at the Warren facility. During 2003, we
recorded the following in depreciation expense: $14 million for the early
retirement of certain power generation units and $7 million related to the
write-down of an office building to its fair value less costs to sell. As of
December 31, 2002 and 2003, we performed impairment analyses of certain of our
wholesale energy segment's property, plant and equipment. In addition, in
November 2002 and July 2003, we performed impairment analyses of all of our
wholesale energy segment's property, plant and equipment as we believed events
had indicated that these assets may not be recoverable. Based on these analyses,
we recorded no impairments.

Over the past few years, margins on the sales of electricity in our
industry have decreased substantially. If our wholesale energy market outlook
changes negatively, we could have impairments of property, plant and equipment
in future periods. In addition, our ongoing evaluation of our wholesale energy
business could result in decisions to mothball, retire or dispose of additional
generation assets, any of which could result in additional impairment charges.

See note 15(c) for discussion of our Liberty Electric PA, LLC (Liberty)
generating station.

(G) GOODWILL AND AMORTIZATION EXPENSE.

We record goodwill for the excess of the purchase price over the fair value
assigned to the net assets of an acquisition. Through 2001, we amortized
goodwill on a straight-line basis over 15 to 40 years. Pursuant to our adoption
of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142) on
January 1, 2002, we discontinued amortizing goodwill. See note 6 for a
discussion regarding our adoption of SFAS No. 142. Goodwill amortization expense
was $25 million for 2001, including a $19 million impairment related to the
communications business (see note 17). Amortization expense for other

F-17

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

intangibles, excluding contractual rights and obligations, was $44 million, $51
million and $59 million for 2001, 2002 and 2003, respectively. See also note 6.

We periodically evaluate goodwill and other intangibles when events or
changes in circumstances indicate that the carrying value of these assets may
not be recoverable. In 2001, the determination of whether an impairment had
occurred was based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. During 2001, we
determined goodwill associated with our communications business was impaired and
accordingly recognized $19 million of goodwill impairments. Effective January 1,
2002, goodwill and other intangibles are evaluated for impairment in accordance
with SFAS No. 142 (see note 6). In 2002, we recognized an impairment charge of
$234 million (pre-tax and after-tax) relating to our European energy segment
goodwill in connection with the adoption of SFAS No. 142. Due to the disposition
of our Desert Basin plant operations, we tested our wholesale energy segment's
goodwill for impairment effective July 2003. In connection with this analysis,
we recognized an impairment of $985 million (pre-tax and after-tax) relating to
our wholesale energy reporting unit. For further discussion of goodwill and
other intangible asset impairment analyses in 2002 and 2003, see note 6.

(H) STOCK-BASED COMPENSATION PLANS.

We apply the intrinsic value 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 to employees have all been
granted with the exercise price equal to 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, "Accounting for Stock-Based
Compensation" (SFAS No. 123) and SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment to SFAS No. 123" (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. The FASB has announced that it plans to require all companies to expense
the fair value of employee stock options in 2005. The FASB is still evaluating
"fair value" valuation models and other items.

If compensation costs had 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 2001, 2002 and 2003, which take into account the
amortization of stock-based compensation, including performance shares,

F-18

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

For further information regarding our stock-based compensation plans, see
note 12(a).

(I) CAPITALIZATION OF INTEREST EXPENSE.

Interest expense is capitalized as a component of major projects under
construction and is amortized over the estimated useful lives of the assets.
During 2001, 2002 and 2003, we capitalized interest of $59 million, $27 million
and $84 million, respectively.

(J) INCOME TAXES.

We use the asset and liability method of accounting for deferred income
taxes and measure deferred income taxes for all significant income tax temporary
differences. For additional information regarding income taxes, see note 13.

Prior to October 1, 2002, we were included in the consolidated federal
income tax returns of CenterPoint and we calculated our income tax provision on
a separate return basis under a tax sharing agreement with CenterPoint. Pursuant
to agreements with CenterPoint, we were owed amounts related to certain loss
carryovers, income inclusions from foreign affiliates, net income tax
receivables/payables relating to our operations prior to the Distribution and
other tax liabilities. Prior to October 1, 2002, current federal and some state
income taxes were payable to or receivable from CenterPoint. Subsequent to the
Distribution, we file a separate federal tax return. See note 13 for further
discussion.

(K) CASH.

We record as cash and cash equivalents all highly liquid short-term
investments with original maturities or remaining maturities at date of purchase
of three months or less.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(L) RESTRICTED CASH.

Restricted cash primarily includes cash at certain subsidiaries, the
distribution or transfer of which to Reliant Resources or our other
subsidiaries, is restricted by financing and other agreements, but is available
to the applicable subsidiary to use to satisfy certain of its obligations. For a
discussion of our various financing agreements, see note 9. The following table
details our current and long-term restricted cash by reporting segment and
entity:

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

(1) This restricted cash is pledged to secure the payment and performance
related to the issuance of certain surety bonds.

(2) The credit facilities and other debt agreements of Orion Power Holdings,
Inc. and certain of its subsidiaries contain various covenants that include,
among others, restrictions on the payment of dividends to Orion Power
Holdings, Inc. and/or us unless certain conditions are satisfied.

(3) See notes 9(a) and 14(a).

(4) The credit agreement of our subsidiary that owns an electric power
generation facility in Channelview, Texas, contains restrictive covenants
that restrict Reliant Energy Channelview, L.P.'s (Channelview) ability to,
among other things, make dividend distributions unless Channelview satisfies
various conditions.

(M) ALLOWANCE FOR DOUBTFUL ACCOUNTS.

Accounts and notes receivable, principally from customers, in the
consolidated balance sheets are net of an allowance for doubtful accounts of $68
million and $74 million at December 31, 2002 and 2003, respectively. The net
provision for doubtful accounts in the consolidated statements of operations for
2001, 2002 and 2003 was $38 million, $21 million and $79 million, respectively.
These amounts include items written off during the years related to refunds for
energy sales in California (see note 15(b)) and related to Enron Corp. and its
affiliates (Enron) (see note 15(a)). We accrue a provision for doubtful accounts
based upon estimated percentages of uncollectible power generation and retail
energy revenues. We determine these percentages from counterparty credit
ratings, historical collections, accounts receivable aging analyses and other
factors. We review the provision and estimated percentages periodically and
adjust them as appropriate. We write-off accounts receivable balances against
the allowance for doubtful accounts when we deem the receivable to be
uncollectible.

(N) INVENTORY.

Inventory consists of materials and supplies, including spare parts, coal,
natural gas and heating oil. Inventories used in the production of electricity
are valued at the lower of average cost or market. Heating

F-20

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

oil and natural gas used in the trading activities were accounted for under
mark-to-market accounting through 2002, as discussed in note 2(d). Beginning
January 1, 2003, this inventory is no longer marked to market in accordance with
EITF No. 02-03 and is now valued at the lower of average cost or market. Below
is a detail of inventory:

(O) INVESTMENTS.

As of December 31, 2002 and 2003, we have other non-marketable investments
of $39 million and $32 million, respectively, in which we have ownership
interests of less than 20% and do not exercise significant influence, which are
carried at cost and are included in other long-term assets in our consolidated
balance sheets. During 2002, we incurred a pre-tax impairment loss of $32
million ($30 million after-tax) related to certain of these investments in
connection with reduced cash flow expectations for these investments,
management's decision to minimize further financial support and management's
intent to sell certain investments in the near-term below our cost basis.

(P) ENVIRONMENTAL COSTS.

We expense or capitalize environmental expenditures, as appropriate,
depending on their future economic benefit. We expense amounts that relate to an
existing condition caused by past operations and that do not have future
economic benefit. We record liabilities related to expected future costs related
to environmental assessments and/or remediation activities when they are
probable and the costs can be reasonably estimated. See note 15(a) for further
discussion.

(Q) ASSET RETIREMENT OBLIGATIONS.

On January 1, 2003, we adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). 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. 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 present values on the dates of acquisition.
Our asset retirement obligations primarily related to the required future
dismantling of power plants and auxiliary equipment at our European energy
operations, which have subsequently been sold and future dismantlement of power
plants on leased property and environmental obligations related to ash disposal
site closures.

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 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
and have subsequently been sold. The impact of the adoption of SFAS No. 143 for
our continuing operations resulted in a
F-21

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2001, the impact would have
been immaterial to our consolidated income from continuing operations and net
income (loss) for both 2001 and 2002.

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

Balance at January 1, 2003.................................. $11
Accretion expense........................................... 1
Payments.................................................... (4)
---
Balance at December 31, 2003................................ $ 8
===

(R) DEFERRED FINANCING COSTS.

Deferred financing costs are costs incurred in connection with obtaining
financings. These costs are deferred and amortized, using the effective interest
method, over the life of the related debt. From October 1, 2002 through December
31, 2003, we had incurred approximately $243 million in financing costs (which
includes the net present value of $15 million to be paid in March 2007) related
to our 2003 refinancing 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 in the first
quarter of 2003, respectively) in fees and other costs related to these
financings. During 2001, 2002 and 2003, we amortized $1 million, $3 million and
$105 million of deferred financing costs to interest expense. Included in our
results for 2003 was the write-off of $55 million of previously deferred
financing costs related to the March 2003 refinancing in connection with the
prepayment of senior secured term loans and the cancellation of our senior
priority facility in 2003. As of December 31, 2002 and 2003, we had $68 million
and $192 million, respectively, of net deferred financing costs classified in
other long-term assets in our consolidated balance sheets. See note 9 for
discussion of our various financing agreements.

(S) FOREIGN CURRENCY ADJUSTMENTS.

Local currencies are the functional currency of our foreign operations.
Foreign subsidiaries' assets and liabilities have been translated into U.S.
dollars using the exchange rate at the balance sheet date. Revenues, expenses,
gains and losses have been translated using the weighted average exchange rate
for each month prevailing during the periods reported. Cumulative adjustments
resulting from translation have been recorded as a component of accumulated
other comprehensive loss in stockholders' equity.

(T) GUARANTEES AND INDEMNIFICATIONS.

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

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

had no impact to our historical 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 year ended December 31, 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 14(e).

(U) DISCLOSURES ABOUT PENSIONS AND OTHER POSTRETIREMENT BENEFITS.

In December 2003, the FASB issued a revision to SFAS No. 132, "Employers'
Disclosures About Pensions and Other Postretirement Benefits -- An Amendment of
FASB Statements No. 87, 88 and 106" (SFAS No. 132 (Revised 2003)). This
statement revises employers' disclosures about pension plans and other
postretirement benefit plans. This statement retains the disclosure requirements
contained in SFAS No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits" (SFAS No. 132), which it replaces. It requires
additional disclosures to those in the original SFAS No. 132 about the assets,
obligations, cash flows and net periodic benefit cost of defined benefit pension
plans and other defined benefit postretirement plans. We have adopted these
additional disclosures. See note 12(b).

(V) NEW ACCOUNTING PRONOUNCEMENTS.

As of February 20, 2004, no standard setting body or authoritative body has
established new accounting pronouncements or changes to existing accounting
pronouncements that would have a material impact to our results of operations,
financial position or cash flows, for which we have not already adopted and/or
disclosed elsewhere in these notes.

(3) HISTORICAL RELATED PARTY TRANSACTIONS

Prior to the Distribution, CenterPoint was a related party. Transactions
with CenterPoint subsequent to the Distribution are not reported as affiliated
transactions. We had, or continue to have (as indicated) the following
agreements/transactions with CenterPoint:

Indemnities and Releases. We have agreements with CenterPoint providing
for mutual indemnities and releases with respect to our respective businesses
and operations, corporate governance matters, the responsibility for employee
compensation and benefits, and the allocation of tax liabilities. The agreements
also require us to indemnify CenterPoint for any untrue statement of a material
fact, or omission of a material fact necessary to make any statement not
misleading, in the registration statement or prospectus that we filed with the
Securities and Exchange Commission (SEC) in connection with our IPO. We have
also guaranteed, in the event CenterPoint becomes insolvent, certain
non-qualified benefits of CenterPoint's and its subsidiaries' existing retirees
at the date of Distribution totaling approximately $57 million as of December
31, 2003.

Corporate Support Services. CenterPoint agreed to provide us various
corporate support services, information technology services and other previously
shared services such as corporate security, facilities management, accounts
receivable, accounts payable and payroll, office support services and purchasing
and logistics services. Certain of these arrangements will continue until
December 31, 2004; however, we have the right to terminate categories of
services at an earlier date. The charges we pay to CenterPoint for these
services allow CenterPoint to recover its fully allocated costs, plus
out-of-pocket costs and expenses. 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 2001 and the nine
months ended September 30, 2002,
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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

were $9 million and $15 million, respectively, and are included primarily in
operation and maintenance expenses and general and administrative expenses. Net
interest income related to various net receivables representing transactions
between us and CenterPoint was $12 million and $5 million during 2001 and the
nine months ended September 30, 2002, respectively.

Leases. We leased office space in CenterPoint's corporate headquarters and
continue to lease office space in various CenterPoint facilities in Houston,
Texas, including a data center. Our lease at CenterPoint's corporate
headquarters expired in January 2004, except with respect to an insignificant
amount of space used primarily for information technology operations. We also
have various agreements with CenterPoint relating to ongoing commercial
arrangements, including the leasing of optical fiber and related maintenance
activities, gas purchasing and agency matters and subcontracting energy services
under existing contracts. During 2001 and the nine months ended September 30,
2002, we incurred $16 million and $24 million, respectively, of rent expense to
CenterPoint.

Purchases and Sales of Energy Commodities, Transportation and Related
Services. In 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 CenterPoint. Purchases of electric generation energy and
capacity and electric transmission services from CenterPoint were $1.5 billion
for the nine months ended September 30, 2002. During 2001 and the nine months
ended September 30, 2002, the net purchases and sales and services from/to
CenterPoint and its subsidiaries related to our trading operations totaled $469
million and $161 million, respectively. In addition, during 2001 and the nine
months ended September 30, 2002, other sales and services to CenterPoint and its
subsidiaries totaled $56 million and $15 million, respectively.

Equity Contributions. During 2001, 2002 and 2003, CenterPoint made equity
contributions to us of $1.8 billion, $53 million and $45 million, respectively.
The contributions in 2001 primarily related to the conversion into equity of
debt owed to CenterPoint and some related interest expense totaling $1.7 billion
and the contribution of net benefit assets and liabilities, net of deferred
income taxes. The contributions in 2002 primarily related to benefit
obligations, net of deferred income taxes. The contributions in 2003 primarily
related to the non-cash conversion to equity of accounts payable to CenterPoint.

Services Provided to CenterPoint. Through 2001, we provided billing,
customer service, credit and collection and remittance services to certain of
CenterPoint's regulated utilities. The charges CenterPoint paid us for these
services allowed us to recover our fully allocated costs of providing the
services, plus out-of-pocket costs and expenses.

(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."

In January 2003, CenterPoint distributed approximately 19% of the common
stock of Texas Genco to CenterPoint shareholders. CenterPoint granted us an
option to purchase all of the remaining shares of common stock of Texas Genco
held by CenterPoint. The option expired unexercised on January 24, 2004.

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 currently able to
participate in these legally mandated capacity auctions. Under CenterPoint's
prior agreement with us, Texas Genco was required to auction the remainder of
its capacity
F-24

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

after certain other adjustments, and we had the right to participate directly in
such auctions. Texas Genco's obligation to auction its remaining capacity and
our associated rights terminated when we decided not to exercise our option to
acquire CenterPoint's ownership interest in Texas Genco.

We have 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
receivables and related assets are junior to our receivables facility and senior
to our March 2003 credit facilities and to our senior secured notes. See note
16. The term of the master power purchase contract terminates on January 24,
2005.

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. As of December 31, 2003, we had
purchased entitlements to capacity of Texas Genco averaging 6,376 megawatts (MW)
per month in 2004 and 923 MW per month in 2005. Our anticipated capacity
payments related to these capacity entitlements are $714 million. The capacity
entitlements are accounted for as normal purchases under SFAS No. 133. See notes
2(d) and 7 for discussion of our derivative financial instruments.

Under a support agreement with CenterPoint, 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 occur of
(a) CenterPoint's sale of Texas Genco, or all or substantially all of the
generating assets of Texas Genco or (b) May 31, 2005; however, Texas Genco may
extend the term of this agreement until December 31, 2005. In addition, Texas
Genco has the right to terminate all or a portion of the services provided under
the agreement upon 90 days' notice. In February 2004, Texas Genco notified us
that it will terminate the technical support services and the environmental,
safety and industrial health services provided under the support agreement. The
effective date of termination is May 2004.

(5) BUSINESS ACQUISITION

In February 2002, we acquired all of the outstanding shares of common stock
of Orion Power Holdings, Inc. (Orion Power Holdings) 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 primarily funded the acquisition with a $2.9
billion credit facility. Orion Power is an electric power generating company
with generating assets in the states of New York, Pennsylvania, Ohio and West
Virginia.

As of February 19, 2002, Orion Power had 81 generating facilities with a
total generating capacity of 5,644 MW and two development projects with an
additional 804 MW of capacity under construction. Both projects under
construction had reached commercial operation by December 31, 2002.

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

F-25

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

final valuations of property, plant and equipment, intangible assets and other
assets and obligations. There were no additional material modifications to the
preliminary adjustments from December 31, 2002.

The net purchase price of Orion Power was allocated and the fair value
adjustments to the seller's book value were as follows:

Adjustments to property, plant and equipment and other intangibles,
excluding contractual rights, are based primarily on valuation reports prepared
by independent appraisers and consultants.

The following factors contributed to the recognized goodwill of $1.3
billion: commercialization value attributable to our trading capabilities,
commercialization and synergy value associated with fuel procurement in
conjunction with existing generating plants in the region, entry into the New
York power market, general and administrative cost synergies with existing PJM
Interconnection, LLC (PJM) power market generating assets, and risk
diversification value due to increased scale, fuel supply mix and the nature of
the acquired assets. Of the resulting goodwill, only $105 million is deductible
for United States income tax purposes. The $1.3 billion of goodwill was assigned
to the wholesale energy segment. See note 6 for discussion of our subsequent
goodwill impairment in 2003 related to our wholesale energy reporting unit.

The components of other intangible assets and the related weighted average
amortization period for the Orion Power acquisition consist of the following:

F-26

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

There was no allocation of purchase price to any intangible assets that are
not subject to amortization. See note 6 for further discussion of goodwill and
intangible assets.

Our results of operations include the results of Orion Power for the period
beginning February 19, 2002. The following table presents selected financial
information and unaudited pro forma information for 2001 and 2002, as if the
acquisition had occurred on January 1, 2001 and 2002, as applicable:

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, 2001 and 2002, as
applicable. 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.

F-27

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(6) 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. A reconciliation of 2001
reported net income and per share amounts adjusted for the exclusion of goodwill
amortization with a comparison to 2002 and 2003 follows:

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

(1) This impairment of $19 million, net of tax, is included in the annual
goodwill amortization amount, net of tax, of $25 million for continuing
operations.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Intangibles. Other intangible assets consist of the following:

We recognize specifically identifiable intangibles, including air emissions
regulatory allowances, contractual rights, power generation site permits, water
rights and FERC licenses, when specific rights and contracts are acquired. We
have no intangible assets with indefinite lives recorded as of December 31, 2002
and 2003. We amortize air emissions regulatory allowances primarily on a
units-of-production basis as utilized. We amortize other acquired intangibles,
excluding contractual rights, on a straight-line basis over the lesser of their
contractual or estimated useful lives. All intangibles, excluding goodwill, are
subject to amortization.

Estimated amortization expense, excluding contractual rights and
obligations (see below), for the next five years is as follows (in millions):

In connection with the acquisition of Orion Power, we recorded the fair
value of certain fuel and power contracts acquired. We estimated the fair value
of the contracts using forward pricing curves as of the acquisition date over
the life of each contract. Those contracts with positive fair values at the date
of acquisition (contractual rights) were recorded to intangible assets and those
contracts with negative fair values at the date of acquisition (contractual
obligations) were recorded to other long-term liabilities in the consolidated
balance sheet.

Contractual rights and contractual obligations are amortized to fuel
expense and revenues, as applicable, based on the estimated realization of the
fair value established on the acquisition date over the contractual lives. There
may be times during the life of the contract when accumulated amortization
exceeds the carrying value of the recorded assets or liabilities due to the
timing of realizing the fair value established on the acquisition date.

We amortized $26 million and $29 million of contractual rights and
contractual obligations, respectively, for a net amount of $3 million, during
2002. We amortized $28 million and $33 million of contractual rights and
contractual obligations, respectively, for a net amount of $5 million, during
2003.

F-29

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Estimated amortization of contractual rights and contractual obligations,
excluding Liberty's terminated tolling agreement (see notes 9(a) and 15(c)), for
the next five years is as follows:

Goodwill. The following tables show the composition of goodwill by
reportable segment as of December 31, 2002 and 2003 and changes in the carrying
amount of goodwill for 2002 and 2003 by reportable segment:

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

(1) See below for discussion.

(2) On July 9, 2003, we entered into a definitive agreement to sell our
588-megawatt Desert Basin plant (see note 23). The sale closed in October
2003. This anticipated sale of our Desert Basin plant operations 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. We did not allocate any goodwill to our Desert Basin
plant operations, which are classified as discontinued operations, prior to
July 2003.

(3) Effective January 1, 2003, as we began reporting our ERCOT generation
facilities in our retail energy segment rather than our wholesale energy
segment, we transferred $25 million of goodwill to our retail energy
segment. Effective December 31, 2003, we began reporting these facilities in
our wholesale energy segment and transferred $4 million of goodwill back to
our wholesale energy segment for a net transfer to our retail energy segment
of $21 million. See note 21.

As of December 31, 2002 and 2003, we had $144 million and $131 million,
respectively, of net goodwill recorded in our consolidated balance sheets that
is deductible for United States income tax purposes for future periods.

SFAS No. 142 requires goodwill to be tested at least annually and more
frequently in certain circumstances. The date of our annual impairment test was
November 1 for 2002 and 2003. 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.

F-30

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 in the first quarter of 2002. Based on the first step of this goodwill
impairment test, no goodwill was impaired for our other reporting units.

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

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, we considered the sales
price in the agreement that we signed in February 2003 to sell our European
energy operations (see note 22). 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 22.
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 in October 2003. See note 23
for further discussion of this sale. This sale of our Desert Basin plant
required us 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. We were
also required to test the recoverability of goodwill in our remaining wholesale
energy reporting unit as of July 2003.

As a result of the July 2003 test, we recognized an impairment of $985
million (pre-tax and after-tax) in the third quarter of 2003. This impairment
was due to a decrease in the estimated fair value of our wholesale energy
reporting unit. This change in fair value was 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; expectations 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 projected
commercial, operational and support groups costs and lower projected operations
and maintenance expense.

2003 Annual Goodwill Impairment Tests. We performed our annual goodwill
impairment tests for our wholesale energy and retail energy reporting units
effective November 1, 2003 and determined that no additional impairments of
goodwill had occurred since July 2003.

Estimation of our Wholesale Energy Segment Fair Value. We estimate the
fair value of our wholesale energy segment based on a number of subjective
factors, including: (a) appropriate weighting of

F-31

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

valuation approaches (income approach, market approach and comparable public
company approach), (b) projections about future power generation margins, (c)
estimates of our future cost structure, (d) discount rates for our estimated
cash flows, (e) selection of peer group companies for the public company
approach, (f) required level of working capital, (g) assumed terminal value and
(h) time horizon of cash flow forecasts.

The income approach used in our analyses is a discounted cash flow analysis
based on our internal forecasts and contains numerous assumptions made by
management and the independent appraiser, any of which if changed could
significantly affect the outcome of the analyses. We believe the income approach
is the most subjective of the approaches.

Management has determined the fair value of our wholesale energy reporting
unit with the assistance of an independent appraiser. In determining the fair
value of our wholesale energy segment in 2003, we made the following key
assumptions: (a) the markets in which we operate will continue to be
deregulated; (b) demand for electricity will grow, which will result in lower
reserve margins; (c) there will be a recovery in electricity margins over time
to a level sufficient such that companies building new generation facilities can
earn a reasonable rate of return on their investment and (d) the economics of
future construction of new generation facilities will likely be driven by
regulated utilities. As part of our process, we modeled all of our power
generation facilities and those of others in the regions in which we operate.
The following table summarizes certain of these significant assumptions:

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

(1) The number of years used in the internal cash flow analysis changed from 5
years in the January 2002 test to 15 years due to the fact that five years
in the forecast did not capture the full impact of the cyclical nature of
our wholesale energy operations. Additional periods were included in the
forecasts to derive an appropriate forecast period, which was used to
determine the estimated terminal value. As of January 2002, based on current
market conditions in the wholesale energy industry, management did not
believe additional periods beyond five years in the forecast were required.

(2) The EBITDA multiple for terminal values changed from 6.0 in the January 2002
test to 7.0 to 7.5 in the November 2002 test and from 7.0 to 7.5 in the
November 2002 test to 7.5 in the 2003 tests due to the independent
appraiser's updated analysis of the public guideline companies that
indicated higher multiples were appropriate to calculate the terminal values
at the applicable dates.

(3) Depending on the region, the specific rate is projected to be somewhat
higher or lower.

(4) Based on our assumption in 2003 that regulated utilities will be the primary
drivers underlying the construction of new generation facilities, we have
assumed that the after-tax return on investment will yield a return
representative of a regulated utility's cost of capital (7.5%) rather than
that of an independent power producer (9.0%). Based on changes in assumed
market conditions, including regulatory rules, we have changed the projected
time horizon for substantially achieving the after-tax return on investment
to 2008 -- 2012 (depending on region). Formerly, we had assumed that the
time horizon for substantially achieving this rate of return was
2006 -- 2010.

Potential Future Impairments of Goodwill. Because we recognized a goodwill
impairment in 2003, in the near future, if our wholesale energy market outlook
changes negatively, we could have additional impairments of goodwill that would
need to be recognized. In addition, our ongoing evaluation of our wholesale
energy business could result in decisions to mothball, retire or dispose of
additional generation assets, any of which could result in additional impairment
charges related to goodwill, impact our fixed assets' depreciable lives or
result in fixed asset impairment charges.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(7) DERIVATIVE INSTRUMENTS, INCLUDING ENERGY TRADING ACTIVITIES

We are exposed to various market risks. These risks arise from the
ownership of our assets and operation of our business. We routinely utilize
derivative instruments such as futures, physical forward contracts, swaps and
options to mitigate the impact of changes in electricity, natural gas and fuel
prices on our operating results and cash flows. We utilize interest rate swaps
and options to mitigate the impact of changes in interest rates and other
financial instruments to manage various other market risks.

We have a risk control framework designed to monitor, measure and define
appropriate transactions to hedge and manage the risk in our existing portfolio
of assets and contracts and to authorize new transactions. These risks fall into
three different categories: market risk, credit risk and operational risk. We
believe that we have effective procedures for evaluating and managing these
risks to which we are exposed. Key risk control activities include definition of
appropriate transactions for hedging, credit review and approval, credit and
performance risk measurement and monitoring, validation of transactions,
portfolio valuation and daily portfolio reporting including mark-to-market
valuation, value-at-risk and other risk measurement metrics. We seek to monitor
and control our risk exposures through a variety of separate but complementary
processes and committees, which involve business unit management, senior
management and our board of directors.

The primary types of derivatives we use are described below:

- Futures contracts are exchange-traded standardized commitments to
purchase or sell an energy commodity or financial instrument, or to make
a cash settlement, at a specific price and future date.

- Physical forward contracts are commitments to purchase or sell energy
commodities in the future.

- Swap agreements require payments to or from counterparties based upon the
differential between a fixed price and variable index price (fixed price
swap) or two variable index prices (variable price swap) for a
predetermined contractual notional amount. The respective index may be an
exchange quotation or an industry pricing publication.

- Option contracts convey the right to buy or sell an energy commodity or a
financial instrument at a predetermined price or settlement of the
differential between a fixed price and a variable index price or two
variable index prices.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Trading and derivative assets and liabilities at December 31, 2002 and 2003
include amounts for non-trading and trading activities, as follows:

(A) NON-TRADING DERIVATIVE ACTIVITIES.

To reduce the risk from market fluctuations in our results of operations
and the resulting cash flows, we may enter into energy derivatives in order to
hedge some expected purchases of electric power, natural gas and other
commodities and sales of electric power (non-trading energy derivatives). The
non-trading energy derivative portfolios are managed to complement our asset
portfolio, reducing overall risks.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The fair values of our non-trading derivative activities as of December 31,
2002 and 2003, are determined by (a) prices actively quoted, (b) prices provided
by other external sources or (c) prices based on models and other valuation
methods.

Below is the pre-tax income (loss) of our non-trading derivative
instruments, including non-trading energy derivatives and interest rate
derivatives, both from cash flow hedge ineffectiveness and from non-trading
derivative mark-to-market income and losses, for 2001, 2002 and 2003:

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

(1) For 2001, 2002 and 2003, no component of the derivative instruments' gain or
loss was excluded from the assessment of effectiveness.

(2) Includes $0, $16 million and $0 for 2001, 2002 and 2003, respectively, of
losses recognized in our results of operations as a result of the
discontinuance of cash flow hedges because it was probable that the
forecasted transaction would not occur.

Below is a reconciliation of our net derivative assets (liabilities) to
accumulated other comprehensive loss, net of tax, as of December 31, 2002 and
2003:

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

(1) Represents deferred derivative losses of our total accumulated other
comprehensive loss.

(2) As of December 31, 2003, we expect $21 million of accumulated other
comprehensive loss to be reclassified into our results of operations during
2004.

As of December 31, 2002 and 2003, the maximum length of time we are hedging
our exposure to the variability in future cash flows for forecasted
transactions, excluding the payment of variable interest on existing financial
instruments, is ten years and nine years, respectively. As of December 31, 2002
and 2003,

F-35

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the maximum length of time we are hedging our exposure to the payment of
variable interest rates is seven and six years, respectively.

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

Other Non-trading Derivative Activities. During 2001, we entered into two
structured transactions, involving a series of forward contracts to buy and sell
an energy commodity in 2001 and to buy and sell an energy commodity in 2002. The
change in fair value of these derivative assets and liabilities was recorded in
the statement of consolidated operations for each reporting period. During 2001
and 2002, $117 million of net non-trading derivative liabilities and $121
million of net non-trading derivative assets, respectively, were settled related
to these transactions, which was recorded in cash flows from operations; $1
million and $3 million, respectively, of pre-tax unrealized gains were
recognized.

(B) ENERGY TRADING ACTIVITIES.

As discussed in note 2(d), in March 2003, we discontinued our proprietary
business. Trading positions taken prior to our decision to exit this business
are managed solely for purposes of closing them on economical terms.

Historically, our trading activities included (a) transactions establishing
open positions in the energy markets, primarily on a short-term basis and (b)
energy price risk management services to customers primarily related to natural
gas, electric power and other energy-related commodities. Our electricity sales
to large commercial, industrial and institutional customers under contracts
executed before October 25, 2002 were accounted for under the mark-to-market
method of accounting upon contract execution (see note 2(d)).

The fair values of our trading activities as of December 31, 2002 and 2003,
are determined by (a) prices actively quoted, (b) prices provided by other
external sources or (c) prices based on models and other valuation methods.

During 2001, 2002 and 2003, we recognized a loss of $23 million, income of
$31 million and income of $11 million, respectively, for changes in the fair
values of trading assets/liabilities due to changes in valuation techniques and
assumptions.

As of December 31, 2003, the weighted average term of the trading
portfolio, based on fair values, is approximately 16 months. The maximum term of
any contract in the trading portfolio is 13 years. These maximum and average
terms are not indicative of likely future cash flows, as these positions may be
changed by new transactions in the trading portfolio at any time in response to
changing risk management portfolio strategies. Terms regarding cash settlements
of these contracts vary with respect to the actual timing of cash receipts and
payments.

(C) CREDIT RISK.

Credit risk is inherent in our commercial activities and relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. We have broad credit policies and parameters. 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. 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. Credit risk exposure is monitored daily
and the financial condition of our counterparties is reviewed periodically.

If any of our counterparties failed to perform, we might be forced to
acquire alternative hedging arrangements or be required to replace the
underlying commitment at then-current market prices. In this
F-36

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

event, we might incur additional losses in addition to amounts owed to us by the
counterparty. For information regarding the provision related to energy sales in
California, see note 15(b). For information regarding the net provision recorded
in 2001 related to energy sales to Enron, see note 15(a).

As of December 31, 2002 and 2003, one non-investment grade counterparty
represented 14% and 18% of our total credit exposure, net of collateral. The
dollar amounts of our credit exposure to this one counterparty were $86 million
and $113 million as of December 31, 2002 and 2003, respectively. There were no
other counterparties representing greater than 10% of our total credit exposure,
net of collateral.

(8) EQUITY INVESTMENTS

We own a 50% interest in a 470 MW electric generation plant in Boulder
City, Nevada. We also own a 50% 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:

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

During 2001, 2002 and 2003, the net distributions were $27 million, $3
million and $4 million, respectively, from these investments.

As of December 31, 2002 and 2003, the companies in which we have an equity
investment carry debt, of $145 million and $134 million, respectively ($73
million and $67 million, respectively, based on our proportionate ownership
interests of the investments). This debt is non-recourse to Reliant Resources
and all of its consolidated subsidiaries.

F-37

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(9) CREDIT FACILITIES, BONDS, NOTES AND OTHER DEBT

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

F-38

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) The weighted average stated interest rates are for borrowings outstanding as
of December 31, 2002 or 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) The entire balance outstanding under this credit agreement has been
classified as current as of December 31, 2002 and 2003. Included in the
outstanding amount as of December 31, 2003, is $2 million and $2 million of
scheduled principal payments, which were due in October 2003 and January
2004, respectively, for which no payment has been made. As interest payments
due in October 2003 and January 2004 were deferred, additional interest will
be charged on the past due interest amounts. Of the amount shown as current
under the Liberty credit agreement, $11 million matures within 12 months of
December 31, 2003. See below and note 15(c) 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 $74 million and $66 million related to
the Orion Power Holdings senior notes as of December 31, 2002 and 2003,
respectively. Included in the adjustment to fair value of interest rate
swaps is $42 million and $23 million related to the Orion Power MidWest,
L.P. (Orion MidWest) and Orion Power New York, L.P. (Orion NY) credit
facilities, respectively, as of December 31, 2002. Included in the
adjustment to fair value of interest rate swaps is $28 million and $19
million related to the Orion MidWest and Orion NY credit facilities,
respectively, as of December 31, 2003. Included in interest expense is
amortization of $5 million and $8 million for valuation adjustments for debt
and $25 million and $18 million for valuation adjustments for interest rate
swaps, respectively, for 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, 2003 is approximately $2.8 billion. Such restrictions are on the
net assets of Orion Power Capital, LLC (Orion Capital), Liberty and Channelview.
Orion MidWest and Orion NY are subsidiaries of Orion Capital.

Maturities. As of December 31, 2003, maturities of all facilities and
other debt were as follows (in millions):

2004........................................................ $ 161(1)
2005........................................................ 1,126(1)
2006........................................................ 38(1)
2007........................................................ 1,994(1)
2008........................................................ 28(1)
2009 and thereafter......................................... 2,688(1)
------
Subtotal.................................................. 6,035
Other items included in debt................................ 105
------
Total debt................................................ $6,140
======

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

(1) Included in the amounts for years 2004, 2005, 2006, 2007, 2008 and 2009 and
thereafter are $11 million, $9 million, $10 million, $10 million, $11
million and $211 million, respectively, related to our Liberty credit
agreement and which have all been classified as current liabilities in our
consolidated balance sheet as of December 31, 2003. See below and note 15(c)
for further discussion.

Debt Covenant Compliance. We were in compliance with all of our debt
covenants as of December 31, 2003, other than under the Liberty credit
agreement. See below for further discussion.

F-39

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

The following table provides a summary of the amounts owed and amounts
available as of December 31, 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) With consent of the lenders, we have chosen to defer the principal and
interest payments due October 2003 rather than draw on the $17 million
letter of credit posted as debt service reserve. See below and note 15(c)
for further discussion.

(3) As discussed below and in note 15(c), this amount is currently not available
to Liberty.

As of December 31, 2003, committed credit facilities and notes aggregating
$717 million were unsecured.

Senior Secured Term Loans and Senior Secured 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 (see note 14(b)). 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 loans under the refinanced credit
facilities bear interest at the London inter-bank offered rate (LIBOR) plus 4.0%
or a base rate plus 3.0%.

F-40

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In connection with our March 2003 refinancing, we entered into a $300
million senior priority facility. Borrowings under this facility were limited to
secure or prepay ongoing commercial and hedging obligations.

The senior secured facilities originally totaling $5.93 billion are secured
with a lien on all of our contractually and legally available assets. With the
exception of subsidiaries prohibited by the terms of their financing documents
from doing so, our subsidiaries guarantee the refinanced credit facilities.

In connection with our March 2003 refinancing, we issued 20,373,326
warrants, of which 12,537,432 warrants have subsequently been canceled, to
acquire shares of our common stock. The remaining 7,835,894 warrants, which have
an exercise price of $5.09 per share, vested in March 2003 and are exercisable
until August 2008. See (b) below for further discussion.

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. Such
restrictions include our ability to (a) encumber our assets, (b) enter into
business combinations or divest our assets, (c) incur additional debt or engage
in sale and leaseback transactions, (d) pay dividends or prepay certain other
debt, (e) make investments or acquisitions or engage in development activities,
(f) enter into transactions with affiliates, (g) make capital expenditures, (h)
materially change our business, (i) amend our debt and other material
agreements, (j) repurchase our capital stock, (k) allow limitations on
distributions from our subsidiaries and (l) engage in certain types of trading
activities. We must use the proceeds of any loans under the senior secured
revolving credit facility solely for working capital and other general corporate
purposes and we are not permitted to use the proceeds from loans under any of
these facilities to acquire Texas Genco or ERCOT assets. Financial covenants
include maintaining a debt to earnings before interest, taxes, depreciation,
amortization and rent (EBITDAR) ratio of a certain minimum amount and an EBITDAR
to interest ratio of a certain minimum amount. We must be in compliance with
each of the covenants before we can borrow or issue letters of credit under the
revolving credit facility. The covenants are not anticipated to materially
restrict our ability to borrow funds or obtain letters of credit. Our failure to
comply with these covenants could result in an event of default that, if not
cured or waived, could result in the revolving credit commitment being canceled
and/or our being required to repay these borrowings before their scheduled due
dates. We must also prepay the refinanced facilities with net proceeds from
certain asset sales and issuances of certain debt and equity securities and,
beginning in 2005, with certain cash flows in excess of a threshold amount.

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 revised 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, revised 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 proceeds from the sale
of our Desert Basin plant and our European energy operations) and separated the
Orion Power Holdings limited guarantee from the credit agreement so it can
ratably guarantee the bank debt and the senior secured notes.

We finalized a second amendment to our March 2003 credit facilities in
December 2003. In connection with this amendment, we used $917 million that had
accumulated in an escrow account, including the net proceeds from (a) primarily
the sales of our Desert Basin plant and our European energy operations and the
related interest income ($651 million) and (b) our convertible senior
subordinated
F-41

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

notes ($266 million), to prepay debt under the credit facilities. The December
2003 amendment continues to allow us, by specified dates, to purchase the stock
of Texas Genco through a negotiated purchase with CenterPoint and adds the
flexibility, with certain limitations, to purchase up to $1.0 billion of
individual generating assets from Texas Genco or others to support our Texas
retail business, and to raise specified forms of debt to finance such asset
acquisitions. In connection with this amendment, we also canceled our $300
million senior priority facility, which was never used. If we later determine
that this facility is needed, the December 2003 amendment gives us the
flexibility to obtain a new senior priority facility, for the same purposes and
with the same priority or equal priority with the lenders under our March 2003
credit facilities and our senior secured notes, in an amount up to $300 million.

After the December 2003 amendment, our March 2003 credit facilities permit
us to place net cash proceeds from offerings of junior securities in a
restricted escrow account for the possible acquisition of the stock of Texas
Genco or of individual generating assets from Texas Genco or others to support
our Texas retail business. If such cash proceeds are not used for such
acquisitions, we may keep up to 50% of the cash proceeds for general corporate
purposes and are required to use the remainder to prepay indebtedness under our
March 2003 credit facilities.

Senior Secured Notes. On July 1, 2003, we issued $550 million 9.25% senior
secured notes and $550 million 9.5% senior secured notes 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 March
2003 credit facilities. Interest is payable semi-annually on January 15 and July
15. With certain limited exceptions, the senior secured notes are secured by the
same collateral which secures our March 2003 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 March
2003 credit facilities, except for certain subsidiaries of Orion Power Holdings
and certain other subsidiaries. See note 19 for further discussion of the
guarantors, the limited guarantor and the non-guarantors. 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
and received net proceeds, after deducting the initial purchasers' discount and
estimated out-of-pocket expenses, of $266 million. In connection with the
December 2003 amendment to our March 2003 credit facilities, as discussed above,
we used these net proceeds to prepay debt under our March 2003 credit
facilities. The notes bear interest at 5.00% per annum, payable semi-annually on
February 15 and August 15. 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.

Orion Power Holdings Senior Notes. Orion Power Holdings has outstanding
$400 million aggregate principal amount of 12% senior notes. In connection with
the Orion Power acquisition, we recorded the senior notes at an estimated fair
value of $479 million. The $79 million premium is being amortized to interest
expense using the effective interest rate method over the life of the senior
notes. The fair value of the senior notes was based on our incremental borrowing
rates for similar types of borrowing arrangements

F-42

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

as of the acquisition date. The senior notes are senior unsecured obligations of
Orion Power Holdings. Orion Power Holdings is not required to make any mandatory
redemption or sinking fund payments with respect to the senior notes. The senior
notes are not guaranteed by any of Orion Power Holdings' subsidiaries and are
non-recourse to Reliant Resources. The senior notes indenture contains
covenants, which bind Orion Power Holdings and certain of its subsidiaries, that
include, among others, restrictions on (a) the payment of dividends, (b) the
incurrence of indebtedness and the issuance of preferred stock, (c) investments,
(d) asset sales, (e) liens, (f) transactions with affiliates, (g) engaging in
unrelated businesses and (h) sale and leaseback transactions.

Orion MidWest and Orion NY Credit Agreements. During October 2002, the
Orion Power Holdings revolving credit facility was prepaid and terminated, and
we refinanced the Orion MidWest and Orion NY credit agreements. In connection
with these refinancings, we applied excess cash of $145 million to prepay and
terminate the Orion Power Holdings revolving credit facility and to reduce the
term loans and revolving working capital facilities at Orion MidWest and Orion
NY. As of the refinancing date, the amended and restated Orion MidWest credit
agreement included a term loan of approximately $974 million and a $75 million
revolving working capital facility. As of the refinancing date, the amended and
restated Orion NY credit agreement included a term loan of approximately $353
million and a $30 million revolving working capital facility. As of December 31,
2002 and 2003, Orion MidWest had $969 million and $884 million, respectively, of
term loans outstanding. As of December 31, 2002 and 2003, Orion NY had $351
million and $334 million, respectively, of term loans outstanding. The
refinancing included an extension of the maturities of the Orion MidWest and
Orion NY credit agreements by three years to October 2005.

The loans under each facility bear interest at LIBOR plus a margin or at a
base rate plus a margin. The LIBOR margin is 2.75% as of December 31, 2003 and
increases to 3.25% in April 2004 and 3.75% in October 2004. The base rate margin
is 1.75% as of December 31, 2003 and increases to 2.25% in April 2004 and 2.75%
in October 2004.

The amended and restated Orion MidWest credit agreement is secured by a
first lien on substantially all of the assets of Orion MidWest and its
subsidiary. Orion NY and its subsidiaries are guarantors of the Orion MidWest
obligations under the amended and restated Orion MidWest credit agreement. A
substantial portion of the assets of Orion NY and its subsidiaries (excluding
certain plants) are pledged, via a second lien, as collateral for this
guarantee. The amended and restated Orion NY credit agreement is, in turn,
secured by a first lien on a substantial portion of the assets of Orion NY and
its subsidiaries (excluding certain plants). Orion MidWest and its subsidiary
are guarantors of the Orion NY obligations under the amended and restated Orion
NY credit agreement. Substantially all of the assets of Orion MidWest and its
subsidiary are pledged, via a second lien, as collateral for this guarantee.
Orion MidWest's and Orion NY's obligations under the respective agreements are
non-recourse to Orion Power Holdings and Reliant Resources.

Both the Orion MidWest and Orion NY credit agreements contain affirmative
and negative covenants, including negative pledges, that must be met by each
borrower under its respective agreement to borrow funds or obtain letters of
credit, and which require Orion MidWest and Orion NY to maintain a combined debt
service coverage ratio of 1.5 to 1.0. These covenants are not anticipated to
materially restrict either borrower's ability to borrow funds or obtain letters
of credit. The agreements also provide for any available cash at one borrower to
be made available to the other borrower to meet shortfalls in the other
borrower's ability to make certain payments, including operating costs. This is
effected through distributions of such available cash to Orion Capital, a direct
subsidiary of Orion Power Holdings formed in connection with the refinancing.
Orion Capital, as indirect owner of each of Orion MidWest and Orion NY, can then
contribute such cash to the other borrower. The ability of the borrowers to make
dividends, loans or advances to Orion Power Holdings for interest payments or
otherwise is restricted. In any event, no

F-43

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

distributions may be made after October 28, 2004 until the earlier of maturity
or retirement. No distributions are anticipated during the remaining terms of
the credit agreements. Any restricted cash which is not dividended, will be
applied on a quarterly basis to prepay outstanding loans at Orion MidWest and
Orion NY. See note 2(l) for a detail of restricted cash under the Orion MidWest
and Orion NY credit agreements.

Liberty Credit Agreement. In July 2000, Liberty Electric Power, LLC (LEP)
and Liberty, indirect wholly-owned subsidiaries of Orion Power Holdings, 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 Holdings 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
Holdings as credit support was canceled.

The floating rate loans under the Liberty credit agreement bear interest at
LIBOR plus a margin or a base rate plus a margin. For the floating rate term
loan, as of December 31, 2003, the LIBOR margin is 1.25% and increases to 1.375%
in May 2005 and 1.625% in May 2008. As of December 31, 2003, the base rate
margin is 0.25% and increases to 0.375% in May 2005 and 0.625% in May 2008. For
the revolving working capital facility, as of December 31, 2003, the LIBOR
margin is 1.25% and increases to 1.375% in May 2005. As of December 31, 2003,
the base rate margin is 0.25% and increases to 0.375% in May 2005.

The lenders under the Liberty credit agreement have a security interest in
substantially all of the assets of Liberty and LEP. The outstanding borrowings
related to the Liberty credit agreement are non-recourse to Reliant Resources
and all other subsidiaries. The Liberty credit agreement contains affirmative
and negative covenants, including a negative pledge, that must be met to borrow
funds or obtain letters of credit. Liberty is currently unable to access the
revolving working capital facility. Additionally, the Liberty credit agreement
restricts Liberty's ability to, among other things, make dividend distributions
unless Liberty satisfies various conditions. See note 2(l) for a detail of
restricted cash under the Liberty credit agreement.

Given that Liberty is currently in default under the credit agreement, we
have classified the debt as a current liability. Neither Reliant Resources nor
any other of its subsidiaries is in default under other debt agreements due to
the credit agreement default at Liberty. See note 15(c).

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 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(c)). Three series of tax-exempt 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 revenue bonds relating to the Seward project were
issued by PEDFA, for a total of $400 million outstanding as of December 31,
2003. Of the net proceeds from the September 2003 issuance, $95 million was used
to pay down borrowings under our senior secured revolver. The bonds bear
interest, which is payable monthly, at a floating rate determined each week. The
bonds are non-recourse to Reliant Resources; however, letters of credit totaling
$407 million 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.

F-44

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REMA Term Loans. Reliant Energy Mid-Atlantic Power Holdings, LLC and its
subsidiaries' (REMA) is obligated to provide credit support for its lease
obligations (see note 14(a)) in the form of letters of credit and/or cash
resulting from draws on such 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 and $16 million in letters of credit issued in January 2004.
The draw on the letters of credit 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 and did not constitute a default under any of REMA's obligations.
Interest on the term loans is payable at the rate of LIBOR plus 3%. REMA's
subsidiaries guarantee REMA's obligations under the leases and the term loans.
The term loans are non-recourse to Reliant Resources.

Reliant Energy Channelview L.P. In 1999, Channelview, a project subsidiary
of Reliant Energy Power Generation, Inc. (REPG), entered into a $475 million
syndicated credit facility to finance the construction and start-up operations
of an electric power generation plant located in Channelview, Texas. The maximum
availability under this facility was (a) $92 million in equity bridge loans for
the purpose of paying or reimbursing project costs, (b) $369 million in loans to
finance the construction of the project and (c) $14 million in revolving loans
for general working capital purposes. In November 2002, the construction loans
were converted to term loans. On the conversion date, subsidiaries of REPG
contributed cash equity and subordinated debt of $92 million into Channelview,
which was used to repay in full the equity bridge loans advanced by the lenders.
The term loans have scheduled maturities from 2004 to 2024. The revolving
working capital facility matures in 2007.

As of December 31, 2003, with the exception of the fixed-rate tranche, the
term loans and revolving working capital facility loans bear a floating interest
rate at the borrower's option based on either LIBOR or base rate, plus a margin,
and the margins increase over time.

Obligations under the term loans and revolving working capital facility are
secured by substantially all of the assets of the borrower. The outstanding
borrowings related to the Channelview credit agreement are non-recourse to
Reliant Resources. The Channelview credit agreement contains affirmative and
negative covenants, including a negative pledge, that must be met to borrow
funds. These covenants are not anticipated to materially restrict Channelview's
ability to borrow funds under the credit facility. The Channelview credit
agreement allows Channelview to pay dividends or make restricted payments only
if specified conditions are satisfied, including maintaining specified debt
service coverage ratios and debt service reserve account balances. Channelview
is not expected to satisfy such conditions in 2004. See note 2(l) for a detail
of restricted cash under the Channelview credit agreement.

(b) WARRANTS.

As discussed above in (a), we have outstanding 7,835,894 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. During
2003, we amortized $7 million to interest expense and the unamortized balance
was $8 million as of December 31, 2003.

F-45

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(c) INTEREST RATE DERIVATIVE INSTRUMENTS.

Below are our interest rate derivative instruments:

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

(1) These interest rate swaps hedge the floating interest rate risk associated
with our floating rate long-term debt. 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. As of December 31, 2002 and 2003,
floating rate LIBOR-based interest payments are exchanged for weighted fixed
rate interest payments of 6.97% and 6.88%, respectively. As of December 31,
2002 and 2003, these swaps have negative termination values (i.e., we would
have to pay). See note 7 for information regarding our derivative financial
instruments.

(2) The LIBOR interest rates are capped at a weighted average rate of 3.18% for
$3.0 billion in 2004 and 4.35% for $1.5 billion in 2005.

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 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 7 for information
regarding our derivative financial instruments.

During January 2003, we purchased three-month LIBOR interest rate caps for
$29 million to hedge our floating rate risk associated with Reliant Resources'
credit facilities. During the first quarter of 2003, these interest rate caps
qualified as cash flow hedges of LIBOR-based anticipated borrowings; changes in
fair market value during this period were recorded to other comprehensive income
(loss) and ineffectiveness was recorded to interest expense. Hedge
ineffectiveness during the first quarter of 2003 resulted in the recording of $2
million in interest expense on these interest rate caps. Effective March 31,
2003, these interest rate caps were no longer designated as cash flow hedges,
accordingly, subsequent changes in the fair market value are being recorded to
net income (loss). The unrealized net loss on these derivative instruments of
$15 million (pre-tax) through December 31, 2003 previously reported in other
comprehensive loss will be reclassified into earnings during the periods in
which the originally designated hedged transactions occur. Subsequent to March
31, 2003, we recorded $9 million in interest expense due to unrealized losses in
fair value of the interest rate caps.

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. In
2002, we liquidated these forward-starting interest rate swaps. The liquidation
of these swaps resulted in a loss of $55 million, which was recorded in
accumulated other comprehensive loss and is being amortized into interest
expense in the same periods during which the forecasted interest payment affects
earnings, which is through 2012. At December 31, 2002 and 2003, the unamortized
balance of such loss was $38 million (pre-tax).

F-46

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(10) STOCKHOLDERS' EQUITY

(A) INITIAL PUBLIC OFFERING AND COMMON STOCK ACTIVITY.

In May 2001, Reliant Resources offered 59.8 million shares of its common
stock to the public at an IPO price of $30 per share and received net proceeds
from the IPO of $1.7 billion. Pursuant to the terms of the master separation
agreement with CenterPoint, we used $147 million of the net proceeds to repay
certain indebtedness owed to CenterPoint. We used the remainder of the net
proceeds of our IPO for repayment of third party borrowings, capital
expenditures, repurchases of our common stock and payment of taxes, interest and
other payables.

The following table describes our common stock activity for the indicated
periods:

(b) TREASURY STOCK PURCHASES.

During 2001, we purchased 11 million shares of our common stock at an
average price of $17.22 per share, or an aggregate purchase price of $189
million. The 11 million shares in treasury stock purchases increased
CenterPoint's percentage ownership in us from approximately 80% to approximately
83%. CenterPoint recorded the acquisition of treasury shares under the purchase
method of accounting and pushed down the effect to us. As such, we recorded a
decrease in net assets from discontinued operations of $43 million and a
decrease in additional paid-in capital of $43 million.

Based on our March 2003 credit facilities and our senior secured notes, our
ability to purchase treasury stock is restricted; see note 9(a).

(c) TREASURY STOCK ISSUANCES AND TRANSFERS.

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

F-47

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(11) EARNINGS PER SHARE

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

For 2001 and 2002, the computation of diluted EPS excludes purchase options
for 8,258,098 and 15,875,183 shares of common stock that have an exercise price
(ranging from $23.20 to $34.03 per share and ranging from $8.50 to $34.03 per
share, respectively) greater than or equal to the average market price ($22.11
per share and $8.15 per share, respectively) for the respective periods and
would thus be anti-dilutive if exercised.

For 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
from assumed conversions for 2003 (shares in thousands):

Stock options............................................... 680(1)
======
Restricted stock and performance-based shares............... 1,174
======
Employee stock purchase plan................................ 151
======
5.00% convertible senior subordinated notes................. 14,870(2)
======
Warrants.................................................... 364
======

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

(1) For 2003, the incremental shares from assumed conversions exclude purchase
options for 17,076,778 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 ($5.16 per share) and would thus be anti-dilutive if
exercised.

(2) If we had recorded income from continuing operations for 2003, for purposes
of calculating diluted EPS, we would have increased our income from
continuing operations by $5 million for 2003 as it relates to the assumed
conversions for our convertible senior subordinated notes.

F-48

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(12) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT AND OTHER BENEFIT
PLANS

(A) STOCK-BASED INCENTIVE COMPENSATION PLANS.

At December 31, 2003, our eligible employees participate in four incentive
plans described below.

The Reliant Resources, Inc. 2002 Long-Term Incentive Plan (2002 LTIP)
permits us to grant awards (stock options, restricted stock, stock appreciation
rights, performance awards and cash awards) to key employees, non-employee
directors and other individuals who we expect to become key employees within the
following six months. Subject to adjustment as provided in the plan, the
aggregate number of shares of our common stock that may be issued may not exceed
17,500,000 shares. We also sponsor the Long-Term Incentive Plan of Reliant
Resources, Inc. (2001 LTIP), which was effective January 31, 2001, and was
amended to provide that no additional awards would be made under the 2001 LTIP
after June 6, 2002. Upon the adoption of the 2002 LTIP, the shares remaining
available for grant under the 2001 LTIP, totaling approximately 3.5 million,
became available as authorized shares available for grant under the 2002 LTIP.
These shares are included in the total of 17,500,000 shares available under the
2002 LTIP. Additionally, any shares forfeited under the 2001 LTIP become
available for grant under the 2002 LTIP.

The Reliant Resources, Inc. 2002 Stock Plan (2002 Stock Plan) permits us to
grant awards (stock options, restricted stock, stock appreciation rights,
performance awards and cash awards) to all of our employees (excluding officers
subject to Section 16 of the Securities Exchange Act of 1934). The board of
directors authorized 6,000,000 shares for grant upon adoption of the 2002 Stock
Plan. To the extent these 6,000,000 shares were not granted in 2002, the excess
shares were canceled. An additional 6,000,000 shares were authorized for the
2003 plan year. The total number of shares is adjusted for new grants,
exercises, forfeitures, cancellations and terminations of outstanding awards
under the plan throughout the year. We do not plan to authorize additional
shares for this plan after the end of the 2003 plan year.

Prior to the IPO, eligible employees participated in a CenterPoint
Long-Term Incentive Compensation Plan and other incentive compensation plans
(collectively, the CenterPoint Plans) that provided for the issuance of
stock-based incentives including performance-based shares, restricted shares,
stock options and stock appreciation rights, to key employees including
officers. The Reliant Resources, Inc. Transition Stock Plan was adopted to
govern the outstanding restricted shares and options of CenterPoint common stock
held by our employees prior to the Distribution date, under the CenterPoint
Plans. There were 9,100,000 shares authorized under the Reliant Resources, Inc.
Transition Stock Plan and it is anticipated that no additional shares will be
issued.

In addition, in conjunction with the Distribution, we entered into an
employee matters agreement with CenterPoint. This agreement covered the
treatment of outstanding CenterPoint equity awards (including performance-based
shares, restricted shares and stock options) under the CenterPoint Plans held by
our employees and CenterPoint employees. According to the agreement, each
CenterPoint equity award granted to our employees and CenterPoint employees
prior to the agreed upon date of May 4, 2001, that was outstanding under the
CenterPoint Plans as of the Distribution date, was adjusted. This adjustment
resulted in each individual, who was a holder of a CenterPoint equity award,
receiving an adjusted equity award of our common stock and CenterPoint common
stock, immediately after the Distribution. The combined intrinsic value of the
adjusted CenterPoint equity awards and our equity awards, immediately after the
record date of the Distribution, was equal to the intrinsic value of the
CenterPoint equity awards immediately before the record date of the
Distribution.

Performance-based Shares and Restricted Shares. Performance-based shares
and restricted shares have been granted to employees without cost to the
participants. The performance-based shares generally vest three years after the
grant date based upon performance objectives over a three-year cycle, except as
discussed below. The restricted shares vest to the participants at various times
ranging from immediate vesting to vesting at the end of a five-year period.
During 2001, 2002 and 2003, we recorded compensation
F-49

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

expense of $8 million, $4 million and $11 million, respectively, related to
performance-based and restricted share grants.

Prior to the Distribution, our employees and CenterPoint employees held
outstanding performance-based shares and restricted shares of CenterPoint's
common stock under the CenterPoint Plans. On the Distribution date, each
performance-based share of CenterPoint common stock outstanding under the
CenterPoint Plans, for the performance cycle ending December 31, 2002, was
converted to restricted shares of CenterPoint's common stock based on a
conversion ratio provided under the employee matters agreement. Immediately
following this conversion, outstanding restricted shares of CenterPoint common
stock were converted to restricted shares of our common stock, which shares were
subject to their original vesting schedule under the CenterPoint Plans. The
conversion ratio was determined using the intrinsic value approach described
above. As such, our employees and CenterPoint's employees held 302,306 and
87,875 restricted shares, respectively, outstanding under CenterPoint Plans
which were converted to 238,457 and 69,334 restricted shares, respectively, of
our common stock, of which a majority vested on December 31, 2002.

The following table summarizes Reliant Resources' performance-based shares
and restricted shares grant activity for 2001, 2002 and 2003:

Stock Options. Under both CenterPoint's and our plans, stock options
generally vest over a three-year period and expire after ten years from the date
of grant. The exercise price is equal to or greater than the market value of the
applicable common stock on the grant date.

As of the record date of the Distribution, CenterPoint converted all
outstanding CenterPoint stock options granted prior to May 4, 2001 (totaling
7,761,960 stock options) to a combination of CenterPoint stock options totaling
7,761,960 stock options at a weighted average exercise price of $17.84 and
Reliant Resources stock options totaling 6,121,105 stock options with a weighted
average exercise price of $8.59. The conversion ratio was determined using an
intrinsic value approach as described above.

F-50

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes Reliant Resources stock option activity for
2001, 2002 and 2003:

The following table summarizes, with respect to Reliant Resources, the
range of exercise prices and the weighted average remaining contractual life of
the options outstanding and the range of exercise prices for the options
exercisable at December 31, 2003:

Of the outstanding and exercisable stock options as of December 31, 2003,
20,135,837 and 13,028,449, respectively, relate to our current or former
employees. The remainder of outstanding and exercisable stock options as of
December 31, 2003, primarily relate to employees of CenterPoint.

Employee Stock Purchase Plan. In the second quarter of 2001, we
established the Reliant Resources, Inc. Employee Stock Purchase Plan (ESPP)
under which we are authorized to sell up to 18,000,000 shares of our common
stock to our employees. Under the ESPP, employees may contribute up to 15% of
their compensation, as defined, towards the purchase of shares of our common
stock at a price of 85% of the lower of the market value at the beginning or end
of each six-month offering period. The

F-51

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

initial purchase period began on the date of the IPO and ended December 31,
2001. The market value of the shares acquired in any year may not exceed $25,000
per individual. Amounts contributed in excess of $21,250 during a purchase
period will be refunded to the employee. The following table details the number
of shares (and price per share) issued under our ESPP for 2002 and 2003 and
through January 2004:

Pro Forma Effect on Net Income (Loss). In accordance with SFAS No. 123, we
apply the intrinsic value method contained in APB No. 25 and disclose the
required pro forma effect on net income (loss) and earnings (loss) per share as
if the fair value method of accounting for stock compensation was used. The
weighted average grant date fair value for an option to purchase our common
stock granted during 2001, 2002 and 2003 was $13.35, $5.09 and $3.10,
respectively. The weighted average grant date fair value of a purchase right
issued under our ESPP during 2001, 2002 and 2003 was $9.24, $4.51 and $1.80,
respectively. The weighted average grant date fair value for an option to
purchase CenterPoint common stock granted during 2001 was $9.25. The fair values
were estimated using the Black-Scholes option valuation model with the following
weighted average assumptions:

For 2001 and 2002, we determined stock option expected volatility based on
an average of the historical volatility of our common stock and a group of
companies we consider similar to us. For 2003, we determined stock option
expected volatility based on the historical volatility of our common stock. The
Black-Scholes option valuation model was developed for use in estimating the
fair value of traded options, which have no vesting restrictions and are fully
transferable. In addition, option valuation models require the input of highly
subjective assumptions including the expected stock price volatility. Because
our

F-52

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

employee stock options and purchase rights have characteristics significantly
different from those of traded options, and because changes in the subjective
input assumptions can materially affect the fair value estimate, in our opinion,
the existing models do not necessarily provide a single measure of the fair
value of our employee stock options and purchase rights.

For the pro forma computation of net income (loss) and earnings (loss) per
share as if the fair value method of accounting had been applied to all stock
awards, see note 2(h).

(b) PENSION.

We sponsor multiple noncontributory defined benefit pension plans covering
certain union and non-union employees. Depending on the plan, the benefit
payment is either based on years of service with final average salary and
covered compensation, or in the form of a cash balance account which grows based
on a percentage of annual compensation and accrued interest.

Prior to March 1, 2001, we participated in CenterPoint's noncontributory
cash balance pension plan. Effective March 1, 2001, we no longer accrued
benefits under this noncontributory pension plan for our domestic non-union
employees (Resources Participants). Effective March 1, 2001, each Resources
Participant's unvested pension account balance became fully vested and a
one-time benefit enhancement was provided to some qualifying participants.
During the first quarter of 2001, we incurred a charge to earnings of $83
million (pre-tax) for a one-time benefit enhancement and a gain of $23 million
(pre-tax) related to the curtailment of CenterPoint's pension plan. In
connection with the Distribution, we incurred a loss of $65 million (pre-tax)
related to the accounting settlement of the pension obligation. In connection
with recording the accounting settlement, CenterPoint contributed certain
benefit plan deferred losses, net of taxes, totaling $18 million that were
deemed to be associated with our benefit obligation. Upon the Distribution, we
effectively transferred to CenterPoint our pension obligation. After the
Distribution, each Resources Participant may elect to have his accrued benefit
(a) left in the CenterPoint pension plan for which CenterPoint is the plan
sponsor, (b) rolled over to our savings plan or an individual retirement account
or (c) paid in a lump-sum or annuity distribution.

F-53

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Our funding policy is to review amounts annually in accordance with
applicable regulations in order to determine contributions necessary to achieve
adequate funding of projected benefit obligations. We use a December 31
measurement date for our plans. Our pension obligation and funded status are as
follows:

Amounts recognized in the consolidated balance sheets are as follows:

F-54

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The accumulated benefit obligation for all defined benefit plans was $50
million and $61 million at December 31, 2002 and 2003, respectively.

Net pension cost includes the following components:

The significant weighted average assumptions used to determine the pension
benefit obligation include the following:

The significant weighted average assumptions used to determine the net
pension cost include the following:

As of December 31, 2003, our expected long-term rate of return on pension
plan assets is developed based on third party models. These models consider
expected inflation, current dividend yields, expected corporate earnings growth
and risk premiums based on the expected volatility of each asset category. The
expected long-term rates of return for each asset category are weighted to
determine our overall expected long-term rate of return on pension plan assets.
In addition, peer data and historical returns are reviewed.

Our pension plan weighted average asset allocations at December 31, 2002
and 2003 and target allocation for 2004 by asset category are as follows:

F-55

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In managing the investments associated with the pension plans, our
objective is to exceed, on a net-of-fee basis, the rate of return of a
performance benchmark composed of the following indices:

As a secondary measure, asset performance is compared to the returns of a
universe of comparable funds, where applicable, over a full market cycle.

During 2001, 2002 and 2003, we made cash contributions of $1 million, $8
million and $12 million, respectively, to our pension plans. We expect cash
contributions to approximate $15 million during 2004.

Information for pension plans with an accumulated benefit obligation in
excess of plan assets is as follows:

Prior to the Distribution, we participated in CenterPoint's non-qualified
pension plan which allowed participants to retain the benefits to which they
would have been entitled under CenterPoint's qualified noncontributory pension
plan except for the federally mandated limits on these benefits or on the level
of salary on which these benefits may be calculated. Effective March 1, 2001, we
no longer provide future non-qualified pension benefits to our employees. In
connection with the Distribution, we assumed CenterPoint's obligation related to
our employees under the non-qualified pension plan. The expense associated with
this non-qualified plan was $2 million, $3 million and $6 million in 2001, 2002
and 2003, respectively. During 2003, we recognized an accounting settlement
charge of $5 million (pre-tax) related to participants in our non-qualified
pension plan rolling over to a non-qualified deferred compensation plan
established in 2002, as further discussed below. We believe it was appropriate
to discontinue the application of pension accounting to these benefits. After
the Distribution, participants in the non-qualified pension plan were given the
opportunity to elect to receive distributions or have their account balance
funded into a rabbi trust. Accordingly, $17 million of the non-qualified pension
plan account balances was transferred to the rabbi trust, as discussed below.
The accrued benefit liability for the non-qualified pension plan was $5 million
and $6 million as of December 31, 2002 and 2003, respectively (excluding the
liability related to participants rolling over to a non-qualified deferred
compensation plan). In addition, the accrued benefit liabilities as of December
31, 2002 and 2003 include the recognition of minimum liability adjustments of $7
million and $2 million, respectively, which is reported as a component of other
comprehensive income (loss), net of income tax effects.

(c) SAVINGS PLAN.

We have employee savings plans that are tax-qualified plans under Section
401(a) of the Internal Revenue Code of 1986, as amended (Code), and include a
cash or deferred arrangement under Section 401(k) of the Code for substantially
all our employees. Prior to February 1, 2002, our non-union employees, except
for REMA non-union employees and our foreign subsidiaries' employees,
participated in

F-56

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CenterPoint's employee savings plan that is a tax qualified plan under Section
401(a) of the Code, and included a cash or deferred arrangement under Section
401(k) of the Code.

Under the plans, participating employees may contribute a portion of their
compensation, pre-tax or after-tax, generally up to a maximum of 16% of
compensation with the exception of the Orion Power savings plan under which
contributions are generally up to a maximum of 18% of compensation. Our savings
plans matching contribution and any payroll period discretionary employer
contribution will be made in cash; any discretionary annual employer
contribution, as applicable, may be made in our common stock, cash or both.

Our savings plans benefit expense was $20 million, $24 million and $29
million in 2001, 2002 and 2003, respectively.

(d) POSTRETIREMENT BENEFITS.

Effective March 1, 2001, we discontinued providing subsidized
postretirement benefits to our domestic non-union employees. We incurred a
pre-tax loss of $40 million in the first quarter of 2001 related to the
curtailment of our postretirement obligation. In connection with the
Distribution, we incurred a pre-tax gain of $18 million related to the
accounting settlement of postretirement benefit obligations. Prior to March 1,
2001, through a CenterPoint subsidized postretirement plan, we provided some
postretirement benefits for substantially all of our retired employees. We
continue to provide subsidized postretirement benefits to certain union
employees and Orion Power employees. We fund our postretirement benefits on a
pay-as-you-go basis. We use a December 31 measurement date for our plans.

F-57

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Accumulated postretirement benefit obligation and funded status are as
follows:

Amounts recognized in the consolidated balance sheets are as follows:

F-58

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net postretirement benefit cost includes the following components:

The significant weighted average assumptions used to determine the
accumulated postretirement benefit obligation include the following:

The significant weighted average assumptions used to determine the net
postretirement benefit cost include the following:

The following table shows our assumed health care cost trend rates used to
measure the expected cost of benefits covered by our postretirement plan:

Assumed health care cost trend rates have a significant effect on the
amounts reported for our health care plans. A one-percentage-point change in
assumed health care cost trend rates would have the following effects as of
December 31, 2003:

During 2002, the retiree medical benefits for certain union employees were
redesigned to allow for a company-provided subsidy for premium coverage
attributable to qualifying employees. This resulted in a $10 million increase in
the accumulated postretirement benefit obligation during 2002.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 became law. This law introduces a prescription drug
benefit, as well as a federal subsidy under certain circumstances to sponsors of
retiree health care benefit plans. In January 2004, the FASB issued FASB Staff
Position No. 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003." This
FASB staff position permits sponsors of postretirement health care plans that
provide a prescription drug benefit to make a one time election to defer
accounting for the effects of this law until the earlier of: (a) the issuance of
authoritative guidance on accounting for the federal subsidy or (b) the
occurrence of a significant event that would call for remeasurement of a plan's
assets and obligations, such as a plan amendment, settlement or curtailment. We
have elected to defer accounting for the effects of this law. The measurements
of our accumulated postretirement benefit obligation and net periodic
postretirement benefit cost do not reflect the effect of this law. When
authoritative guidance on accounting for the federal subsidy is issued, we will
revise our accounting as required.

(e) POSTEMPLOYMENT BENEFITS.

We record postemployment benefits based on SFAS No. 112, "Employer's
Accounting for Postemployment Benefits," which requires the recognition of a
liability for benefits provided to former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily health care and life insurance benefits for participants in the
long-term disability plan). Net postemployment benefit costs were insignificant
for 2001 and 2002 and $3 million for 2003.

(f) OTHER NON-QUALIFIED PLANS.

Effective January 1, 2002, key and highly compensated employees are
eligible to participate in our non-qualified deferred compensation and savings
restoration plan. The plan allows eligible employees to elect to defer up to 80%
of their annual base salary and/or up to 100% of their eligible annual bonus. In
addition, the plan allows participants to retain the benefits which they would
have been entitled to under our qualified savings plans, except for the
federally mandated limits on these benefits or on the level of salary on which
these benefits may be calculated. We fund these deferred compensation and
savings restoration liabilities by making contributions to a rabbi trust. Plan
participants direct the allocation of their deferrals and restoration benefits
between one or more of our designated investment funds within the rabbi trust.

Through 2001, certain eligible employees participated in CenterPoint's
deferred compensation plans, which permit participants to elect each year to
defer a percentage of that year's salary and up to 100% of that year's annual
bonus. Interest generally accrued on deferrals made in 1989 and subsequent years
at a rate equal to the average Moody's Long-Term Corporate Bond Index plus 2%,
determined annually until termination when the rate is fixed at the greater of
the rate in effect at age 64 or at age 65. Fixed rates of 19% to 24% were
established for deferrals made in 1985 through 1988. We recorded interest
expense related to these deferred compensation obligations of $4 million, $2
million and $1 million in 2001, 2002 and 2003, respectively. Each of our
employees that participated in this plan has elected to have his CenterPoint
non-qualified deferred compensation plan account balance, after the
Distribution: (a) paid in a lump-sum distribution, (b) placed in a new deferred
compensation plan established by us, which generally mirrors the former
CenterPoint deferred compensation plans, or (c) rolled over to our deferred
compensation and savings restoration plan discussed above.

Our discounted deferred compensation obligation related to the deferred
compensation obligation under the plan that mirrors the CenterPoint deferred
compensation plan was $12 million as of December 31, 2002 and 2003. Our deferred
compensation and savings restoration liability related to the deferred
compensation and savings restoration plan established effective January 1, 2002
(discussed above)

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

was $23 million and $28 million and the related investment in the rabbi trust
was $23 million and $28 million as of December 31, 2002 and 2003, respectively.

(g) OTHER EMPLOYEE MATTERS.

As of December 31, 2003, approximately 27% of our employees are subject to
collective bargaining arrangements, of which contracts covering 7% of our
employees will expire prior to December 31, 2004.

(13) INCOME TAXES

The components of income (loss) from continuing operations before income
taxes are as follows:

Our current and deferred components of income tax expense (benefit) were as
follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

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

(1) Not meaningful as we had a pre-tax loss of $822 million and income tax
expense of $80 million. The primary reason is due to the wholesale energy
segment's goodwill impairment of $985 million, for which no tax benefit can
be recognized as the goodwill is non-deductible.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Following were our tax effects of temporary differences between the
carrying amounts of assets and liabilities in the consolidated financial
statements and their respective tax bases:

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Tax Attribute Carryovers. At December 31, 2003, we had approximately $797
million, $41 million and $570 million of state and foreign net operating loss
carryforwards and capital loss carryforwards, respectively. As of December 31,
2003, we did not have any federal net operating loss carryforwards. The state
loss carryforwards, foreign loss carryforwards and capital loss carryforwards
can be carried forward to offset future income or capital gains, as applicable,
through the years 2023, 2010 and 2008, respectively.

Subsequent to the Distribution, we ceased being a member of the CenterPoint
consolidated tax group. This separation could have future income tax
implications for us. Our separation from the CenterPoint consolidated tax group
changed our overall future income tax posture. As a result, we could be limited
in our future ability to effectively use future tax attributes. We agreed with
CenterPoint that we may carry back net operating losses we generate in our tax
years after deconsolidation to tax years when we were part of the CenterPoint
consolidated tax group subject to CenterPoint's consent and any existing
statutory carryback limitations. CenterPoint agreed not to unreasonably withhold
such consent. In accordance with this agreement, in 2003, we carried back net
operating losses related to the fourth quarter of 2002 to CenterPoint's
pre-Distribution tax years and received a $76 million tax refund in January
2004. In addition, in February 2004, we received $9 million from CenterPoint in
settlement of certain tax matters pursuant to such agreement.

The valuation allowance reflects a $46 million net increase in 2002 and a
$215 million net increase in 2003. The net increase in 2002 results primarily
from increased state net operating losses and impairments on capital assets. In
addition, in connection with the Orion Power acquisition, we recorded a
valuation allowance of $30 million in 2002 due to state net operating losses.
The net increase in 2003 results primarily from (a) increased state net
operating losses in jurisdictions where we do not expect to receive a future tax
benefit and (b) a capital loss on the sale of our European energy operations.
These net changes for 2002 and 2003 also resulted from a reassessment of our
future ability to use federal, state and foreign tax net operating loss and
capital loss carryforwards.

(14) COMMITMENTS

(A) LEASE COMMITMENTS.

REMA Sale-leasebacks. In 2000, we entered into separate sale-leaseback
transactions with each of three owner-lessors' respective 16.45%, 16.67% and
100% interests in the Conemaugh, Keystone and Shawville generating facilities,
respectively, acquired in the REMA acquisition during 2000. As lessee, we lease
an interest in each facility from each owner-lessor under a facility lease
agreement. We expect to make lease payments through 2029 under these leases,
with total cash payments of $1.3 billion remaining as of December 31, 2003. The
lease terms expire in 2026 (Shawville facility) and 2034 (Conemaugh and Keystone
facilities). The equity interests in all the subsidiaries of REMA are pledged as
collateral for
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REMA's lease obligations and the subsidiaries have guaranteed the lease
obligations. Additionally, REMA is obligated to provide credit support for its
lease obligations. See note 9(a) for discussion. These lease obligations, which
were entered into in connection with a financing transaction, are non-recourse
to Reliant Resources. During 2001, 2002 and 2003, we made lease payments related
to the REMA sale-leasebacks of $259 million, $138 million and $77 million,
respectively. As of December 31, 2002 and 2003, we have recorded a prepaid lease
obligation related to the REMA sale-leasebacks of $59 million in other current
assets and of $200 million and $218 million, respectively, in other long-term
assets.

The lease documents contain restrictive covenants that restrict REMA's
ability to, among other things, make dividend distributions unless REMA
satisfies various conditions. As of December 31, 2003, all of these conditions
were met.

Tolling Agreements. In the first quarter of 2001, we entered into tolling
arrangements with a third party to purchase the rights to utilize and dispatch
electric generating capacity of approximately 1,100 MW extending through 2012.
Two gas-fired, simple-cycle peaking plants generate this electricity. We did not
pay any amounts under these tolling arrangements during 2001. We paid $45
million and $54 million in tolling payments during 2002 and 2003, respectively.
The tolling arrangements qualify as operating leases.

We have a long-term office space lease for our corporate headquarters. The
lease term, which commenced in 2003, expires in 2018, subject to two five-year
renewal options.

Cash Obligations Under Operating Leases. The following table sets forth
information concerning our cash obligations under non-cancelable long-term
operating leases as of December 31, 2003. Other non-cancelable, long-term
operating leases principally consist of tolling arrangements, as discussed
above, rental agreements for building space, including the office space lease
discussed above, data processing equipment and vehicles, including major work
equipment:

Operating Lease Expense. Total lease expense for all operating leases was
$72 million, $117 million and $159 million during 2001, 2002 and 2003,
respectively.

(b) CONSTRUCTION AGENCY AGREEMENTS WITH OFF-BALANCE SHEET ENTITIES IN 2001 AND
2002.

In 2001, certain of our subsidiaries entered into operative documents with
entities to facilitate the development, construction, financing and leasing of
several power generation projects. We did not consolidate the entities as of
December 31, 2002. Certain of our subsidiaries acted as construction agents for
these entities and were responsible for completing construction of these
projects by December 31, 2004. However, we had generally limited our risk during
construction to an amount not to exceed 89.9% of costs incurred to date, except
in certain events. Upon completion of an individual project and exercise of the
lease option, our subsidiaries would have been required to make lease payments
in an amount sufficient to

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

provide a return to the investors. Reliant Resources had guaranteed its
subsidiaries' obligations under the operative agreements during the construction
periods. As of December 31, 2002, the entities had property, plant and equipment
of $1.3 billion, net other assets of $3 million and secured debt obligations of
$1.3 billion. As of December 31, 2002, the entities had equity from unaffiliated
third parties of $49 million.

Due to the adoption of FIN No. 46 (as explained in note 2(c)), we began to
consolidate these entities effective January 1, 2003. The 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 9(a).

(c) OFF-BALANCE SHEET EQUIPMENT FINANCING STRUCTURE IN 2001 AND 2002.

We, through a subsidiary, entered into an agreement with a bank in 2000
whereby the bank, as owner, entered into contracts for the purchase and
construction of power generation equipment and our subsidiary, or its subagent,
acted as the bank's agent in connection with administering the contracts for
such equipment. The agreement was terminated in September 2002. Our subsidiary,
or its designee, had the option at any time to purchase, or, at equipment
completion, subject to certain conditions, to lease the equipment or to assist
in the remarketing of the equipment under terms specified in the agreement. We
were required to cash collateralize our obligation to administer the contracts.
This cash collateral was approximately equivalent to the total payments by the
bank for the equipment, interest and other fees. As of December 31, 2001, we had
deposits of $230 million in the collateral account.

In January 2002, the bank sold to the parties to the construction agency
agreements discussed above, equipment contracts with a total contractual
obligation of $258 million, under which payments and interest during
construction totaled $142 million. Accordingly, $142 million of collateral
deposits were returned to us. In May 2002, we were assigned and exercised a
purchase option for a contract for equipment totaling $20 million under which
payments and interest during construction totaled $8 million. We used $8 million
of our collateral deposits to complete the purchase. After the purchase, we
canceled the contract and recorded a $10 million loss on the cancellation of the
contract, which included a $2 million termination fee. Immediately prior to the
expiration of the agreement in September 2002, we terminated the agreement and
were assigned and exercised purchase options for contracts for steam and
combustion turbines and two heat recovery steam generators with an aggregate
cost of $121 million under which payments and interest during construction
totaled $94 million. We used $94 million of our collateral deposits to complete
the purchase.

Pursuant to SFAS No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (SFAS No. 144), we evaluated for impairment the steam and
combustion turbines and two heat recovery steam generators purchased in
September 2002. Based on our analysis, we determined this equipment was impaired
and accordingly recognized a $37 million pre-tax impairment loss that is
recorded as depreciation expense in 2002 in our consolidated statement of
operations. The fair value of the equipment and thus the impairments were
determined using a combination of quoted market prices and prices for similar
assets.

(d) PAYMENT TO CENTERPOINT IN 2004.

Consistent with the Texas electric restructuring law, we expect to make a
payment to CenterPoint for our residential customers. This provision of the law
requires a payment be made to CenterPoint unless, as of December 31, 2003, 40%
or more of the electric power consumed in 2000 by each class of customer in the
Houston service territory was provided by other retail electric providers.
Currently, we estimate the payment to be $175 million and expect that the
payment will be made in the fourth quarter of 2004. This amount is computed by
multiplying $150 by the number of residential customers that we served on
January 1, 2004 in the Houston service territory, less the number of residential
customers we served in other areas of Texas on that same date. We recognized
$128 million (pre-tax) in the third and fourth
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

quarters of 2002 and $47 million (pre-tax) in the first quarter of 2003 for a
total accrual of $175 million as of December 31, 2003. We recognized the total
obligation over the period we recognized the related revenues.

We will not be required to make a similar payment for small commercial
customers because in January 2004 the PUCT found that the 40% target for small
commercial customers was reached before the end of 2003.

(e) 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 was approximately $58 million and $57 million as
of December 31, 2002 and 2003, respectively. There are no assets held as
collateral. There is no liability recorded in our consolidated balance sheet as
of December 31, 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.

(f) OTHER COMMITMENTS.

Property, Plant and Equipment Purchase Commitments. As of December 31,
2003, we had two generating facilities under construction. Total estimated cost
of constructing these facilities is $1.2 billion. As of December 31, 2003, we
had incurred $1.1 billion of the total forecasted project costs.

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Fuel Supply, Commodity Transportation, Purchase Power and Electric Capacity
Commitments. We are a party to fuel supply contracts, commodity transportation
contracts, and purchase power and electric capacity contracts, that have various
quantity requirements and durations that are not classified as trading and
derivative assets and liabilities and hence are not included in our consolidated
balance sheet as of December 31, 2003. Minimum purchase commitment obligations
under these agreements are as follows, as of December 31, 2003:

Our aggregate electric capacity commitments, including capacity auction
products, are for 22,612 MW, 12,276 MW and 5,168 MW for 2004, 2005 and 2006,
respectively. Included in the above purchase power and electric capacity
commitments are amounts acquired from Texas Genco. For additional discussion of
this commitment, see note 4.

As of December 31, 2003, the maximum remaining terms under any individual
fuel supply contract, transportation contract and purchased power and electric
and gas capacity contract is 16 years, 20 years and three years, respectively.

Sale Commitments. As of December 31, 2003, we have sale commitments,
including electric energy and capacity sale contracts, which are not classified
as trading and derivative assets and liabilities and hence are not included in
our consolidated balance sheet. At execution, the estimated minimum sale
commitments under these contracts were $1.9 billion, $751 million, $210 million,
$39 million and $2 million in 2004, 2005, 2006, 2007 and 2008, respectively.

In addition, in January 2002, we began providing retail electric services
to approximately 1.7 million residential and small commercial customers
previously served by CenterPoint's electric utility division. In the Houston
area, the Texas electric restructuring law required us, as a former affiliate of
the transmission and distribution utility in Houston, to sell electricity to
residential or small commercial customers only at a specified price, or
"price-to-beat" until the earlier of January 1, 2005, or the date that 40% or
more of the electric power consumed by the applicable customer class is served
by other retail electric providers. In January 2004, the PUCT made such a
determination for small commercial customers and we are now permitted to sell
electricity at unregulated prices both outside and in the Houston area for these
customers. We do not expect to meet the 40% test for our residential customers
in the Houston area. The price-to-beat was the only price that could be offered
by us to residential and small commercial customers in the Houston area
throughout 2003. The Texas electric restructuring law requires us to continue to
make electricity available for our small commercial customers in the Houston
area at the price-to-beat until January 1, 2007. The PUCT's regulations allow
our retail electric provider to adjust its price-to-beat fuel factor based on a
percentage change in the price of natural gas. In addition, the retail electric
provider may also request an adjustment as a result of changes in the price of
purchased energy. We can request up to two adjustments to our price-to-beat in
each year. During 2002 and 2003, we requested and the PUCT approved two such
adjustments in each year.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Provider of Last Resort Contracts. One of our subsidiaries is
contractually obligated through the end of 2004 to provide energy to Duquesne
Light Company to satisfy the demands of any customer in its service area that
purchases power from Duquesne Light Company as its "provider of last resort."
These contracts do not specify a minimum or maximum quantity of energy to be
supplied. Although we expect to produce more energy than needed to meet these
contractual obligations, it is possible that, due to seasonal variations in
demand or operational outages, our subsidiary may occasionally need to purchase
energy from third parties to cover its contractual obligations. Since these
events are likely to occur at times of higher market prices, we are at risk that
the cost of power purchased may exceed the fixed prices for power under
contracts with Duquesne Light Company. Failure to provide sufficient energy
under the terms of the contracts could give rise to, in addition to other direct
damages, penalties of up to $1,000 per megawatt hour, depending upon the
circumstances of such under delivery. During 2002 and 2003, we did not incur or
pay any penalties.

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. The agreement extends through 2032.
In addition to naming rights, the agreement provides us with significant
sponsorship rights. The aggregate cost of the naming rights is approximately
$300 million. Starting in 2002, we began to pay $10 million each year, which
will continue through 2032, for the annual naming, advertising and other
benefits under this agreement.

Long-term Power Generation Maintenance Agreements. We have entered into
long-term maintenance agreements that cover certain periodic maintenance,
including parts, on power generation turbines. The long-term maintenance
agreements terminate over the next 5 to 13 years based on turbine usage.
Estimated cash payments over the next five years for these agreements are as
follows (in millions):

2004........................................................ $ 50
2005........................................................ 38
2006........................................................ 36
2007........................................................ 48
2008........................................................ 39
----
Total..................................................... $211
====

Other Commitments. In addition to items discussed in our consolidated
financial statements, our other contractual commitments have various quantity
requirements and durations and are not considered material either individually
or in the aggregate to our results of operations or cash flows.

(15) CONTINGENCIES

(A) LEGAL AND ENVIRONMENTAL MATTERS.

We are involved in a number of legal, environmental and other proceedings
before courts and governmental agencies. We are also subject to ongoing
investigations by various governmental agencies, including investigations into
possible criminal law violations. Although we cannot predict the outcome of
these proceedings, many of these matters involve substantial claim amounts
which, in the event of an adverse judgment, could have a material adverse effect
on our results of operations, financial condition and cash flows.

LEGAL MATTERS.

In connection with several of the following proceedings, CenterPoint and
certain of its subsidiaries are parties to such proceedings. Pursuant to our
indemnity agreement with CenterPoint, we have assumed the

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RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

defense and related indemnity obligations arising from claims against
CenterPoint and its subsidiaries in each of the related proceedings.

CLASS ACTION LAWSUITS

Western States Electricity Class Actions. Certain of our operating
subsidiaries have been named, along with a number of other defendants, including
a subsidiary of CenterPoint, as defendants in class action lawsuits in
California. In general, the plaintiffs allege that our operating subsidiaries
unlawfully conspired to increase wholesale electricity prices in California from
2000 to 2001. The lawsuits seek injunctive relief, treble damages, restitution
of overpayments, disgorgement of unlawful profits and legal expenses. These
lawsuits fall into three groups:

- The first group consists of six lawsuits originally filed in the fourth
quarter of 2000 and the first quarter of 2001 and subsequently
consolidated in one proceeding before the United States District Court
for the Southern District of California. In December 2002, the court
ordered that the six lawsuits be tried in California state court. The
court's order is under appeal before the United States Court of Appeals
for the Ninth Circuit.

- The second group consists of eight lawsuits originally filed in the
second quarter of 2002 and subsequently consolidated into one proceeding
before the United States District Court for the Southern District of
California. In August 2003, the court dismissed seven of the eight cases
on the basis of federal preemption and the filed rate doctrine, the
eighth case not having been served on any of the defendants. The
plaintiffs have appealed to the United States Court of Appeals for the
Ninth Circuit.

- The third group consists of a multi-state class action lawsuit filed in
May 2003 against an operating company of our wholesale energy segment and
a subsidiary of CenterPoint that is currently pending before the United
States District Court for the Southern District of California.

Snohomish County PUD Class Action. In July 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,
along with a number of other defendants. The plaintiffs allege manipulation of
the price of electricity purchased by the utility for its customers in violation
of California's antitrust and unfair and unlawful business practices laws. In
January 2003, the United States District Court for the Southern District of
California dismissed the lawsuit on the basis of 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. We, and certain of our operating companies,
along with a number of other defendants, including a subsidiary of CenterPoint,
are parties to two class action lawsuits consolidated before the United States
District Court of Nevada, and a third that has been conditionally transferred to
the United States District Court of Nevada from the United States District Court
for the Eastern District of California. In each of the three suits, the
plaintiffs allege 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. In one of the lawsuits, the
plaintiffs allege violations of the federal Sherman Act. The lawsuits seek
injunctive and declaratory relief, treble the amount of damages, restitution,
disgorgement of unjust enrichment, costs of suit and attorneys' fees.

A fourth class action was filed in February 2004, in Superior Court of the
State of California, San Diego County against one of our operating subsidiaries
and a number of other defendants. Similar to the other class actions, plaintiffs
allege 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 plaintiffs seek injunctive and declaratory
relief, treble the amount of damages, disgorgement of unjust enrichment, costs
of suit and attorneys' fees.
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

We and certain of our operating companies, along with a number of other
defendants, are also parties to a taxpayer representative lawsuit filed in
November 2002 by the California Lieutenant Governor in the Superior Court of the
State of California, Los Angeles County on behalf of purchasers of gas and power
in California. The plaintiff alleges 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 damages, restitution and legal fees.

Natural Gas Futures Complaints. Certain of our wholesale energy segment
operating companies and a subsidiary of CenterPoint are defendants in three
class action lawsuits pending before the United States District Court for the
Southern District of New York (originally filed in August, October and November
2003, respectively). The plaintiffs in each case allege that the defendants
manipulated the price of natural gas and thereby influenced 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.

STATE ATTORNEY GENERAL LAWSUITS/COMPLAINTS

California Attorney General Actions. In March 2002, the California
Attorney General filed a lawsuit against Reliant Resources, a subsidiary of
CenterPoint and several of our wholesale energy segment operating companies. The
lawsuit alleged 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 sought
injunctive relief, disgorgement of our alleged unlawful profits for sales of
electricity and civil penalties. In March 2003, the United States District Court
for the Northern District of California dismissed this lawsuit on the basis of
federal preemption and the filed rate doctrine. The California Attorney General
has appealed to the United States Court of Appeals for the Ninth Circuit.

In March 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 failure of our operating companies to file
transaction-specific information about sales and purchases resulted in a refund
obligation to the extent that such transactions took place at prices above "just
and reasonable" rates. In May 2002, the FERC denied the complaint but ordered
our operating companies to 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 FERC's decision.

In April 2002, the California Attorney General sued Reliant Resources, a
subsidiary of CenterPoint, and several of our wholesale energy segment operating
companies. The lawsuit is substantially similar to the complaint filed with the
FERC described above. In addition, the lawsuit alleges that we 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 other equitable relief. In March 2003, the United States District
Court for the Northern District of California dismissed this lawsuit on the
basis of federal preemption and the filed rate doctrine. The California Attorney
General has appealed to the United States Court of Appeals for the Ninth
Circuit.

In April 2002, the California Attorney General and the California
Department of Water Resources (CDWR) sued 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,
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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.

Montana Attorney General Action. On June 30, 2003, the Montana Attorney
General and Flathead Electric Cooperative sued one of our wholesale energy
segment operating companies, along with a number of other defendants, in the
First Judicial District Court of Montana, County of Lewis and Clark. The
plaintiffs allege that, together with other energy and trading company
defendants named in the suit, our operating companies conspired to restrain
trade and to 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. The lawsuit seeks injunctive relief, treble the amount of
damages alleged, costs of suit and attorneys' fees, but has not been served on
any of the defendants.

PRIVATE LITIGANTS

Sierra Pacific Resources and Nevada Power Company. In November 2003,
Nevada Power Company named us as a defendant in arbitration before the American
Arbitration Association. Nevada Power alleges that we conspired to drive up the
price of natural gas in violation of various state and federal laws. Nevada
Power seeks $15 million in the arbitration for its alleged damages.

Los Angeles Department of Water and Power (LADWP). In July 2003, the City
of Los Angeles sued Reliant Resources, CenterPoint and one of our wholesale
energy segment operating companies in the Superior Court in California. The case
has been conditionally removed to the United States District Court of Nevada to
proceed with the natural gas class actions discussed above. 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, which it estimates at $218
million, interest, and legal costs. 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.

In January of 2004, the City of Los Angeles filed a similar lawsuit against
us and other natural gas trading and marketing companies in California Superior
Court. The lawsuit alleges many of the same state law claims but does not allege
the federal law claims included in the first lawsuit.

Nevada Power and PacificCorp Complaints. In June 2003, the FERC denied a
series of complaints filed by Nevada Power Company and PacificCorp, which sought
reformation of certain forward power contracts those companies had with several
counterparties, including one of our subsidiaries. The complainants have
appealed.

Texas Commercial Energy. In July 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 committed violations of state and federal antitrust laws, fraud,
negligent misrepresentation, breach of fiduciary duty, breach of contract and
civil conspiracy. The lawsuit seeks damages in excess of $535 million, exemplary
damages, treble damages, interest, costs of suit and attorneys' fees. In
November 2003, two other retail electric providers in the ERCOT market requested
to intervene in this action as plaintiffs making factual allegations similar to
those made by Texas Commercial Energy, LLP and seeking the same kinds of relief,
although not specifying the amount of damages they seek. The intervention motion
and the motions to dismiss Texas Commercial Energy, LLP's complaint are set for
hearing in May 2004.

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Bankruptcy of Enron Corp. and Its Affiliates. In the fourth quarter of
2001, Enron Corp. filed a voluntary petition for bankruptcy. Accordingly, we
recorded a $68 million provision, comprised of provisions against 100% of Enron
receivables of $79 million offset by net trading and derivative balances of $11
million. In 2002, we sued Enron Canada Corp., the only Enron party to our
netting agreement which is not in bankruptcy, in United States District Court
for the Southern District of Texas to recover $78 million (an amount which
reflects the netting pursuant to the netting agreement of amounts among various
Enron subsidiaries and our subsidiaries). The case is pending. However, in
January 2003, Enron sued us in United States Bankruptcy Court for the Southern
District of New York claiming $13 million based on the unenforceability of the
netting agreement.

In November 2003, Enron Canada Corp., which is seeking to enjoin our
lawsuit against it in Texas, initiated a lawsuit in Canada involving a gas
purchase and sale contract underlying our netting agreement. Enron Canada Corp.
asserts that the netting agreement is unenforceable and that our Canadian
subsidiary has therefore breached the gas purchase and sale agreement by failing
to pay approximately $4 million under the gas purchase and sale agreement. Enron
Canada Corp. alleges that we are also liable for this amount under a guarantee.
We have not yet been served in this lawsuit.

In addition, on December 1, 2003, a subsidiary of Enron Corp. sued one of
our subsidiaries, Reliant Energy Services, Inc. (Reliant Energy Services), in
United States Bankruptcy Court for the Southern District of New York for $85
million. Enron alleges that a series of related natural gas financial swap
transactions executed by and among Enron, Reliant Energy Services and the Bank
of Montreal on November 5, 2001, resulted in set-offs against debts with Enron,
which should be invalidated under the preference, set-off and fraudulent
conveyance provisions of the bankruptcy code.

The non-trading derivatives with Enron were designated as cash flow hedges
(see note 7). 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 forecasted transactions occur. During 2002 and 2003, $52
million gain and $3 million loss, respectively, was reclassified into earnings
related to these cash flow hedges. As of December 31, 2002 and 2003, the
remaining amount to be reclassified into earnings through 2007 was $6 million
and $3 million of losses, respectively.

RMF Industrial Contracting, Inc. In July 2003, a subcontractor
participating in the construction of our 521 MW electric generating facility,
the Seward project, filed a mechanics' lien in the amount of $36 million against
property owned by one of our subsidiaries. The subcontractor has alleged that
the contractor for the Seward project prevented the subcontractor from
completing its work on the project and failed to pay it for work performed on
the project. The terms of the engineering, procurement and construction contract
for the project permits our subsidiary to withhold payments to the contractor to
protect itself against the possibility that the lien is found to be valid, and
requires the contractor to indemnify and hold our subsidiary harmless from the
mechanics' lien and the cost of defending related actions. As of March 1, 2004,
our subsidiary has withheld payments to the contractors in an aggregate amount
exceeding $36 million. The existence of the mechanics' lien does not constitute
a default or an event of default under any of our, or our subsidiaries' credit
agreements. The matter is pending before the United States District Court for
the Western District of Pennsylvania.

PUCT Cases. Since 2002, the PUCT has approved various increases to the
fuel factor component contained in our "price-to-beat." Parties opposing the
increases have filed for judicial review of the PUCT's orders in state district
court in Travis County, Texas. To date, the court has affirmed the first PUCT
ruling. While the other rulings are pending at the district court, the parties
opposing the increases, have appealed the district court's decision. In each of
these proceedings we are vigorously contesting the appeal.

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TRADING AND MARKETING INVESTIGATIONS

FERC Investigations of Western Market Issues. In October 2003, we entered
into a settlement agreement with the FERC resolving its investigations and
proceedings in connection with its ongoing review of western energy markets
(exclusive of pending FERC proceedings concerning refund obligations in
connection with wholesale electricity sales into the Cal ISO and California
Power Exchange (Cal PX) markets, as described below in note 15(b), and the
gaming show cause proceedings, described below). The settlement provides that:

- We make three cash settlement payments, totaling $25 million, into a fund
established for the benefit of California and western market electricity
consumers. In October 2003, we paid $15 million into the fund; additional
payments of $5 million each shall be made in September 2005 and 2006;

- 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

- Until October 2004, 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.

In 2003, we offered, but did not receive qualifying bids for, capacity from
the 824 MW portion of our California generation portfolio for the 12-month
period beginning April 1, 2004. Although the units will be subject to up to two
more auctions, we have mothballed the units comprising this portion of our
California generation portfolio.

Under the terms of the settlement, we retain the ability to make sales of
power at market-based rates. The FERC 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 2003 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.

In 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.

The gaming show cause proceedings involve allegations that certain of our
subsidiaries unlawfully gamed the California markets by engaging in double
selling and paper trading of ancillary services and by engaging in so-called
ricochet trades. The FERC staff found no foundation to the allegations that our
subsidiaries engaged in paper trading, ricochet transactions or collusive gaming
practices. While not admitting the allegations of double selling of ancillary
services, our subsidiaries entered into a settlement with the FERC in which we
agreed to pay $836,000 in resolution of allegations of double selling. The
settlement resolved related allegations of double selling of ancillary services
made by the Cal ISO in July

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2003 against our operating subsidiaries and the Cal ISO's proposed rescission of
approximately $11 million paid to us. The FERC denied the proposed rescission
and found that all allegations of double selling of ancillary services were to
be resolved in the gaming show cause proceedings.

In January 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 (which
was expensed in the fourth quarter of 2002) directly to customers of the Cal PX
and certain other terms, including a requirement to abide by a must offer
obligation to submit bids for all of our uncommitted, available capacity from
our plants located in California into a California spot market one additional
year following termination of our existing must offer obligation or until
December 31, 2006, whichever is later.

Investigations by the CFTC. In November 2003, we entered into a settlement
with the Commodity Futures Trading Commission (CFTC) in connection with an
investigation relating to trading and price reporting issues. The settlement
addressed the reporting of natural gas trading information to energy industry
publications that compile and report index prices and seven offsetting and
pre-arranged electricity trades that were executed on an electronic trading
platform in 2000. Pursuant to the terms of the settlement, without admitting or
denying liability, one of our subsidiaries agreed to pay a civil monetary
penalty of $18 million, which was paid and expensed in the fourth quarter of
2003.

Investigations by United States Attorneys. We have received subpoenas and
informal requests 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 "round trip
trades," price reporting and alleged price manipulation. We have produced
information to each of the United States Attorneys' offices. The United States
Attorney for the Southern District of New York has closed its investigation.

In response to July 24, 2003, Grand Jury subpoenas, 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. On March 5, 2004, the United
States Attorney's office for the Northern District of California informed our
counsel that it intends to seek a criminal indictment against our subsidiary,
Reliant Energy Services, and certain of its current and former employees (none
of whom is an officer of Reliant Resources), alleging price manipulation based
on the curtailment of electricity generation in California on two days in June
2000. The allegation of price manipulation during this two-day period was the
subject of the settlement with the FERC in January 2003 described above. In our
settlement, we neither admitted nor denied that these actions affected prices in
any market, or violated any law, tariff or regulation.

We do not believe that our subsidiary engaged in actions in violation of
laws, tariffs or regulations in effect at the time and intend vigorously to
contest the allegations. We do not believe that this action against our
subsidiary will have a material impact on our ongoing business operations,
including any impact on our credit or debt agreements, the wholesale license
held by our subsidiary, the retail and wholesale licenses held by our other
subsidiaries or contracts and agreements to which our subsidiary is a party.

The United States Attorney for the Southern District of Texas is currently
investigating natural gas reporting price issues. This investigation could
result in civil or criminal actions being brought against us, certain of our
subsidiaries or our current or former employees.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

SHAREHOLDER CLASS ACTIONS

We are defendants in 15 class action lawsuits filed on behalf of purchasers
of our securities and the securities of CenterPoint. The lawsuits allege that
the defendants violated federal securities laws by, among other things, making
false and misleading statements about trading volumes and revenues. The lawsuits
seek monetary damages on behalf of persons who purchased CenterPoint securities
during specified class periods. In August 2002, the shareholder lawsuits were
consolidated into one proceeding before the United States District Court,
Southern District of Texas, Houston Division. In March 2003, we and the other
defendants filed a motion to dismiss certain of the claims. In January 2004, the
court dismissed with prejudice the federal and state securities fraud claims.
With the dismissal of all fraud-related claims, the only remaining claims
against us are claims under Section 11 and 15 of the Securities Act of 1933
pertaining to statements made in our registration statement for our initial
public offering.

Illinois Shareholder Lawsuit. 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 other class action lawsuits and
seeks treble damages and legal expenses. In January 2004, the court dismissed
the action for failing plead facts supporting plaintiffs' claims, but also
granting plaintiffs leave to file an amended complaint to attempt to cure the
pleading defects.

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 and CenterPoint, on behalf of participants in our and CenterPoint's
employee benefits plans. The lawsuit alleges breach of fiduciary duties in
violation of the Employee Retirement Income Security Act in connection with
investment decisions made by the plans in CenterPoint and our securities. The
lawsuit seeks monetary damages and restitution. In May 2003, the defendants
filed a motion to dismiss the claims. In January 2004, the court dismissed us as
a defendant from this proceeding on standing grounds. CenterPoint, and certain
members of CenterPoint's benefits committee, remain in this case.

SHAREHOLDER DERIVATIVE ACTIONS

Derivative Lawsuit. 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 by causing us to conduct our business in an imprudent and
unlawful manner. Among other things, the lawsuit cites (a) alleged failures to
implement and maintain an adequate internal accounting control system, (b)
"round trip trading transactions" (including the dissemination of materially
misleading and inaccurate information regarding revenue and trading volume) and
(c) withholding power in the California market in June 2000. The lawsuit seeks
monetary damages on our behalf.

In December 2002, our board of directors appointed a special litigation
committee to investigate the claims asserted in the lawsuit. The special
litigation committee was assisted in its investigation by external counsel
appointed by the committee. In December 2003, the special litigation committee
determined that it would not be in our best interest to proceed with the
derivative lawsuit. The special litigation committee has asked the court to
dismiss the suit.

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 at 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

environmental liabilities of $35 million and $23 million as of December 31, 2002
and 2003, respectively, of which we expect to spend $8 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 December 31, 2002 and 2003, we have
recorded the estimated liability for the remediation costs of $8 million and $7
million, respectively, which we expect to pay out through 2008.

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 $87 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 December
31, 2002 and 2003, the total estimated liability determined by management with
assistance from third-party engineers and recorded by Orion Power for these
disposal sites was $14 million and $11 million, respectively, of which $1
million is to be paid over the next five years.

New Source Review Matters. The United States 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 requested from the EPA a copy of all correspondence
relating to the EPA's request for information for one of the six facilities,
which request the EPA has granted. Furthermore, the New York state attorney
general's office and the Pennsylvania Department of Environmental Protection
recently requested from the EPA a copy of all such correspondence relating to
all six facilities, which the EPA granted.

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 results of operations,
financial condition or cash flows.

(b) CALIFORNIA ENERGY SALES CREDIT AND REFUND PROVISIONS.

As of December 31, 2003, our consolidated balance sheet included a $189
million net receivable, included in the $242 million below, for energy sales in
California that relate to sales of power by us into the markets run by the Cal
ISO and the Cal PX in 2000 and 2001.

The receivable remains outstanding as a result of defaults by purchasers of
power in the Cal ISO and Cal PX markets in 2000 and 2001, primarily, the two
investor owned utilities, Pacific Gas and Electric (PG&E) and Southern
California Edison Company (SCE). The receivable is also the subject of the
refund proceeding initiated by the FERC in 2001 regarding prices charged by our
wholesale energy segment in California from October 2, 2000 through June 20,
2001.

SCE has paid to the Cal ISO and the Cal PX all amounts due by it on account
of power purchases; however, no distributions have been made pending resolution
of the FERC refund proceeding. PG&E filed
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for protection under the bankruptcy laws in April 2001 and has not made payment
on account of these pre-petition claims. In December 2003, the bankruptcy court
confirmed PG&E's plan of reorganization. The plan of reorganization adopts a
settlement agreement with the California Public Utilities Commission and calls
for the payment of our claim, including interest thereon, in cash and in an
amount determined by the FERC in the refund proceeding. There is an appeal and
request for rehearing pending the bankruptcy confirmation order and the
California Public Utilities Commission's order approving the settlement
agreement, respectively.

We have receivables due from the Cal ISO, the Cal PX and the CDWR for
energy sales in the California wholesale market during the fourth quarter of
2000 through December 31, 2003. Our gross receivables for California energy
sales are adjusted for (a) an expected refund obligation, (b) a credit reserve
and (c) interest receivable. The adjustments impacted our net receivables as
follows:

During 2001, 2002 and 2003, we adjusted our estimated refund obligation and
credit reserve (netted in revenues) and interest income (recorded in interest
income) related to energy sales in California as follows (income (loss)):

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

(1) We recorded a credit reserve provision in 2000 of $39 million relating to
energy sales in California; taken together with our impacts in 2001, 2002
and 2003, we have a net credit reserve of $21 million as of December 31,
2003.

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 to be between $81 million and $210 million for energy
sales in California. We base this estimate on a number of assumptions:

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

- 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 and
(b) to permit a reduction in refund liability if actual gas costs

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

during the refund period exceeded allowed gas costs under the proxy gas
price used in the FERC's refund formula.

The low end of the range of our estimate, which we have recorded, is based
on a refund calculation factoring in a reduction in the total FERC refund based
on (a) the actual cost paid for gas over the proposed proxy gas price and (b)
exclusion of all purchases made by the CDWR from the refund calculation. The
high end of the range of our estimate of the refund obligation assumes that the
refund obligation is not adjusted for (a) the actual cost paid for gas over the
proposed proxy gas price and (b) purchases made by the CDWR that were in excess
of the amounts needed to meet the needs of the California utilities. We continue
to assess our low and high ends of the range and our most probable estimate
within that range based on the FERC orders which clarify/modify the refund
calculation methodology and it is possible that we could have additional changes
to our accrual and/or our range in the future.

During 2001, we established a $15 million reserve for potential refund
obligations. During 2002, we recognized an additional reserve for potential
refund obligations of $176 million resulting in a reserve of $191 million as of
December 31, 2002. During 2003, we reversed $110 million of previously recorded
refund provisions due to the decisions by the FERC in March and October 2003
permitting us to file to recover our actual gas costs to the extent they exceed
the amount determined using the proxy gas price under the modified refund
formula. As of December 31, 2003, our reserve for refunds related to energy
sales in California was $81 million.

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

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 of this provision resulting in a $6 million provision as of
December 31, 2002. The reversal in 2002 resulted from collections of outstanding
receivables during the period, a determination that credit risk had been reduced
on the remaining outstanding receivables as a result of payments in 2002 to the
Cal PX and due to the write-off of receivables as a result of a May 2002 FERC
order and related interpretations and a March 2003 FERC order discussed above.
During 2003, we recorded additional credit provisions of $15 million due to the
reversal of refund provisions discussed above. As of December 31, 2003, we had a
remaining pre-tax credit provision of $21 million against these receivable
balances. We will continue to assess the collectability of these receivables
based on further developments in the FERC refund proceeding and will adjust the
credit reserve to reflect the impact of such developments in the periods in
which they occur.

Interest Calculation. During 2002 and 2003, we recorded net interest
income of $5 million and $13 million, respectively. We estimated net interest
income based on:

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

- the lowest range in our estimated potential refund;

- the receivable balance outstanding; and

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

(C) TOLLING AGREEMENT FOR LIBERTY'S GENERATING STATION.

LEP owns a 530 MW combined cycle gas fired power generation facility (the
Liberty generating station). Liberty financed the construction costs of the
Liberty generating station with borrowings under a credit agreement of which
$262 million is outstanding as of December 31, 2003. Borrowings under the
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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 interest in LEP. See note 9(a).

In July 2003, the counterparty to the tolling agreement under which LEP
sold the generation output of the Liberty generation station filed for
bankruptcy. Subsequently, a federal bankruptcy court issued an order that
terminated the tolling agreement and triggered another event of default under
the Liberty credit agreement. The default under the Liberty credit agreement,
and the possible foreclosure by the lenders upon the assets of the Liberty
generating station, do not constitute an event of default under any other debt
agreements of Reliant Resources or its affiliates.

To date, the lenders under the Liberty credit agreement have not foreclosed
upon the Liberty generating station. However, there can be no assurance that the
lenders will continue to refrain from exercising such rights. If the lenders
elect to foreclose on LEP, Liberty 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 of December 31, 2003, the combined net book value of LEP
and Liberty was $346 million, excluding the non-recourse debt obligations of
$262 million. At December 31, 2002 and 2003, we evaluated the Liberty generating
station and the related intangible asset for the terminated tolling agreement
for impairment. Based on our analyses, there were no impairments.

In September 2003, LEP sued the corporate guarantor of the counterparty to
the tolling agreement, Gas Transmission Northwest Corporation, seeking payment
of $140 million (the maximum amount of the guarantee) out of the $177 million
termination claim calculated by LEP under the agreement. Subsequently, the
counterparty to the tolling agreement and its corporate guarantors countersued
LEP seeking to collect a $108 million termination payment under the tolling
agreement. The obligations of LEP under the tolling agreement are secured by a
$35 million letter of credit issued under the senior secured revolver of Reliant
Resources. If the letter of credit were to be drawn, Reliant Resources would be
required to reimburse the issuing bank.

In light of current market conditions and the termination of the tolling
agreement, LEP does not expect to have sufficient cash flow to pay both (a) all
of its expenses and to post the collateral required to buy fuel or in respect of
the gas transportation agreements and (b) debt service obligations. Liberty
received temporary deferrals until April 2004 from its lenders for the quarterly
principal installments that were due in October 2003 and January 2004, which
aggregated $4 million. Based on the foregoing, we are exploring various
strategic options with respect to our subsidiaries interest in the Liberty
generating station, including, among other things, the execution of a
foreclosure arrangement with the lenders resulting in a transfer of ownership to
the lenders or a sale of our interest in the generating station. There can be no
assurances regarding the outcome of this process. A foreclosure of our interest
in the generation station would, however, result in an impairment of the asset
on our balance sheet.

If LEP recovers the amount of the termination claim, the lenders are
entitled to require that such amounts be used to pay deferred interest and to
prepay debt under the Liberty credit agreement. Under United States and
Pennsylvania tax laws, it is possible that receipt of a termination payment by
LEP could be deemed taxable income to Reliant Resources and its other
affiliates.

(16) 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

F-80

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

institutional customers and to increase the facility to a maximum total of $350
million. Pursuant to the receivables facility, we formed a 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.

The amount of accounts receivable included under the arrangement may
increase as certain accounts receivable become eligible, particularly from some
of 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 above is accounted for as a sale of
receivables, which is recorded after the first step, and as a result the related
receivables are excluded from our consolidated balance sheets. We continue to
service the receivables and receive a fee of 0.5% of cash collected. The
following table details the servicing fee income and costs associated with the
sale of receivables:

The following table details the outstanding receivables that have been sold
and the corresponding notes receivable from the QSPE, which have been reflected
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. 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

F-81

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

details the maximum amount under the receivables facility and the amount of
funding outstanding as of December 31, 2002 and 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 for 2002 and 2003, an average discount
rate of 5.40% and 8.40%, respectively, was applied to projected cash collections
over a 6-month period. Our collection experience indicated that 98% of the
accounts receivables would be collected within a 6-month period.

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.

(17) RELIANT ENERGY COMMUNICATIONS

During 2001, management decided to exit our communications business.
Consequently, we determined the goodwill associated with the communications
business was impaired. We recorded a total of $54 million of pre-tax disposal
charges in 2001. These charges included the write-off of goodwill of $19
million, fixed asset impairments of $22 million, and severance accruals and
other incremental costs associated with exiting the communications business,
totaling $13 million.

(18) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of financial instruments, including cash and cash
equivalents and trading and derivative assets and liabilities (see note 7), are
equivalent to their carrying amounts in the consolidated balance sheets. The
fair values of trading and derivative assets and liabilities as of December 31,
2002 and 2003 have been determined using quoted market prices for the same or
similar instruments when available or other estimation techniques, see note 7.

The carrying values and related fair market values of our short-term and
long-term debt are detailed as follows (excluding adjustment to fair value of
interest rate swaps and debt under our Liberty credit agreement):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Excludes Liberty's fixed rate debt of $165 million and floating rate debt of
$103 million and $97 million as of December 31, 2002 and 2003, respectively,
as there was no active market for this debt. Due to the situation with
Liberty (see note 15(c)), if the holders of Liberty's debt were to have
tried to sell such debt instrument to a third party, the price which could
have been realized would likely be substantially less than the face value of
the debt instrument and substantially less than the carrying value.

(2) As of December 31, 2002, we had floating rate debt with a carrying value of
$5.9 billion, excluding adjustment to fair value of interest rate swaps and
Liberty's debt. There was no active market for our floating rate debt
obligations as of December 31, 2002. Given our liquidity and credit
situation as of December 31, 2002, if the holders of these borrowings were
to have tried to sell such debt instruments to third parties, the prices
which could have been realized could have been substantially less than the
face values of the debt instruments and substantially less than our carrying
values.

(3) The fair market values of our fixed rate debt (December 31, 2002 and 2003)
and floating rate debt (for December 31, 2003 only) were based on (a) our
incremental borrowing rates for similar types of borrowing arrangements or
(b) information from market participants. For $2.0 billion of our floating
rate debt, the carrying value equals the fair market value.

(4) Each of these amounts includes the values related to the outstanding
warrants. See note 9.

(19) 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.; REPG;
Reliant Energy Retail Holdings, LLC; Reliant Energy Retail Services, LLC;
Reliant Energy Services; Reliant Energy Shelby County II, LP and Reliant Energy
Solutions, LLC.

Orion Power Holdings is the only limited guarantor of these senior secured
notes and its guarantee of both the March 2003 credit facilities and the senior
secured notes 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; LEP; Orion
Capital; Orion MidWest; Orion Power MidWest LP, LLC; Orion NY; Orion Power New
York LP, LLC; Reliant Energy Capital (Europe), Inc. (RECE); Channelview; Reliant
Energy Europe, Inc. (REE); Reliant Energy Trading & Marketing, B.V. (sold in
December 2003); REMA; Reliant Energy New Jersey Holdings, LLC; Reliant Energy
Power Generation Benelux, N.V. (sold in December 2003) and Reliant Energy Europe
B.V. (RE BV) (sold in December 2003). All subsidiaries of Orion Power Holdings
are non-guarantors. In connection with the sale of our European energy
operations in December 2003, the majority of our European entities were sold.
Effective February 2004, after the sale of our European energy operations, the
following entities formerly classified as non-guarantors, became full and
unconditional guarantors: RECE and REE. No adjustments to the disclosures for
2001, 2002 or 2003 were made for this change as the change will be made
prospectively beginning in 2004. However, it is expected that these entities
formerly in our European energy operations will have an insignificant amount of
activity and/or balances.

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

F-83

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following condensed consolidating financial information presents
supplemental information for the indicated groups as of December 31, 2002 and
2003 and for 2001, 2002 and 2003:

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS.

F-84

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-85

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(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.

F-86

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(2) Based on Orion Power Holdings 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 in the fourth quarter of
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 in the third quarter of
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 Holdings 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 in the
third quarter of 2003 in the non-guarantor column. When combined with the
$337 million impairment recognized in 2002, Orion Power Holdings and its
consolidated subsidiaries have recorded a cumulative impairment of $922
million as of December 31, 2003. Other than Orion Power Holdings'
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 in the third quarter of 2003. This
estimate reflects the difference between the consolidated Reliant Resources'
impairment and the cumulative impairments recorded by Orion Power Holdings
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.

F-87

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CONDENSED CONSOLIDATING BALANCE SHEETS.

F-88

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-89

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-90

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-92

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-93

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-94

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-95

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

F-97

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The quarterly operating results incorporate the results of operations of
Orion Power from our February 2002 acquisition date as discussed in note 5. The
variances in revenues from quarter to quarter for 2002 and 2003 were primarily
due to (a) the Orion Power acquisition (for 2002 only), (b) the seasonal
fluctuations in demand for electric energy and energy services, (c) changes in
energy commodity prices and (d) implementation of EITF No. 02-03 (2002 only) and
EITF No. 03-11 (2003 only) (see

F-98

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

notes 2(d) and 7). Changes in operating income (loss) and net income (loss) from
quarter to quarter for 2002 and 2003 were primarily due to:

- the seasonal fluctuations in demand for electric energy and energy
services;

- changes in energy commodity prices;

- the timing of maintenance expenses on electric generation plants; and

- provisions and reversals related to energy sales and refunds in
California.

In addition, operating income (loss) and net income (loss) changed from
quarter to quarter in 2002 by:

- the impact of the Orion Power acquisition (see note 5);

- $109 million in pre-tax loss related to changes in our estimated refund
obligation, credit reserve and interest receivable for energy sales in
California ($33 million in income in the first quarter, $29 million in
loss in the second quarter, $15 million in loss in the third quarter and
$98 million in loss in the fourth quarter) (see note 15(b));

- $234 million, net of tax, cumulative effect of an accounting change
related to the adoption of SFAS No. 142 in the first quarter of 2002 for
our discontinued European energy operations (only impacted net loss) (see
note 6);

- a one-time $109 million pre-tax gain resulting from the amendment of
certain contracts in our European energy discontinued operations in the
second quarter of 2002 (only impacted net income);

- costs related to plant cancellations and equipment impairments in the
second and third quarters of 2002;

- $128 million accrual recorded in the third and fourth quarters of 2002
for a payment to CenterPoint (see note 14(d));

- $47 million pre-tax, non-cash charge in the third quarter of 2002
relating to the accounting settlement of certain benefit obligations
associated with our separation from CenterPoint (see note 12);

- $45 million tax accrual related to our European energy discontinued
operations in the third quarter of 2002 (only impacted net income);

- $482 million goodwill impairment in our European energy discontinued
operations in the fourth quarter of 2002 (only impacted net loss) (see
note 6);

- impairment charges of $32 million pre-tax relating to certain cost method
investments ($27 million pre-tax in the fourth quarter) in 2002 (see note
2(o)); and

- $14 million provision for a FERC settlement in January 2003, which was
recorded in the fourth quarter of 2002 (see note (15(a)).

Also, operating income (loss) and net income (loss) changed from quarter to
quarter in 2003 by:

- $108 million in pre-tax income related to changes in our estimated refund
obligation, credit reserve and interest receivable for energy sales in
California ($84 million in income in the first quarter, $1 million in
income in the second quarter and $23 million in income in the fourth
quarter) (see note 15(b));

F-99

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

- $310 million loss on the disposition of our discontinued European energy
operations ($384 million loss in the first quarter, $44 million gain in
the second quarter, $53 million loss in the third quarter and $83 million
gain in the fourth quarter) (only impacted net loss) (see note 22);

- $80 million pre-tax trading loss related to certain of our natural gas
trading positions recognized in the first quarter of 2003;

- $47 million accrual for a payment to CenterPoint in the first quarter of
2003 (see note 14(d));

- $24 million, net of tax, cumulative effect of accounting changes
primarily in the first quarter of 2003 (only impacted net loss) (see
notes 2(c), 2(d) and 2(q));

- $985 million goodwill impairment in our wholesale energy segment in the
third quarter of 2003 (see note 6);

- $75 million loss on the disposition of our Desert Basin plant operations
in the third quarter of 2003 (see note 23);

- $37 million provision for a settlement agreement reached with the FERC in
the third quarter of 2003 (see note 15(a));

- $28 million write-off of deferred financing costs in the third quarter of
2003 (see note 2(r));

- $14 million increase in depreciation expense associated with the early
retirements of several units in the third quarter of 2003;

- $27 million write-off of deferred financing costs in the fourth quarter
of 2003 (see note 2(r)); and

- $18 million provision for the CFTC settlement in the fourth quarter of
2003 (see note 15(a)).

(21) REPORTABLE SEGMENTS

We have identified the following reportable segments: retail energy,
wholesale energy and other operations. The accounting policies of our reportable
segments are the same as those described in the summary of significant
accounting policies (note 2). We account for intersegment revenues as if such
revenues were to third parties, that is, at current market prices or pursuant to
intercompany agreements entered into at current market prices. In December 2003,
we sold our European energy operations and have classified that as discontinued
operations (see note 22). In October 2003, we sold our Desert Basin plant
operations (which was formerly included in our wholesale energy segment) and
have classified that as discontinued operations (see note 23). 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. Earnings (loss) before interest
expense, interest income and income taxes (EBIT) is the primary measurement used
by our management to evaluate the performance of each of our business segments.
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.

As part of our review of the organization of our business units, effective
December 31, 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 wholesale energy segment rather than our retail
energy segment. Reportable segments from prior periods have been reclassified to
conform to the 2003 presentation.

Long-lived assets include net property, plant and equipment, net goodwill,
net other intangibles and equity investments.

F-100

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

F-101

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) For 2001, 2002 and 2003, revenues include trading margins of $401 million,
$283 million and $(38) million, respectively.

(2) For 2001, 2002 and 2003, revenues include trading margins of $(23) million,
$5 million and $(11) million, respectively.

F-102

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

General. In February 2003, we signed an agreement to sell our European
energy operations through the sale of our shares in RE BV, a holding company for
these operations. The sale closed in December 2003.

We calculated the United States dollar amounts, for those items disclosed
as of either December 31, 2002 or 2003, assuming an exchange rate of 1.2595 US
dollar to the Euro for December 31, 2003, and an exchange rate of 1.0492 US
dollar to the Euro for December 31, 2002, unless the context indicates
otherwise.

Purchase Price. We received net cash proceeds of $1.4 billion (Euro 1.1
billion). We used the net cash proceeds from the sale (a) 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 and (b) to prepay $567
million of debt under our March 2003 credit facilities ($360 million, which had
been temporarily placed in an escrow account, and an additional $207 million
from the remaining net proceeds).

As additional contingent consideration for the sale, we are also entitled
to receive from the purchaser 90% of any cash payments in excess of $139 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. As of December
31, 2003, we have no asset recorded in our consolidated balance sheet for these
potential cash payments from NEA.

Accounting Treatment of Sale Transaction. In connection with the sale, we
recognized a loss on disposition of $310 million during 2003. We do not
currently anticipate that there will be a Dutch or United States income tax
benefit realized by us as a result of this loss. We will recognize contingent
payments, if any (as discussed above), in earnings upon receipt. During the
first quarter of 2003, we began to report the results of our European energy
operations as discontinued operations in accordance with SFAS No. 144 and
accordingly, reclassified 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
6.

F-103

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Assets and liabilities related to our European energy discontinued
operations were as follows as of December 31, 2002 (in millions):

CURRENT ASSETS:
Cash and cash equivalents................................. $ 112
Accounts and notes receivable and accrued unbilled
revenues, principally customer, net.................... 377
Other current assets...................................... 164
------
Total current assets................................... 653
------
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 1,647
OTHER ASSETS:
Stranded costs indemnification receivable................. 203
Investment in NEA......................................... 210
Other..................................................... 16
------
Total long-term assets................................. 2,076
------
Total Assets......................................... $2,729
======
CURRENT LIABILITIES:
Current portion of long-term debt and short-term
borrowings............................................. $ 631
Accounts payable, principally trade....................... 306
Other current liabilities................................. 147
------
Total current liabilities.............................. 1,084
------
OTHER LIABILITIES:
Trading and derivative liabilities, including stranded
costs liability........................................ 363
Other liabilities......................................... 348
------
Total other liabilities................................ 711
------
LONG-TERM DEBT.............................................. 37
------
Total long-term liabilities............................ 748
------
Total Liabilities.................................... $1,832
======
Accumulated other comprehensive income...................... $ 39
======

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

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

(1) Included in this amount is a $310 million loss related to our loss on
disposition.

F-104

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(23) 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 in October 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. We used the net proceeds from the sale of $285 million to prepay
indebtedness under our March 2003 credit facilities.

During the third quarter of 2003, we began to report the results of our
Desert Basin plant operations as discontinued operations in accordance with SFAS
No. 144 and accordingly, reclassified amounts from prior periods. We recognized
a loss of $75 million, after-tax, on the disposition of our Desert Basin plant
operations during 2003. The loss on disposition of $84 million ($75 million
after-tax), consisted of a loss of $21 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
2003.

Assets and liabilities related to our Desert Basin plant discontinued
operations were as follows as of December 31, 2002 (in millions):

CURRENT ASSETS:
Cash and cash equivalents................................. $ --
Accounts and notes receivable and accrued unbilled
revenues, principally customer, net.................... 6
Other current assets...................................... 5
----
Total current assets................................... 11
----
PROPERTY, PLANT AND EQUIPMENT, NET.......................... 302
OTHER ASSETS:
Other..................................................... --
----
Total long-term assets................................. 302
----
Total Assets......................................... $313
====
CURRENT LIABILITIES:
Accounts payable, principally trade....................... $ 1
Other current liabilities................................. 3
----
Total current liabilities.............................. 4
----
OTHER LIABILITIES:
Other liabilities......................................... 12
----
Total other liabilities................................ 12
----
Total long-term liabilities............................ 12
----
Total Liabilities.................................... $ 16
====

F-105

RELIANT RESOURCES, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

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

(1) Included in this amount is an $84 million loss related to our loss on
disposition.

* * *

F-106

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF OPERATIONS
(THOUSANDS OF DOLLARS)

See Notes to the Condensed Financial Statements and Reliant Resources'
Consolidated Financial Statements
F-107

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED BALANCE SHEETS
(THOUSANDS OF DOLLARS)

See Notes to the Condensed Financial Statements and Reliant Resources'
Consolidated Financial Statements
F-108

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS
(THOUSANDS OF DOLLARS)

F-109

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT
CONDENSED STATEMENTS OF CASH FLOWS -- (CONTINUED)
(THOUSANDS OF DOLLARS)

See Notes to the Condensed Financial Statements and Reliant Resources'
Consolidated Financial Statements
F-110

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

These condensed parent company financial statements have been prepared in
accordance with Rule 12-04, Schedule 1 of Regulation S-X, as the restricted net
assets of Reliant Resources' subsidiaries exceed 25% of the consolidated net
assets of Reliant Resources. This information should be read in conjunction with
the Reliant Resources and subsidiaries consolidated financial statements
included elsewhere in this filing.

Reliant Resources, a Delaware corporation, was incorporated in August 2000
with 1,000 shares of common stock, which were owned by Reliant Energy. Effective
December 31, 2000, Reliant Energy consolidated its unregulated operations under
Reliant Resources. In addition, corporate support and executive officers
transferred to Reliant Resources on January 1, 2001.

Effective July 1, 2003, we formed a new company, Reliant Energy Corporate
Services, LLC (RECS), which is wholly-owned by Reliant Resources. RECS was
created to hold the employees, the employee-related costs and other general
corporate activities that were previously held by Reliant Resources. The
applicable assets and liabilities were transferred from Reliant Resources to
RECS effective July 1, 2003.

Reliant Resources' 100% investments in its subsidiaries have been recorded
using the equity basis of accounting in the accompanying condensed parent
company financial statements. Included in equity in earnings (loss) of
investments in subsidiaries in 2001, 2002 and 2003 are (a) earnings/losses
related to our European energy operations, which have been reflected as
discontinued operations as more fully described in note 22 to Reliant Resources'
consolidated financial statements and (b) cumulative effects of accounting
changes for new accounting pronouncements as more fully described in notes 2(c),
2(d), 2(q) and 6 to Reliant Resources' consolidated financial statements.

Some amounts from the previous years have been reclassified to conform to
the 2003 presentation of condensed financial information. These
reclassifications do not affect earnings.

(2) CERTAIN RELATED PARTY TRANSACTIONS

(A) INCOME TAXES

Prior to October 1, 2002, Reliant Resources was included in the
consolidated federal income tax returns of CenterPoint and calculated its income
tax provision on a separate return basis under a tax sharing agreement with
CenterPoint. Prior to October 1, 2002, current federal income taxes were payable
to or receivable from CenterPoint. Subsequent to September 30, 2002, Reliant
Resources files a separate federal income tax return. As of October 1, 2002,
Reliant Resources entered into a tax sharing agreement with certain of its
subsidiaries. Pursuant to the tax sharing agreement, Reliant Resources pays all
federal income taxes on behalf of its subsidiaries included in the consolidated
tax group and is entitled to any related tax refunds. The difference between
Reliant Resources' current federal income tax expense or benefit, as calculated
on a separate return basis, and related amounts payable to/receivable from the
Internal Revenue Service is reflected as an increase/decrease to the investments
in subsidiaries account and is reflected on the subsidiaries' books as
adjustments to their equity. During 2002 and 2003, Reliant Resources made equity
contributions to its subsidiaries for deemed distributions related to current
federal income taxes of $64 million and $52 million, respectively.

(b) ALLOCATIONS OF GENERAL, ADMINISTRATIVE AND DEPRECIATION COSTS AND CASH
MANAGEMENT FUNCTION

Certain general, administrative and depreciation costs are allocated from
Reliant Resources to its subsidiaries. For 2001, 2002 and 2003, these
allocations were $136 million, $187 million and $110 million, respectively, and
are netted in the applicable line on the condensed statements of operations. The
unpaid
F-111

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

allocations are reflected as a component of current advances to and notes
receivable from subsidiaries, net in the condensed balance sheets. As discussed
in note 1, as certain assets and liabilities were transferred from Reliant
Resources to RECS effective July 1, 2003, the related activity and costs from
that date through December 31, 2003 were allocated from RECS to Reliant
Resources' subsidiaries and are not reflected in the $110 million of allocations
discussed above for 2003. The amount allocated from RECS to Reliant Resources'
subsidiaries from July 1, 2003 through December 31, 2003, was $125 million.

Through June 30, 2002, a subsidiary of CenterPoint had established a "money
fund" through which Reliant Resources could borrow or invest on a short-term
basis. Also, during 2001, proceeds not utilized from the IPO were advanced to
this subsidiary of CenterPoint. Reliant Resources earned interest income from
CenterPoint for these short-term investments. After the IPO, Reliant Resource
established a similar "money fund" or "central bank" through which its
subsidiaries can borrow or invest on a short-term basis. The net amounts are
included in current and long-term advances to and notes receivable from
subsidiaries, net in the condensed balance sheets.

(3) 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, 2003 is approximately $2.8 billion.
Such restrictions are on the net assets of Orion Capital, Liberty and
Channelview. Orion MidWest and Orion NY are subsidiaries of Orion Capital.

It is the customary practice of Reliant Resources to loan monies to and
borrow monies from certain of its subsidiaries through the use of the "central
bank" as described in note 2 above. However, there were no legally declared cash
dividends or return of shareholder's equity to Reliant Resources from its
subsidiaries in 2001, 2002 and 2003.

(4) BANKING OR DEBT FACILITIES

For a discussion of Reliant Resources' banking or debt facilities, see note
9 to Reliant Resources' consolidated financial statements. Reliant Resources'
debt obligations are included in the Other Operations segment data in note 21 to
Reliant Resources' consolidated financial statements.

Maturities of Reliant Resources' debt obligations outstanding as of
December 31, 2003, were as follows (in millions):

2004........................................................ $ --
2005........................................................ --
2006........................................................ --
2007........................................................ 1,968
2008........................................................ --
2009 and thereafter......................................... 1,376
------
Subtotal.................................................. 3,344
Other items included in debt................................ (8)
------
Total debt................................................ $3,336
======

F-112

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

(5) COMMITMENTS AND CONTINGENCIES

For a discussion of Reliant Resources' commitments and contingencies, see
notes 14 and 15 to Reliant Resources' consolidated financial statements.

(a) GUARANTEES

Reliant Resources has issued guarantees in conjunction with certain
performance agreements and commodity and derivative contracts and other
contracts that provide financial assurance to third parties on behalf of a
subsidiary or an unconsolidated third-party. The guarantees on behalf of
subsidiaries are entered into primarily to support or enhance the
creditworthiness otherwise attributed to a subsidiary on a stand-alone basis,
thereby facilitating the extension of sufficient credit to accomplish the
relevant subsidiary's intended commercial purposes.

The following tables detail Reliant Resources' various guarantees,
including the maximum potential amounts of future payments, assets held as
collateral and the carrying amount of the liabilities recorded on the balance
sheets, if applicable:

F-113

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Reliant Resources has guaranteed the performance of certain of its
wholly-owned subsidiaries' trading and hedging obligations. These guarantees
were provided to counterparties in order to facilitate physical and
financial agreements in electricity, gas, oil, transportation and related
commodities and services. These guarantees have varying expiration dates.
The fair values of the underlying transactions are included in Reliant
Resources' subsidiaries' balance sheets.

(2) See note 14(b) to Reliant Resources' consolidated financial statements for
discussion of Reliant Resources' guarantees under the construction agency
agreements. These guarantees were terminated in March 2003.

(3) Reliant Resources has guaranteed the payment and performance obligations of
certain wholly-owned subsidiaries arising under certain power purchase
agreements. As of December 31, 2003, these guarantees have varying
expiration dates through December 2016.

(4) Reliant Resources has outstanding standby letters of credit which guarantee
the performance of certain of its wholly-owned subsidiaries. As of December
31, 2003, these letters of credit expire on various dates through December
2004.

(5) Reliant Resources has guaranteed the payment obligations of certain
wholly-owned subsidiaries arising under long-term service agreements and
leases for certain facilities. As of December 31, 2003, the expiration of
certain guarantees was not yet determinable. As of December 31, 2003,
guarantees with determinable expiration dates expire over varying years
through December 2019.

(6) Reliant Resources has guaranteed, in the event CenterPoint becomes
insolvent, certain non-qualified benefits of CenterPoint's and its
subsidiaries' existing retirees at the Distribution. See note 14(e) to
Reliant Resources' consolidated financial statements.

(7) Reliant Resources has guaranteed commodity related payments for certain
wholly-owned subsidiaries' sale of electricity to large commercial,
industrial and institutional customers to facilitate the physical and
financial transactions of electricity services. As of December 31, 2003,
these guarantees expire on various dates through October 2006.

Unless otherwise noted, failure by the primary obligor to perform under the
terms of the various agreements and contracts guaranteed may result in the
beneficiary requesting immediate payment from Reliant Resources. To the extent
liabilities exist under the various agreements and contracts that Reliant
Resources guarantees, such liabilities are recorded in Reliant Resources'
subsidiaries' balance sheets at December 31, 2003. Management believes the
likelihood that Reliant Resources would be required to perform or otherwise
incur any significant losses associated with any of these guarantees is remote.

Reliant Resources has entered into contracts that include indemnification
and guarantee provisions as a routine part of its 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
F-114

RELIANT RESOURCES, INC.

SCHEDULE I -- CONDENSED FINANCIAL INFORMATION OF REGISTRANT

NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

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, Reliant Resources generally
indemnifies 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. Management believes the likelihood of making any
material payments under these provisions is remote. For additional discussion of
certain indemnifications and guarantees by Reliant Resources, see note 14(e) to
Reliant Resources' consolidated financial statements.

(b) LEASES

As of December 31, 2003, Reliant Resources is obligated under long-term
non-cancelable operating leases, including the lease related to our corporate
headquarters. The following table sets forth information concerning these cash
obligations as of December 31, 2003 (in millions):

2004........................................................ $ 26
2005........................................................ 22
2006........................................................ 22
2007........................................................ 22
2008........................................................ 22
2009 and thereafter......................................... 217
----
Total..................................................... $331
====

* * *

F-115

RELIANT RESOURCES, INC. AND SUBSIDIARIES

SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2003
(THOUSANDS OF DOLLARS)

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

(1) Charged to other accounts represents obligations acquired through business
acquisitions and transfers of reserves to other accounts. In 2003, we
changed our classification of certain derivative activities that
historically were reclassified as trading activities to non-trading
activities. See note 2(d) to Reliant Resources' consolidated financial
statements.

(2) Deductions from reserves represents losses or expenses for which the
respective reserves were created. In the case of the uncollectible accounts
reserve, such deductions are net of recoveries of amounts previously written
off.

* * *

F-116

INDEX TO FINANCIAL STATEMENTS

RELIANT ENERGY RETAIL HOLDINGS, LLC
AND SUBSIDIARIES

Independent Auditors' Report................................ F-118
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-119
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-120
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-121
Consolidated Statements of Member's (Deficit) Equity and
Comprehensive Income (Loss) for the Years Ended December
31, 2001, 2002 and 2003................................... F-122
Notes to Consolidated Financial Statements.................. F-123

F-117

INDEPENDENT AUDITORS' REPORT

To the Management of Reliant Energy Retail Holdings, LLC
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant
Energy Retail Holdings, LLC and its subsidiaries (the Company), as of December
31, 2002 and 2003, and the related consolidated statements of operations, cash
flows, member's (deficit) equity and comprehensive income (loss) for each of the
three years in the period ended December 31, 2003. These financial statements
are the responsibility of the Company's management. Our responsibility is to
express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2002 and 2003, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of America.

As discussed in notes 2, 5 and 6 to the consolidated financial statements,
the Company changed its accounting for energy trading contracts and its
presentation of revenues and costs of sales associated with non-trading
commodity derivative activities in 2003, its method of presenting its trading
activities from a gross basis to a net basis and its accounting for goodwill and
other intangibles in 2002.

DELOITTE & TOUCHE LLP

Houston, Texas
March 5, 2004

F-118

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See Notes to the Consolidated Financial Statements
F-119

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to the Consolidated Financial Statements
F-120

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to the Consolidated Financial Statements
F-121

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF MEMBER'S (DEFICIT) EQUITY
AND COMPREHENSIVE INCOME/(LOSS)

See Notes to the Consolidated Financial Statements
F-122

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

(a) BACKGROUND.

Reliant Energy Retail Holdings, LLC (Retail Holdings), a wholly-owned
subsidiary of Reliant Resources, Inc. (Reliant Resources), was formed September
1, 2000 in Delaware. Reliant Resources is the sole member and holds all 1,000
shares of Retail Holdings. Retail Holdings and its subsidiaries are collectively
referred to herein as "the Company." Prior to September 30, 2002, the majority
of Reliant Resources' common stock was owned by CenterPoint Energy, Inc.
(CenterPoint), a regulated energy services and delivery company. CenterPoint
served the electricity customers in Houston, Texas until January 1, 2002, when
the electricity market opened to retail competition. On September 30, 2002,
CenterPoint distributed all of the 240 million shares of Reliant Resources'
common stock it owned to its common shareholders (Distribution).

The Company provides electricity products and services to end-use retail
customers, ranging from residential and small commercial customers to large
commercial, industrial and institutional customers, primarily in Texas. In 2003,
the Company began providing retail energy products and services to small and
large commercial, industrial and institutional customers in New Jersey and
Maryland.

Certain of the Company's wholly-owned subsidiaries include Reliant Energy
Retail Services, LLC (Retail Services), formed in September 2000; Reliant Energy
Solutions, LLC (Solutions), formed in April 1996; Reliant Energy Electric
Solutions, LLC (Electric Solutions), formed in January 2002; StarEn Power, LLC
(StarEn Power), formed in November 2000; Reliant Energy Solutions East, LLC
(Solutions East), formed in February 2002 and Reliant Energy Renewables, Inc.
(Renewables), formed in April 2000. In December 2000, Reliant Resources
contributed the operations of Retail Services and the member's equity of
Solutions to Retail Holdings. In accordance with accounting principles generally
accepted in the United States of America (GAAP), the transfers from Reliant
Resources were accounted for as a reorganization of entities under common
control. In January 2003, the Company purchased all the outstanding common stock
in Renewables from Reliant Energy Power Generation, Inc., an affiliated company
and an indirect wholly-owned subsidiary of Reliant Resources for $27,000 and
assumed all notes payable to affiliated companies. The purchase price was based
on Renewables' book value. The acquisition was treated as a reorganization of
entities under common control.

(b) BASIS OF PRESENTATION.

The consolidated statements of operations include general corporate
expenses allocated by Reliant Resources to the Company and by CenterPoint to the
Company during 2001. All of the allocations in the consolidated 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 the Company had
been operated as a stand-alone entity. Additionally, costs to manage the
Company's supply might be greater if incurred on a stand-alone basis.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) RECLASSIFICATIONS.

Some amounts from the previous years have been reclassified to conform to
the 2003 presentation of financial statements. These reclassifications do not
effect earnings.

(b) USE OF ESTIMATES AND MARKET RISK AND UNCERTAINTIES.

The preparation of financial statements in conformity with GAAP requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities, disclosure of

F-123

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 Company's critical
accounting estimates include: (a) trading and derivative activities, (b)
estimated revenues and energy supply costs and (c) contingencies.

The Company is subject to the risk associated with price movements of
energy commodities and the credit risk associated with its commercial
activities. For additional information regarding these risks, see notes 2(d) and
6. The Company is subject to risks relating to the reliability of the systems,
procedures and other infrastructure necessary to operate the business. The
Company is also subject to risks relating to changes in laws and regulations;
the outcome of pending lawsuits, governmental proceedings and investigations;
the effects of competition; liquidity concerns in its markets; the availability
of adequate supplies of electricity; weather conditions; the creditworthiness or
financial distress of its counterparties; actions by rating agencies with
respect to Reliant Resources or its competitors; political, legal, regulatory
and economic conditions and developments; the successful operation of
deregulating power markets and other items.

(c) PRINCIPLES OF CONSOLIDATION.

The accounts of the Company and its wholly-owned subsidiaries are included
in the consolidated financial statements except for a receivables facility
arrangement, which involves a qualified special purpose entity (QSPE) formed as
a bankruptcy remote subsidiary in 2002, that the Company entered into with
financial institutions that purchase undivided interests in the Company's
accounts receivable from certain retail customers (see note 12). All significant
intercompany transactions and balances are eliminated in consolidation.

(d) REVENUES AND ACCOUNTING FOR HEDGING AND TRADING ACTIVITIES.

Electricity Revenues. The Company records gross revenues for energy sales
and services to residential, small commercial and large commercial, industrial
and institutional electric customers that have not executed a contract under the
accrual method and these revenues generally are recognized upon delivery.
Electricity sales to large commercial, industrial and institutional customers
under contracts executed after October 25, 2002 are typically accounted for
under the accrual method and these gross revenues are generally recognized upon
delivery.

Electricity sales to large commercial, industrial and institutional
customers under contracts executed before October 25, 2002 were accounted for
under the mark-to-market method of accounting upon contract execution. See
further discussion below of the impact of implementation of Emerging Issues Task
Force (EITF) Issue No. 02-03, "Issues Related to Accounting for Contracts
Involved in Energy Trading and Risk Management Activities," (EITF No. 02-03)
rescinding EITF Issue No. 98-10, "Accounting for Contracts Involved in Energy
Trading and Risk Management Activities," (EITF No. 98-10).

The determination of retail energy sales is based on the reading of
customer meters by the transmission and distribution utilities. The transmission
and distribution utilities in Texas send the information to the Electric
Reliability Council of Texas (ERCOT) Independent System Operator (ERCOT ISO),
which in turn sends the information to the Company. The Company may be limited
in its ability to confirm the accuracy of such information. This activity occurs
on a systematic basis throughout the month. 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. Unbilled revenue
is estimated each month based on estimated volumes for each customer class and
derived from weather factors and analyses of historical trends and experience.
As of December 31, 2002 and 2003, the Company had accrued unbilled revenues of
$216 million and $290 million, respectively. As additional information becomes
available, the Company revises its estimated revenues related to prior periods
and records the
F-124

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

results in subsequent periods. The Company believes that the estimates and
assumptions utilized to recognize revenues are reasonable and represent its best
estimates. However, actual results can differ from those estimates.

Hedging Activities. Effective January 1, 2001, the Company adopted
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended (SFAS No. 133), which
establishes accounting and reporting standards for derivative instruments. The
adoption did not have a material impact to the Company's consolidated financial
statements.

If certain conditions are met, the Company may designate a derivative
instrument as hedging (a) the exposure to variability in expected future cash
flows (cash flow hedge), (b) the exposure to changes in the fair value of an
asset or liability (fair value 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 sheets whether or not it is
designated as a hedge. Derivative commodity contracts for the physical delivery
of purchase and sale quantities transacted in the normal course of business are
designated as normal purchases and sales exceptions and are not reflected in the
consolidated balance sheet at fair value. 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.

The Company designates its derivatives utilized in non-trading activities
as cash flow hedges only if there is a high correlation between price movements
in the derivative and the item designated as being hedged. This correlation is
measured both at the inception of the hedge and on an ongoing basis, with an
acceptable level of correlation of at least 80% to 125% for hedge designation.
The gains and losses related to derivative instruments designated as cash flow
hedges are deferred in accumulated other comprehensive income (loss), net of
tax, to the extent the contracts are effective as hedges, and then are
recognized in the results of operations in the same period as the settlement of
the underlying hedged transactions. Once the anticipated transaction occurs, the
accumulated deferred gain or loss recognized in accumulated other comprehensive
income (loss) is reclassified and included in the consolidated statements of
operations (a) prior to October 1, 2003, under the captions (i) purchased power,
in the case of hedging activities related to physical power purchases and (ii)
revenues, in the case of hedging activities related to physical power sales
transactions and (b) effective October 1, 2003, under the captions (i) purchased
power, in the case of hedging activities related to physical power purchases
that do physically flow and (ii) revenues, in the case of hedging activities
related to physical power sales transactions and physical power purchases that
do not physically flow.

For a derivative not designated as a hedge, changes in fair value are
recorded as unrealized gains or losses in the results of operations. If and when
correlation ceases to exist at an acceptable level, hedge accounting ceases and
changes in fair value are recognized currently in the results of operations. If
it becomes probable that a forecasted transaction will not occur, the Company
immediately recognizes the respective deferred gains or losses in the results of
operations. The associated hedging instrument is then marked to market through
the results of operations for the remainder of the contract term unless a new
hedging relationship is redesignated. Prior to October 1, 2003, revenues and
purchased power related to sale and purchase contracts designated as hedges were
generally recorded on a gross basis in the delivery period. In July 2003, the
EITF issued EITF No. 03-11, which stated 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.
Reclassification of prior year amounts is not required. On October 1, 2003, the
Company began reporting prospectively the settlement of sales and purchases of
purchased power related to the non-trading commodity derivative activities that
were not physically delivered on a net basis in the consolidated statement of
operations based on the item hedged. This change

F-125

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

resulted in decreased revenues and a corresponding decrease in power of $3
million for the fourth quarter of 2003. The Company believes the application of
EITF 03-11 will continue to result in certain amounts of our non-trading
commodity derivative activities being reported on a net basis prospectively that
were previously reported on a gross basis. EITF No. 03-11 has no impact on
margins or net income. Comparative financial statements for prior periods have
not been reclassified to conform to this presentation, as it is not required. In
addition, it is not practicable to determine sales and purchased power in 2001,
2002 and the nine months ended September 30, 2003 that would have been shown net
if EITF No. 03-11 had been applied to the results of operations historically.

In April 2003, the Financial Accounting Standards Board (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. 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 the consolidated financial statements.

For additional discussion of derivative and hedging activities, see note 6.

Trading Activities. In 2002, the EITF 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. Beginning in
the quarter ended September 30, 2002, the Company reports all energy trading
activities on a net basis in the consolidated statements of operations.
Comparative financial statements for prior periods were reclassified to conform
to this presentation.

Furthermore, in 2002, the EITF 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. This transition was
effective (a) on January 1, 2003 for contracts executed prior to October 25,
2002 and (b) on October 25, 2002 for contracts executed on or after that date.
The Company recorded a cumulative effect of a change in accounting principle of
$6 million gain, net of tax of $4 million, effective January 1, 2003, related to
EITF No. 02-03. The cumulative effect reflects the fair value, as of January 1,
2003, of contracts executed prior to October 25, 2002 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, electricity sales to large commercial, industrial and
institutional customers under executed contracts (and the related energy supply
contracts) for contracts executed prior to October 25, 2002 were accounted for
under the mark-to-market method of accounting pursuant to EITF No. 98-10.
Accordingly, these contractual commitments were recorded at fair value in
revenues on a net basis upon contract execution. As of December 31, 2002, the
recognized, unrealized balances were recorded at fair value in trading and
derivative assets/liabilities in the consolidated balance sheet. Beginning in
January 2003, the Company began applying the normal purchase and sale exception
of SFAS No. 133 to a substantial portion of the large commercial, industrial and
institutional sales contracts and the related energy supply agreements and began
utilizing accrual accounting. The related revenues and energy supply costs are
recorded on a gross basis in the results of operations. The results of
operations related to the electricity sales to large commercial, industrial and
institutional customers for contracts executed prior to October 25, 2002 are not
comparable between 2001, 2002 and 2003 because of this change. During 2001 and
2002, the Company recognized $73 million and $(6) million, respectively, of
unrealized net gains (losses) related to our electricity sales to large
commercial, industrial and institutional customers and the related energy supply
contracts. During 2003, volumes were delivered under electricity sales to large
commercial, industrial and institutional customers under executed contracts and
the related energy supply
F-126

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

contracts for which $66 million was previously recognized as unrealized
earnings. As of December 31, 2003, the Company has unrealized gains that have
been previously recorded in the results of operations of $27 million that will
be realized upon delivery of the electricity ($21 million in 2004 and $6 million
in 2005). These unrealized gains are recorded in trading and derivative
assets/liabilities in the consolidated balance sheets of an affiliated company,
as of December 31, 2003 and the related contracts are accounted for as cash flow
hedges or normal purchases and sales contracts under SFAS No. 133. See note
3(b).

During 2001 and 2002, the Company recorded $74 million and $43 million,
respectively, of fair value at the contract inception related to trading
activities, including electricity sales to large commercial, industrial and
institutional customers and the related energy supply contracts. Inception gains
recorded were evidenced by quoted market prices and other current market
transactions for energy trading contracts with similar terms and counterparties.

For additional discussion regarding trading revenue recognition and the
related estimates and assumptions that can affect reported amounts of such
revenues, see note 6.

Set-off of Trading and Derivative Assets and Liabilities. Where trading
and derivative instruments are subject to a master netting agreement and the
criteria of FASB Interpretation No. 39, "Offsetting of Amounts Related to
Certain Contracts," are met, the Company presents trading and derivative assets
and liabilities on a net basis in the consolidated balance sheets. Trading and
derivative assets/liabilities and accounts receivable/payable are presented
separately in the consolidated balance sheets.

(e) GENERAL AND ADMINISTRATIVE EXPENSES.

The general and administrative expenses in the consolidated statements of
operations include (a) employee-related costs, (b) certain contractor costs, (c)
advertising, (d) bad debt expense, (e) marketing and market research, (f)
corporate and administrative services (including management services, financial
and accounting, cash management and treasury support, legal, information
technology system support, office management and human resources) and (g)
certain benefit costs. Some of these expenses are allocated from affiliates, see
further discussion in note 3.

(f) PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION EXPENSE.

The Company records property, plant and equipment at historical cost.
Depreciation is computed using the straight-line method based on estimated
useful lives. Property, plant and equipment includes the following:

Information technology assets include hardware, software, consultant time,
in-house labor and capitalized interest used to design and implement various
systems, including the customer billing and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

energy supply systems. Costs are capitalized in accordance with Statement of
Position 98-1, "Accounting for Cost of Computer Software Developed or Obtained
for Internal Use".

Depreciation expense was $8 million, $25 million, and $35 million for 2001,
2002 and 2003, respectively.

The Company periodically evaluates property, plant and equipment for
impairment when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. The determination of whether an
impairment has occurred is based on an estimate of undiscounted cash flows
attributable to the assets, as compared to the carrying value of the assets. A
resulting impairment loss is highly dependent on the underlying assumptions.

(g) GOODWILL AND AMORTIZATION EXPENSE.

The Company records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Through 2001, the
Company amortized goodwill on a straight-line basis over 15 years. Pursuant to
the Company's adoption of SFAS No. 142, "Goodwill and Other Intangible Assets"
(SFAS No. 142) on January 1, 2002, the Company discontinued amortizing goodwill.
See note 5 for a discussion regarding the Company's adoption of SFAS No. 142.
Goodwill amortization expense was $2 million for 2001. Amortization expense for
other intangibles was $1 million for 2001, 2002 and 2003. See also note 5.

The Company periodically evaluates goodwill and other intangibles when
events or changes in circumstances indicate that the carrying value of these
assets may not be recoverable. In 2001, the determination of whether an
impairment had occurred was based on an estimate of undiscounted cash flows
attributable to the assets, as compared to the carrying value of the assets.
Effective January 1, 2002, goodwill and other intangibles are evaluated for
impairment in accordance with SFAS No. 142 (see note 5). For further discussion
of goodwill and other intangible asset impairment analyses in 2002 and 2003, see
note 5.

(h) STOCK-BASED COMPENSATION PLANS.

The Company applies the intrinsic value 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 the stock options to employees have
all been granted with the exercise price equal to market value at date of grant,
no compensation expense has been recognized under APB No. 25. The Company
complies with the disclosure requirements of SFAS No. 123, "Accounting for
Stock-Based Compensation" (SFAS No. 123) and SFAS No. 148, "Accounting for
Stock-Based Compensation -- Transition and Disclosure, an amendment to SFAS No.
123" (SFAS No. 148) and discloses the pro forma effect on net income (loss) as
if the fair value method of accounting had been applied to all stock awards. The
FASB has announced that it plans to require all companies to expense the fair
value of employee stock options in 2005. The FASB is still evaluating "fair
value" valuation models and other items.

If compensation costs had been determined as prescribed by SFAS No. 123,
net income (loss) would have approximated the following pro forma results for
2001, 2002 and 2003, which take into account the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

For further information regarding Reliant Resources' and CenterPoint's
stock-based compensation plans in which the Company's employees participate, see
note 8.

(i) CAPITALIZATION OF INTEREST EXPENSE.

Interest expense is capitalized as a component of major projects under
construction and is amortized over the estimated useful lives of the assets. It
is principally applied to information technology projects. During 2001, 2002 and
2003 the Company capitalized interest of $4 million, $2 million and $1 million,
respectively.

(j) INCOME TAXES.

Although the Company is organized as a limited liability company, and
therefore has no federal income tax liability, the Company calculates an income
tax provision on a separate return basis. The Company uses the asset and
liability method of accounting for deferred income taxes and measures deferred
income taxes for all significant income tax temporary differences. The current
deferred tax assets and liabilities are shown net in the consolidated balance
sheets because the asset/liability is with Reliant Resources. The non-current
deferred tax assets and liabilities are shown net in the consolidated balance
sheets for the same reason. For additional information regarding income taxes,
see note 9.

Prior to October 1, 2002, the Company was included in the consolidated
federal income tax returns of CenterPoint. As of October 1, 2002, the Company is
included in the consolidated tax returns of Reliant Resources and calculates its
income tax provision on a separate return basis. Pursuant to the Company's tax
sharing agreement with Reliant Resources, Reliant Resources pays all federal
income taxes on its behalf and is entitled to any related tax refunds. The
difference between the Company's current federal income tax expense or benefit,
as calculated on a separate return basis, and related amounts paid or received
to/from Reliant Resources, if any, are recorded on its books as adjustments to
member's equity on its consolidated balance sheets. During 2002 and 2003,
Reliant Resources made equity contributions to the Company for deemed
distributions related to current federal income taxes of $76 million and $243
million, respectively.

(k) CASH AND CASH EQUIVALENTS.

The Company records as cash and cash equivalents all highly liquid
short-term investments with original maturities or remaining maturities at date
of purchase of three months or less.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(l) ALLOWANCE FOR DOUBTFUL ACCOUNTS.

Accounts and notes receivable, principally customers, net in the
consolidated balance sheets are net of an allowance for doubtful accounts of $36
million and $38 million at December 31, 2002 and 2003, respectively. The net
provision for doubtful accounts in the consolidated statements of operations for
2001, 2002 and 2003 was $3 million, $73 million and $65 million, respectively.
The Company accrues a provision for doubtful accounts based upon estimated
percentages of uncollectible revenues. The Company determines these percentages
from counterparty credit ratings, historical collections, accounts receivable
aging analyses and other factors. The Company reviews the provision and
estimated percentages periodically and adjusts them as appropriate. The Company
writes-off accounts receivable balances against the allowance for doubtful
accounts when it deems the receivable to be uncollectible.

(m) NEW ACCOUNTING PRONOUNCEMENTS.

As of February 20, 2004, no standard setting body or authoritative body has
established new accounting pronouncements or changes to existing accounting
pronouncements that would have a material impact to the Company's results of
operations, financial position or cash flows, for which the Company has not
already adopted and/or disclosed elsewhere in these notes.

(3) RELATED PARTY TRANSACTIONS

Accounts and notes payable -- affiliated companies relate primarily to
purchased power, interest, charges for services and office space rental. The
affiliate accounts payable and notes payable are generally settled on a monthly
basis, with the exception of a $375 million affiliate note as of December 31,
2002 from Reliant Resources. These items are discussed more fully below.

(a) RELIANT RESOURCES.

Corporate Support Services. Reliant Resources provides the Company various
corporate support services, including accounting, finance, investor relations,
tax, risk, treasury, planning, legal, communications, governmental and
regulatory affairs, human resources, information technology services and other
shared services such as corporate security, facilities management, accounts
payable, purchasing, payroll and office support services. The costs of services
have been directly charged or allocated to the Company using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment and proportionate corporate formulas based on
operating expenses and employees. These charges and allocations are not
necessarily indicative of what would have been incurred had the Company been a
stand-alone entity. Amounts charged and allocated to the Company for these
services were $13 million, $65 million and $93 million for 2001, 2002 and 2003,
respectively. Included in these amounts are $4 million, $8 million and $10
million, for 2001, 2002 and 2003, respectively, for the Company's share of
allocated rent expense, which is included in general and administrative expense
in the consolidated statements of operations.

Reliant Resources manages the Company's daily cash balances. Excess cash is
advanced to Reliant Resources, which provides a cash management function, and is
recorded in long-term note receivable -- affiliated company in the consolidated
balance sheets. As cash is required to fund operations, the Company's bank
accounts are funded by Reliant Resources, and those changes are recorded as a
reduction in long-term note receivable -- affiliate. The Company records
interest income or expense, based on whether the Company invested excess funds,
or borrowed funds from Reliant Resources. The amount of interest (expense)
income is $(13) million, $(1) million and $20 million, respectively.

On December 31, 2002, the Company borrowed $375 million from Reliant
Resources, which is included in accounts and notes payable -- affiliated
companies on the consolidated balance sheets as of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 31, 2002. This note was repaid on April 11, 2003 and bore interest at
the weighted average corporate borrowing interest rate.

Naming Rights to the Houston Sports Complex. In October 2000, Reliant
Resources acquired the naming rights for a football stadium and other convention
and entertainment facilities included in the stadium complex. The agreement
extends through 2032. In addition to naming rights, the agreement provides
Reliant Resources with significant sponsorship rights. The aggregate cost of the
naming rights is approximately $300 million. Starting in 2002, Reliant Resources
began to pay $10 million each year, which will continue through 2032, for the
annual naming, advertising and other benefits under this agreement. These costs
are charged to the Company by Reliant Resources and are included in general and
administrative expense in the consolidated statements of operations.

Payment to CenterPoint in 2004. Consistent with the Texas electric
restructuring law, Reliant Resources expects to make a payment to CenterPoint
for the Company's residential customers. This provision of the law requires a
payment be made to CenterPoint unless, as of December 31, 2003, 40% or more of
the electric power consumed in 2000 by each class of customer in the Houston
service territory was provided by other retail electric providers. In 2002, the
Company entered into an agreement with Reliant Resources in which the Company
agreed to reimburse Reliant Resources for the payment. This agreement was made
because Retail Services receives the benefit of these customers and related
profit margin. Currently, the Company estimates the payment to be $175 million
and expects that the payment will be made in the fourth quarter of 2004. This
amount is computed by multiplying $150 by the number of residential customers
that the Company served on January 1, 2004 in the Houston service territory,
less the number of residential customers the Company served in other areas of
Texas on that same date. The Company recognized $128 million (pre-tax) in the
third and fourth quarters of 2002 and $47 million (pre-tax) in the first quarter
of 2003 for a total accrual of $175 million as of December 31, 2003. The Company
recognized the total obligation over the period the Company recognized the
related revenues.

The Company will not be required to make a similar payment for small
commercial customers because in January 2004 the Public Utility Commission of
Texas (PUCT) found that the 40% target for small commercial customers was
reached before the end of 2003.

(b) RELIANT ENERGY SERVICES, INC.

Reliant Energy Services, Inc. (Reliant Energy Services) provides commodity
price risk management and supply procurement services for the Company. The
administrative costs for these services were $8 million and $2 million for 2002
and 2003, respectively. These costs did not exist in 2001.

Reliant Energy Services enters into contracts with third parties for the
purposes of supplying the Company with some of the electricity necessary to
serve its retail customers. These supply contracts are subject to the provisions
of the master commodity purchase and sale agreements, master netting
arrangements, and other contractual arrangements that Reliant Energy Services
utilizes with third-party customers and suppliers in connection with Reliant
Energy Services' supply portfolio management activities, including those
activities undertaken for the Company. Consequently, the cost associated with
credit support for the supply portfolio managed by Reliant Energy Services for
the Company could differ significantly from those that the Company would
experience if it managed the electricity supply portfolio directly with third
parties.

The Company reimburses Reliant Energy Services for the ultimate price of
any electricity sold from Reliant Energy Services to the Company, including
costs of derivative instruments, upon final delivery of that electricity. The
Company does not account for the unrealized value associated with the derivative
instruments executed by Reliant Energy Services with third parties because the
contracts are executed by Reliant Energy Services.

F-131

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The net purchases are included in purchased power expense in the
consolidated statements of operations, except for purchases related to supply
for large commercial, industrial and institutional customers under contracts
entered into prior to October 25, 2002 which are included in trading margins.
Purchased power from Reliant Energy Services was $3 million, $2.0 billion and
$522 million for 2001, 2002 and 2003, respectively. Sales and purchases of
electricity related to large commercial, industrial and institutional customers
under contracts entered into prior to October 25, 2002, are accounted for on the
mark-to-market basis (see note 2(d) for further discussion) and are presented on
a net basis in the consolidated statements of operations. Unrealized gains
related to supply contracts accounted for on a mark-to-market basis totaled $142
million during 2002. During 2003, the Company recognized $93 million of
previously unrealized losses related to supply contracts accounted for on a
mark-to-market basis prior to 2003. These costs did not exist in 2001. Purchases
of electricity from Reliant Energy Services included in trading margins for
2001, 2002, and 2003 were $14 million, $541 million and $0, respectively.

During 2003, certain supply contracts were transferred from Reliant Energy
Services to the Company. The value of those contracts was $43 million, net of
tax of $27 million. This transfer was included in contributions from member in
the consolidated statement of member's (deficit) equity.

(c) RELIANT ENERGY POWER GENERATION, INC.

Reliant Energy Power Generation, Inc. provides project management services
related to the construction of the Renewables facilities. The costs for these
services were $1 million in 2002 and 2003. These services were not incurred in
2001.

(d) CENTERPOINT.

Prior to the Distribution, CenterPoint was a related party. Transactions
with CenterPoint subsequent to the Distribution are not reported as affiliated
transactions. The Company had, or continues to have (as indicated) the following
agreements/transactions with CenterPoint:

Corporate Support Services. During 2001, CenterPoint provided the Company
with various corporate support services, information technology services and
other previously shared services such as corporate security, facilities
management, payroll, accounts payable, office support services, and purchasing
services. CenterPoint currently provides services involving remittance
processing, bill inserting and bill printing. Certain of these arrangements will
continue until December 31, 2004; however, the Company has the right to
terminate categories of services at an earlier date. The charges paid to
CenterPoint for these services allow CenterPoint to recover its fully allocated
costs, plus out-of-pocket costs and expenses. The costs of services have been
directly charged or allocated 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 the Company been an unaffiliated
entity. Amounts charged to the Company for these services were $2 million and $3
million during 2001 and the nine months ended September 30, 2002, the date of
the Distribution, and are included in operation and maintenance expense in the
consolidated statements of operations. It is not anticipated that a change, if
any, in these costs and revenues would have a material effect on the Company's
consolidated results of operations, cash flows or financial position.

Services Provided to CenterPoint. During 2001, the Company provided
billing, customer service, credit and collection and remittance services to
certain of CenterPoint's regulated utilities. The charges CenterPoint paid for
these services allowed the Company to recover its fully allocated costs of
providing the services, plus out-of-pocket costs and expenses. The Company
recorded $53 million of revenues and costs related to the provision of these
services during 2001.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

During 2001, Renewables sold $1 million of electricity to CenterPoint.

Cash for customer deposits and the related liability of $46 million were
transferred from CenterPoint to the Company, effective with the transfer of the
customers on January 1, 2002.

The Company also pays to CenterPoint a regulated tariff rate for electric
transmission service for delivering electricity to customers in the Houston
area. For the nine months ended September 30, 2002, the date of the
Distribution, this expense was $664 million and is included in purchased power
expense in the consolidated statement of operations.

(4) AGREEMENTS RELATED 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."

In January 2003, CenterPoint distributed approximately 19% of the common
stock of Texas Genco to CenterPoint shareholders. CenterPoint granted Reliant
Resources an option to purchase all of the remaining shares of common stock of
Texas Genco held by CenterPoint. The option expired unexercised on January 24,
2004.

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 other retail electric providers. The Company is not currently able to
participate in these legally mandated capacity auctions. Under CenterPoint's
prior agreement with Reliant Resources, Texas Genco was required to auction the
remainder of its capacity after certain other adjustments and it had the right
to participate directly in such auctions. Texas Genco's obligation to auction
its remaining capacity and the Company's associated rights terminated when
Reliant Resources decided not to exercise its option to acquire CenterPoint's
ownership interest in Texas Genco.

The Company has a master power purchase contract with Texas Genco covering,
among other things, purchases of capacity and/or energy from Texas Genco's
generating units. In connection with this contract, the Company has granted
Texas Genco a security interest in its rights in the accounts receivables and
related assets of certain of its subsidiaries. The liens on the Company's rights
in the accounts receivable and related assets are junior to the Company's
receivables facility and senior to Reliant Resources' March 2003 credit
facilities and to Reliant Resources' senior secured notes. See note 12. The term
of the master power purchase contract terminates on January 24, 2005.

The Company has purchased entitlements to some of the generation capacity
of electric generation assets of Texas Genco. Reliant Resources, through the
Company, purchased these entitlements in capacity auctions conducted by Texas
Genco. As of December 31, 2003, the Company had purchased entitlements to
capacity of Texas Genco averaging 6,376 megawatts (MW) per month in 2004 and 923
MW per month in 2005. The Company's anticipated capacity payments related to
these capacity entitlements are $714 million. The capacity entitlements are
accounted for as normal purchases under SFAS No. 133. See notes 2(d) and 6 for
discussion of the Company's derivative financial instruments.

Under a support agreement with CenterPoint, the Company provides systems,
technical, programming and consulting support services and hardware maintenance
(but excluding plant-specific hardware) necessary to provide dispatch planning,
settlement and communication with the independent system operator. The fees
charged for these services are designed to allow the Company to recover its
fully

F-133

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

allocated direct and indirect costs and reimbursement of out-of-pocket expenses.
The term of this agreement will end on the first occur of (a) CenterPoint's sale
of Texas Genco, or all or substantially all of the generating assets of Texas
Genco or (b) May 31, 2005; however, Texas Genco may extend the term of this
agreement until December 31, 2005. In addition, Texas Genco has the right to
terminate the agreement upon 90 days' notice. The fees charged for services
provided are $2 million in 2003. There were no services performed by the Company
for these services in 2001 and 2002.

(5) 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. The Company
adopted the provisions of the statement effective January 1, 2002, and
discontinued amortizing goodwill into the results of operations. A
reconciliation of 2001 reported net income adjusted for the exclusion of
goodwill amortization with a comparison to 2002 and 2003 follows:

The Company recorded goodwill for the excess of the purchase price over the
fair value assigned to the net assets of the acquisition of the energy services
division of Southland Industries in 1999. This division contained contracts for
performing energy-related services for commercial customers.

Intangibles. The Company recognizes specifically identifiable intangibles,
which include (a) demand side management contracts (DSM), which are contracts
that allow the Company to install energy efficiency equipment for clients and
share in future energy savings, (b) permanent seat licenses (PSL) at Reliant
Stadium, (c) air emissions regulatory allowances and (d) a non-compete
agreement. The DSM contracts and the non-compete agreement were purchased as
part of an acquisition of the energy services division of Southland Industries
in 1999.

The air emissions regulatory allowances were purchased in 2000 by
Renewables. Other intangible assets consist of the following:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company amortizes acquired intangibles, other than air emissions
regulatory allowances, on a straight-line basis over their contractual or
estimated useful lives. The Company does not amortize its air emissions
regulatory allowances because they have been issued in perpetuity by the Texas
Commission of Environmental Quality.

Estimated amortization expense for the next five years is as follows (in
millions):

2004........................................................ $ 1
2005........................................................ 1
2006........................................................ 1
2007........................................................ --
2008........................................................ --
----
Total $ 3
====

Goodwill. There were no changes in the carrying amount of goodwill in 2002
and 2003.

SFAS No. 142 requires goodwill to be tested at least annually and more
frequently in certain circumstances. The date of the annual impairment test was
November 1 for 2002 and 2003. 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 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 goodwill with the
carrying amount of that goodwill, to measure the amount of the goodwill
impairment, if any. Based on the first step of the goodwill impairment test
effective November 1, 2002, the Company's goodwill was not impaired. In 2003,
the Company met certain criteria which allowed it to carry forward the 2002 fair
value. Goodwill was not impaired for 2003, as the fair value exceeded the
carrying value.

(6) DERIVATIVE INSTRUMENTS, INCLUDING ENERGY TRADING ACTIVITIES

The Company is exposed to various market risks. These risks arise from the
ownership of the Company's assets and operation of the business. The Company
routinely utilizes derivative instruments such as futures, physical forward
contracts, swaps and options to mitigate the impact of changes in electricity
prices on the operating results and cash flows.

Reliant Resources has a risk control framework, which the Company is
subject to, designed to monitor, measure and define appropriate transactions to
hedge and manage the risk in the existing portfolio of assets and contracts and
to authorize new transactions. These risks fall into three different categories:
market risk, credit risk and operational risk. The Company believes that it has
effective procedures for evaluating and managing these risks to which it is
exposed. Key risk control activities include definition of appropriate
transactions for hedging, credit review and approval, credit and performance
risk measurement and monitoring, validation of transactions, portfolio valuation
and daily portfolio reporting including mark-to-market valuation, value-at-risk
and other risk measurement metrics. The Company seeks to monitor and control its
risk exposures through a variety of separate but complementary processes and
committees, which involve business unit management, senior management and
Reliant Resources' board of directors.

The primary types of derivatives used are physical forward contracts, which
are commitments to purchase or sell energy commodities in the future.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Trading and derivative assets and liabilities at December 31, 2002 and 2003
include amounts for non-trading and trading activities, as follows:

(a) NON-TRADING DERIVATIVE ACTIVITIES.

To reduce the risk from market fluctuations in the results of operations
and the resulting cash flows, the Company may enter into energy derivatives in
order to hedge expected purchases and sales of electric power (non-trading
energy derivatives). There were no such activities in 2001 and 2002.

The fair values of the non-trading derivative activities as of December 31,
2003 are determined by (a) prices actively quoted, (b) prices provided by other
external sources or (c) prices based on models and other valuation methods.

Below is the pre-tax income of the non-trading derivative instruments,
including non-trading energy derivatives, both from cash flow hedge
ineffectiveness and from non-trading derivative mark-to-market income and
losses, for 2003 (in millions):

Hedge ineffectiveness(1).................................... $--
Non-trading derivatives mark-to-market income............... 23
---
Total..................................................... $23
===

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

(1) For 2003, no component of the derivative instruments' gain or loss was
excluded from the assessment of effectiveness.

As of December 31, 2003, the Company expects $9 million of accumulated
other comprehensive income to be reclassified into the results of operations
during 2004. As of December 31, 2003, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

maximum length of time the Company is hedging its exposure to the variability in
future cash flows for forecasted transactions is 2 years.

(b) ENERGY TRADING ACTIVITIES.

Electricity sales to large commercial, industrial and institutional
customers under contracts executed before October 25, 2002 were accounted for
under the mark-to-market method of accounting upon contract execution (see note
2(d)). The fair values of trading activities as of December 31, 2002, are
determined by (a) prices actively quoted, (b) prices provided by other external
sources or (c) prices based on models and other valuation methods.

(c) CREDIT RISKS.

Credit risk is inherent in the Company's commercial activities and relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. Reliant Resources has broad credit policies and parameters,
which the Company is subject to. The Company seeks to enter into contracts that
permit the Company to net receivables and payables with a given counterparty.
The Company also enters into contracts that enable the Company to obtain
collateral from a counterparty as well as to terminate upon the occurrence of
certain events of default. The credit risk control organization establishes
counterparty credit limits. Reliant Resources employs tiered levels of approval
authority for counterparty credit limits, with authority increasing from the
credit risk control organization through senior management. Credit risk exposure
is monitored daily and the financial condition of counterparties is reviewed
periodically.

If any of the counterparties failed to perform, the Company might be forced
to acquire alternative hedging arrangements or be required to replace the
underlying commitment at then-current market prices. In this event, the Company
might incur additional losses in addition to amounts owed to the Company by the
counterparty.

As of December 31, 2003, there was one investment grade counterparty
representing 15% of the Company's total credit exposure, net of collateral. The
dollar amount of the Company's credit exposure to this counterparty was $21
million as of December 31, 2003. As of December 31, 2003, there were no other
counterparties representing greater than 10% of our total credit exposure, net
of collateral.

(7) LONG-TERM DEBT

On January 1, 2002, the Company sold equipment subject to an operating
lease. This transaction was recorded as a borrowing under SFAS No. 13,
"Accounting for Leases," because the Company retained substantial risk of
ownership in the leased property. The Company is required to either repurchase
the lease or remarket the leased equipment in the event that the lessee defaults
on the lease. The initial balance of the debt was $14 million and expires on
April 2004. As of December 31, 2002 and 2003, the remaining lease obligation was
$9 million and $4 million, respectively.

(8) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT AND OTHER BENEFIT
PLANS

(A) STOCK-BASED INCENTIVE COMPENSATION PLANS.

At December 31, 2003, eligible employees of the Company participate in four
incentive plans described below.

The Reliant Resources, Inc. 2002 Long-Term Incentive Plan (2002 LTIP)
permits Reliant Resources to grant awards (stock options, restricted stock,
stock appreciation rights, performance awards and cash awards) to key employees,
non-employee directors and other individuals which the Company expects to

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RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

become key employees within the following six months. Subject to adjustment as
provided in the plan, the aggregate number of shares of Reliant Resources'
common stock that may be issued may not exceed 17,500,000 million shares.
Reliant Resources also sponsors the Long-Term Incentive Plan of Reliant
Resources, Inc. (2001 LTIP), which was effective January 31, 2001, and was
amended to provide that no additional awards would be made under the 2001 LTIP
after June 6, 2002. Upon the adoption of the 2002 LTIP, the shares remaining
available for grant under the 2001 LTIP, totaling approximately 3.5 million,
became available as authorized shares available for grant under the 2002 LTIP.
These shares are included in the total of 17,500,000 shares available under the
2002 LTIP. Additionally, any shares forfeited under the 2001 LTIP become
available for grant under the 2002 LTIP.

The Reliant Resources, Inc. 2002 Stock Plan (2002 Stock Plan) permits
Reliant Resources to grant awards (stock options, restricted stock, stock
appreciation rights, performance awards and cash awards) to all employees
(excluding officers subject to Section 16 of the Securities Exchange Act of
1934). The board of directors authorized 6,000,000 shares for grant upon
adoption of the 2002 Stock Plan. To the extent these 6,000,000 shares were not
granted in 2002, the excess shares were canceled. An additional 6,000,000 shares
were authorized for the 2003 plan year. The total number of shares is adjusted
for new grants, exercises, forfeitures, cancellations and terminations of
outstanding awards under the plan throughout the year. Reliant Resources does
not plan to authorize additional shares for this plan after the end of the 2003
plan year.

Prior to the IPO, eligible employees participated in a CenterPoint
Long-Term Incentive Compensation Plan and other incentive compensation plans
(collectively, the CenterPoint Plans) that provided for the issuance of
stock-based incentives including performance-based shares, restricted shares,
stock options and stock appreciation rights, to key employees including
officers. The Reliant Resources, Inc. Transition Stock Plan was adopted to
govern the outstanding restricted shares and options of CenterPoint common stock
held by employees prior to the Distribution date, under the CenterPoint Plans.
There were 9,100,000 shares authorized under the Reliant Resources, Inc.
Transition Stock Plan and it is anticipated that no additional shares will be
issued.

In addition, in conjunction with the Distribution, Reliant Resources
entered into an employee matters agreement with CenterPoint. This agreement
covered the treatment of outstanding CenterPoint equity awards (including
performance-based shares, restricted shares and stock options) under the
CenterPoint Plans held by Reliant Resources employees and CenterPoint employees.
According to the agreement, each CenterPoint equity award granted to Reliant
Resources employees and CenterPoint employees prior to the agreed upon date of
May 4, 2001, that was outstanding under the CenterPoint Plans as of the
Distribution date, was adjusted. This adjustment resulted in each individual,
who was a holder of a CenterPoint equity award, receiving an adjusted equity
award of Reliant Resources common stock and CenterPoint common stock,
immediately after the Distribution. The combined intrinsic value of the adjusted
CenterPoint equity awards and Reliant Resources equity awards, immediately after
the record date of the Distribution, was equal to the intrinsic value of the
CenterPoint equity awards immediately before the record date of the
Distribution.

Performance-based Shares and Restricted Shares. Performance-based shares
and restricted shares have been granted to employees without cost to the
participants. The performance-based shares generally vest three years after the
grant date based upon performance objectives over a three-year cycle, except as
discussed below. The restricted shares vest to the participants at various times
ranging from immediate vesting to vesting at the end of a five-year period.
During 2001, 2002 and 2003, the Company recorded compensation expense of $2
million, $1 million and $1 million, respectively, related to performance-based
and restricted share grants.

Prior to the Distribution, Reliant Resources employees and CenterPoint
employees held outstanding performance-based shares and restricted shares of
CenterPoint's common stock under the CenterPoint
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Plans. On the Distribution date, each performance-based share of CenterPoint
common stock outstanding under the CenterPoint Plans, for the performance cycle
ending December 31, 2002, was converted to restricted shares of CenterPoint's
common stock based on a conversion ratio provided under the employee matters
agreement. Immediately following this conversion, outstanding restricted shares
of CenterPoint common stock were converted to restricted shares of Reliant
Resources' common stock, which shares were subject to their original vesting
schedule under the CenterPoint Plans. The conversion ratio was determined using
the intrinsic value approach described above. As such, the Company's employees
held 160,461 restricted shares outstanding under CenterPoint Plans which were
converted to 126,555 restricted shares, of Reliant Resources' common stock, of
which a majority vested on December 31, 2002.

The following table summarizes performance-based shares and restricted
shares grant activity to employees of the Company for 2001, 2002 and 2003:

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

(1) The change in performance-based shares between 2002 and 2003 is primarily
due to employee transfers.

Stock Options. Under both CenterPoint's and Reliant Resources' plans,
stock options generally vest over a three-year period and expire after ten years
from the date of grant. The exercise price is equal to or greater than the
market value of the applicable common stock on the grant date.

As of the record date of the Distribution, CenterPoint converted all
outstanding CenterPoint stock options granted prior to May 4, 2001 (totaling
664,204 stock options held by employees of the Company) to a combination of
CenterPoint stock options totaling 664,204 stock options at a weighted average
exercise price of $19.02 and Reliant Resources stock options totaling 523,794
stock options with a weighted average exercise price of $9.15. The conversion
ratio was determined using an intrinsic value approach as described above.

The following table summarizes stock options outstanding for 2001, 2002 and
2003:

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RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2003, exercise prices for Reliant Resources' stock
options outstanding and held by the Company's employees ranged from $3.51 to
$34.03.

Employee Stock Purchase Plan. In the second quarter 2001, Reliant
Resources established the Employee Stock Purchase Plan (ESPP). Under the ESPP,
employees may contribute up to 15% of their compensation, as defined, towards
the purchase of shares of Reliant Resources common stock at a price of 85% of
the lower of the market value at the beginning or end of each six-month offering
period. The initial purchase period began on the date of Reliant Resources'
initial public offering (May 2001) and ended December 31, 2001. The market value
of the shares acquired in any year may not exceed $25,000 per individual.
Amounts contributed in excess of $21,250 during a purchase period will be
refunded to the employee. The following table details the number of shares (and
price per share) issued to employees of the Company under the ESPP for 2002 and
2003 and through January 2004:

Pro Forma Effect on Net Income (Loss). In accordance with SFAS No. 123,
the Company applies the intrinsic value method contained in APB No. 25 and
discloses the required pro forma effect on net income (loss) as if the fair
value method of accounting for stock compensation was used. The weighted average
grant date fair value for an option to purchase Reliant Resources common stock
granted during 2001, 2002 and 2003 was $13.35, $5.09 and $3.10, respectively.
The weighted average grant date fair value of a purchase right issued under
Reliant Resources ESPP during 2001, 2002 and 2003 was $9.24, $4.51 and $1.80,
respectively. The weighted average grant date fair value for an option to
purchase CenterPoint common stock granted during 2001 was $9.25.

The fair values were estimated using the Black-Scholes option valuation
model with the following weighted average assumptions:

F-140

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For 2001 and 2002, stock option expected volatility was determined based on
an average of the historical volatility of Reliant Resources common stock and a
group of companies considered similar to Reliant Resources. For 2003, stock
option expected volatility was determined based on the historical volatility of
Reliant Resources common stock. The Black-Scholes option valuation model was
developed for use in estimating the fair value of traded options, which have no
vesting restrictions and are fully transferable. In addition, option valuation
models require the input of highly subjective assumptions including the expected
stock price volatility. Because Reliant Resources employee stock options and
purchase rights have characteristics significantly different from those of
traded options, and because changes in the subjective input assumptions can
materially affect the fair value estimate, in Reliant Resources' opinion, the
existing models do not necessarily provide a single measure of the fair value of
employee stock options and purchase rights.

For the pro forma computation of net income (loss) as if the fair value
method of accounting had been applied to all stock awards, see note 2(h).

(b) PENSION.

Prior to March 1, 2001, certain of the Company's employees participated in
CenterPoint's noncontributory cash balance pension plan. Effective March 1,
2001, Reliant Resources and its subsidiaries no longer accrued benefits under
this noncontributory pension plan for their domestic non-union employees
(Resources Participants). Effective March 1, 2001, each Resources Participant's
unvested pension account balance became fully vested and a one-time benefit
enhancement was provided to some qualifying participants.

The retirement plan provides retirement benefits based on years of service
and compensation. CenterPoint's funding policy was to review amounts annually in
accordance with applicable regulations in order to achieve adequate funding of
projected benefit obligations. Prior to the Distribution, pension (expense)
income was allocated to the Company based on the number of the Company's
employees with an accrued benefit. Assets of the retirement plan are not
segregated or restricted by CenterPoint's participating subsidiaries and accrued
obligations for the Company employees are the obligation of the retirement plan.
The Company's pension income was approximately $1 million for 2001 and 2002.

(c) SAVINGS PLAN.

The savings plan is a tax-qualified plan under Section 401(a) of the
Internal Revenue Code of 1986, as amended (Code), and includes a cash or
deferred arrangement under Section 401(k) of the Code for the Company's
employees. Prior to February 1, 2002, Reliant Resources' non-union employees
participated in CenterPoint's employee savings plan that is a tax qualified plan
under Section 401(a) of the Code, and included a cash or deferred arrangement
under Section 401(k) of the Code.

Under the plan, participating employees may contribute a portion of their
compensation, pre-tax or after-tax, generally up to a maximum of 16% of
compensation. The savings plan's matching contribution

F-141

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

and any payroll period discretionary employer contribution will be made in cash;
any discretionary annual employer contribution, as applicable, may be made in
Reliant Resources common stock, cash or both.

The savings plans benefit expense was $2 million, $4 million and $9 million
in 2001, 2002 and 2003, respectively.

(d) POSTRETIREMENT BENEFITS.

Historically, the Company provided some postretirement benefits through
CenterPoint plans (primarily medical care and life insurance benefits) for its
retired employees, substantially all of whom may become eligible for these
benefits when they retire. SFAS No. 106, "Employers' Accounting for
Postretirement Benefits Other Than Pensions," requires that the expected cost of
employees' postretirement benefits, be charged to income during the years in
which employees render service. The Company's postretirement benefit costs were
less than $1 million for 2001 and 2002. There were no postretirement benefit
costs in 2003.

(9) INCOME TAXES

The Company's current and deferred components of income tax (benefit)
expense were as follows:

A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

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RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Following were the Company's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the consolidated financial
statements and their respective tax bases:

F-143

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(10) COMMITMENTS

(A) LEASE COMMITMENTS.

The following table sets forth information concerning the Company's cash
obligations under non-cancelable long-term operating leases as of December 31,
2003, which primarily relate to rental agreements for building space and data
processing equipment (in millions):

2004........................................................ $ 4
2005........................................................ 4
2006........................................................ 4
2007........................................................ 3
2008........................................................ 2
2009 and thereafter......................................... 4
---
Total..................................................... $21
===

Total lease expense for all operating leases during 2001, 2002 and 2003 was
$7 million, $4 million and $5 million, respectively.

(b) GUARANTEES.

Together with certain of Reliant Resources' other subsidiaries, the Company
is a guarantor of the obligations under Reliant Resources' Amended and Restated
Credit and Guaranty Agreement dated as of March 28, 2003, and of the obligations
under Reliant Resources' senior secured notes issued in July 2003. All of the
Company's subsidiaries, except for RE Retail Receivables, LLC also guarantee
Reliant Resources' obligations under Amended and Restated Credit and Guaranty
Agreement and its senior secured notes. The Company's maximum potential amount
of future payments under the guarantee is approximately $1.1 billion. Reliant
Resources' obligations mature at various dates from 2010 through 2013.

Both Reliant Resources' March 2003 credit facility and its senior secured
notes restrict the Company's ability to take specific actions, subject to
numerous exceptions that are designed to allow for the execution of Reliant
Resources' and its subsidiaries' business plans in the ordinary course,
including the preservation and optimization of existing investments and the
ability to provide credit support for commercial obligations.

(c) OTHER COMMITMENTS.

Purchase Power and Electric Capacity Commitments. The Company is a party
to several purchase power and electricity capacity contracts, that have various
quantity requirements and durations that are not classified as derivatives
assets and liabilities and hence are not included in the consolidated balance
sheets as of December 31, 2003. Minimum purchase commitment obligations under
these agreements are $609 million, $258 million and $61 million in 2004, 2005
and 2006, respectively. As of December 31, 2003, there are no such commitments
after 2006.

The Company's aggregate minimum electric capacity commitments, including
capacity auction products, are for 19,359 MW, 9,240 MW and 2,400 MW for 2004,
2005 and 2006, respectively. Included in the above purchase power and electric
capacity commitments are amounts acquired from Texas Genco. For additional
discussion of this commitment, see note 4.

As of December 31, 2003, the maximum duration under any individual
purchased power and electric capacity contract is 3 years, with the exception of
the contract to purchase wind power, which is 15 years, which is not a firm
commitment to purchase power.

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RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Sale Commitments. As of December 31, 2003, the Company has sale
commitments, including electric energy and capacity sale contracts, which are
not classified as trading and as derivative assets and liabilities and hence are
not included in the consolidated balance sheets. At execution, the estimated
minimum sale commitments under these contracts were $1.8 billion, $610 million,
$120 million and $5 million in 2004, 2005, 2006 and 2007, respectively. As of
December 31, 2003, there are no such commitments after 2007.

In addition, in January 2002, the Company began providing retail electric
services to approximately 1.7 million residential and small commercial customers
previously served by CenterPoint's electric utility division. In the Houston
area, the Texas electric restructuring law required the Company, as a former
affiliate of the transmission and distribution utility in Houston, to sell
electricity to residential or small commercial customers only at a specified
price, or "price-to-beat" until the earlier of January 1, 2005, or the date that
40% or more of the electric power consumed by the applicable customer class is
served by other retail electric providers. In January 2004, the PUCT made such a
determination for small commercial customers and the Company is now permitted to
sell electricity at unregulated prices both outside and in the Houston area for
these customers. The Company does not expect to meet the 40% test for its
residential customers in the Houston area. The price-to-beat was the only price
that could be offered by the Company to residential and small commercial
customers in the Houston area throughout 2003. The Texas electric restructuring
law requires the Company to continue to make electricity available for its small
commercial customers in the Houston area at the price-to-beat until January 1,
2007. The PUCT's regulations allow the Company to adjust its price-to-beat fuel
factor based on a percentage change in the price of natural gas. In addition,
the Company may also request an adjustment as a result of changes in the price
of purchased energy. The Company can request up to two adjustments to its
price-to-beat in each year. During 2002 and 2003, the Company requested and the
PUCT approved two such adjustments in each year.

For information regarding commitments to CenterPoint and commitments to
affiliates, see note 3.

Other Commitments. In addition to items discussed in the consolidated
financial statements, the Company's other contractual commitments have various
quantity requirements and durations and are not considered material either
individually or in the aggregate to the results of operations or cash flows.

(11) CONTINGENCIES

(A) LEGAL MATTERS.

Regulatory Investigations. In connection with the PUCT's industry-wide
investigation into potential manipulation of the ERCOT market, Reliant Energy
Services provided information to the PUCT concerning its scheduling and trading
practices on and after July 31, 2001. Reliant Energy Services reached a
settlement relating to scheduling issues. The PUCT approved the settlement in
November 2002. The costs of the settlement, $3 million, were transferred from
Reliant Energy Services to the Company in December 2002.

Texas Commercial Energy. In July 2003, Texas Commercial Energy, LLP filed
a lawsuit against the Company 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 committed violations of state and federal antitrust laws,
fraud, negligent misrepresentation, breach of fiduciary duty, breach of contract
and civil conspiracy. The lawsuit seeks damages in excess of $535 million,
exemplary damages, treble damages, interest, costs of suit and attorneys' fees.
In November 2003, two other retail electric providers in the ERCOT market
requested to intervene in this action as plaintiffs making factual allegations
similar to those made by Texas Commercial Energy, LLP and seeking the same kinds
of relief, although not specifying the amount of damages they

F-145

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

seek. The intervention motion and the motions to dismiss Texas Commercial
Energy, LLP's complaint are set for hearing in May 2004.

PUCT Cases. Since 2002, the PUCT has approved various increases to the
fuel factor component contained in our "price-to-beat." Parties opposing the
increases have filed for judicial review of the PUCT's orders in state district
court in Travis County, Texas. To date, the court has affirmed the first PUCT
ruling. While the other rulings are pending at the district court, the parties
opposing the increases, have appealed the district court's decision. In each of
these proceedings we are vigorously contesting the appeal.

Other Matters. The Company is involved in other legal proceedings before
various courts and governmental agencies regarding matters arising in the
ordinary course of business, some of which involve substantial amounts. Although
the Company cannot predict the outcome of these proceedings, the Company
believes that the effects on the financial statements, if any, from the
disposition of these matters will not have a material adverse effect on the
results of operations, financial condition or cash flows.

(12) RECEIVABLES FACILITY

In July 2002, the Company entered into a receivables facility arrangement
with a financial institution to sell an undivided interest in the Company's
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 the accounts receivable from the Company's large
commercial, industrial and institutional customers and to increase the facility
to a maximum total of $350 million. The sale of accounts receivable is reflected
as a decrease in accounts and notes receivable, principally customers, and
unbilled revenues, net and an increase in notes receivable related to
receivables facility on the consolidated balance sheets. Pursuant to the
receivables facility, the Company formed a QSPE as a bankruptcy remote
subsidiary. The QSPE was formed for the sole purpose of buying receivables
generated by the Company 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. The Company,
irrevocably and without recourse, transfers receivables to the QSPE. The QSPE,
in turn, sells an undivided interest in these receivables to the participating
financial institutions. The Company is not ultimately liable for any failure of
payment of the obligors on the receivables. Reliant Resources has, however,
guaranteed the performance obligations of the sellers and the servicing of the
receivables under the related documents.

The amount of accounts receivable included under the arrangement may
increase as certain accounts receivable become eligible, particularly from some
of the 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 above is accounted for as a sale of
receivables, which is recorded after the first step, and as a result the related
receivables are excluded from the consolidated balance sheets. The Company
continues to service the receivables and receive a fee of 0.5% of cash
collected. The net costs associated with the sale of receivables since the
inception of the facility are $8 million.

F-146

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table details the outstanding receivables that have been sold
and the corresponding notes receivable from the QSPE, which have been reflected
in the Company's consolidated balance sheets:

The failure of the obligors to make payment on the receivables could result
in the Company's notes receivable from the QSPE not being fully realized. Texas
Genco holds a senior lien on these notes receivable, while Reliant Resources'
senior secured note holders and the banks under Reliant Resources' March 2003
credit facilities ratably hold a junior lien. See note 4 for further discussion.

The amount of funding available 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 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 for 2002 and 2003, an average discount
rate of 5.40% and 8.40%, respectively, was applied to projected cash collections
over a 6-month period. The Company's 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.

(13) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of financial instruments, including cash and cash
equivalents, short-term and long-term borrowings, and trading and derivative
assets and liabilities, are equivalent to their carrying amounts in the
consolidated balance sheets. The fair values of trading and derivative assets
and liabilities as of December 31, 2002 and 2003 have been determined using
quoted market prices for the same or similar instruments when available or other
estimation techniques. See note 6.

* * *

F-147

INDEX TO FINANCIAL STATEMENTS

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

Independent Auditors' Report................................ F-149
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-150
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-151
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-152
Consolidated Statements of Shareholder's Equity and
Comprehensive Income (Loss) for the Years Ended December
31, 2001, 2002 and 2003................................... F-153
Notes to Consolidated Financial Statements.................. F-154

F-148

INDEPENDENT AUDITORS' REPORT

To Reliant Energy Mid-Atlantic Power Holdings, LLC
Houston, Texas

We have audited the accompanying consolidated balance sheets of Reliant
Energy Mid-Atlantic Power Holdings, LLC and subsidiaries (the "Company") as of
December 31, 2002 and 2003, and the related consolidated statements of
operations, shareholder's equity and comprehensive income (loss), and cash flows
for each of the three years in the period ended December 31, 2003. These
financial statements are the responsibility of the Company's management. Our
responsibility is to express an opinion on the financial statements based on our
audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company as of December 31,
2002 and 2003, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003, in conformity with
accounting principles generally accepted in the United States of America.

As discussed in notes 2 and 4 to the consolidated financial statements, the
Company changed its accounting for asset retirement obligations and its
presentation of revenues and cost of sales associated with non-trading commodity
derivative activities in 2003; goodwill and other intangibles in 2002; and
derivative contracts and hedging activities in 2001.

DELOITTE & TOUCHE LLP

Houston, Texas
March 5, 2004

F-149

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See Notes to the Consolidated Financial Statements
F-150

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to the Consolidated Financial Statements
F-151

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to the Consolidated Financial Statements
F-152

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF
SHAREHOLDER'S EQUITY AND COMPREHENSIVE INCOME (LOSS)

See Notes to the Consolidated Financial Statements
F-153

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND

Reliant Energy Mid-Atlantic Power Holdings, LLC and subsidiaries (REMA), is
an indirect wholly owned subsidiary of Reliant Energy Power Generation, Inc.
(REPG). REPG is a wholly owned subsidiary of Reliant Resources, Inc. (Reliant
Resources).

As of December 31, 2003, REMA owned or leased interests in 20 operating
electric generation plants in Pennsylvania, New Jersey and Maryland with an
annual average net generating capacity of approximately 3,798 megawatts (MW).
See note 12.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) RECLASSIFICATIONS.

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

(b) USE OF ESTIMATES AND MARKET RISK AND UNCERTAINTIES.

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. REMA's critical accounting estimates include: (a) property, plant and
equipment, (b) depreciation expense, (c) derivative activities, (d)
contingencies and (e) deferred tax asset valuation allowances and tax
liabilities.

REMA is subject to risks associated with price movements of energy
commodities and the credit risk associated with its commercial activities. For
additional information regarding these risks, see notes 2(d) and 5. REMA is
subject to risks relating to the reliability of the systems, procedures and
other infrastructure necessary to operate its business. REMA is also subject to
risks relating to changes in laws and regulations; the effects of competition;
liquidity concerns in the markets in which REMA operates; the availability of
adequate supplies of fuel and transportation; weather conditions; financial
market conditions and REMA's access to capital; the creditworthiness or
financial distress of REMA's counterparties; actions by rating agencies with
respect to REMA or its competitors; political, legal, regulatory and economic
conditions and developments; the successful operation of deregulating power
markets and other items.

(c) PRINCIPLES OF CONSOLIDATION.

REMA's accounts and those of its wholly-owned subsidiaries are included in
the consolidated financial statements. All significant intercompany transactions
and balances are eliminated in consolidation.

In 2000, REMA entered into separate sale-leaseback transactions with each
of three owner-lessors for its respective interests in three power generation
stations (see note 9(a)). REMA does not consolidate these generating facilities.

In January 2003, the Financial Accounting Standards Board (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, receives a majority of the
entity's expected residual returns, or both. FIN No. 46 requires entities to
either (a) record the effects
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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.

REMA adopted FIN No. 46 on January 1, 2003. FIN No. 46 did not have any
impact on REMA's consolidated financial statements. In December 2003, the FASB
released FASB Interpretation No. 46 (revised December 2003) "Consolidation of
Variable Interest Entities, an Interpretation of ARB No. 51" (FIN No. 46R),
which replaces FIN No. 46 and modified certain criteria in determining which
entities should be considered as variable interest entities. REMA does not
believe the application of FIN No. 46R will have a material impact to its
consolidated financial statements. The application of FIN No. 46R continues to
evolve as the FASB continues to address issues submitted for consideration. REMA
will continue to assess its application of clarified or revised guidance related
to FIN No. 46R.

(d) REVENUES AND ACCOUNTING FOR HEDGING ACTIVITIES.

Power Generation Revenues. Revenues include energy, capacity and ancillary
service sales. REMA records gross revenues under the accrual method and these
revenues generally are recognized upon delivery. REMA's electric power and
services are sold at market-based prices through a related party and indirect
subsidiary of Reliant Resources, Reliant Energy Services, Inc. (Reliant Energy
Services). Reliant Energy Services acts as agent on behalf of REMA on most
market-based sales. REMA's capacity was also sold pursuant to a transition power
purchase agreement with GPU, Inc.. The transition power purchase agreement
expired on May 31, 2002. Sales not billed by month-end are accrued based upon
estimated energy or services delivered. See below for the discussion of the
impact of implementation of Emerging Issues Task Force (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).

Hedging Activities. Effective January 1, 2001, REMA adopted Statement of
Financial Accounting Standards (SFAS) No. 133, "Accounting for Derivative
Instruments and Hedging Activities," as amended (SFAS No. 133), which
establishes accounting and reporting standards for derivative instruments.
Adoption of SFAS No. 133 on January 1, 2001 resulted in no after-tax increase in
net income and a cumulative after-tax increase in accumulated other
comprehensive loss of $73.6 million. During 2001, $70.4 million of the initial
after-tax transition adjustment recorded in accumulated other comprehensive loss
was recognized in net loss.

If certain conditions are met, REMA may designate a derivative instrument
as hedging (a) the exposure to variability in expected future cash flows (cash
flow hedge), (b) the exposure to changes in the fair value of an asset or
liability (fair value 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. Derivative commodity contracts for the physical delivery of purchase
and sale quantities transacted in the normal course of business are designated
as normal purchases and sales exceptions and are not reflected in REMA's
consolidated balance sheets at fair value. 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.

REMA designates its derivatives utilized in non-trading activities as cash
flow hedges only if there is a high correlation between price movements in the
derivative and the item designated as being hedged. This correlation is measured
both at the inception of the hedge and on an ongoing basis, with an acceptable
level of correlation of at least 80% to 125% for hedge designation. The gains
and losses related to derivative instruments designated as cash flow hedges are
deferred in accumulated other comprehensive
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income (loss), net of tax, to the extent the contracts are effective as hedges,
and then are recognized in REMA's results of operations in the same period as
the settlement of the underlying hedged transactions. Once the anticipated
transaction occurs, the accumulated deferred gain or loss recognized in
accumulated other comprehensive income (loss) is reclassified and included in
our consolidated statements of operations (a) prior to October 1, 2003, under
the captions (i) fuel and purchased power, in the case of hedging activities
related to physical and financial natural gas transactions and (ii) revenues, in
the case of hedging activities related to physical and financial power
transactions and (b) effective October 1, 2003, under the captions (i) fuel and
purchased power, in the case of hedging activities related to physical natural
gas purchase transactions, physical natural gas sales transactions that do not
physically flow, financial natural gas transactions and physical power purchase
transactions that physically flow, and (ii) revenues, in the case of hedging
activities related to financial power transactions, physical power sales
transactions, physical power purchase transactions that do not physically flow
and natural gas sales transactions that physically flow.

For a derivative not designated as a hedge, changes in fair value are
recorded as unrealized gains or losses in REMA's results of operations. If and
when correlation ceases to exist at an acceptable level, hedge accounting ceases
and changes in fair value are recognized currently in REMA's results of
operations. If it becomes probable that a forecasted transaction will not occur,
REMA immediately recognizes the respective deferred gains or losses in its
results of operations. The associated hedging instrument is then marked to
market through REMA's results of operations for the remainder of the contract
term unless a new hedging relationship is redesignated.

In July 2003, the EITF issued EITF No. 03-11, which stated 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. Reclassification of prior year amounts is not required. On
October 1, 2003, REMA began reporting prospectively the settlement of sales and
purchases of fuel and power related to its hedging activities that were
physically delivered on a gross basis in REMA's consolidated statement of
operations. Prior to October 1, 2003 the settlement of sales and purchases of
fuel and power related to REMA's hedging activities were reported on a net basis
in REMA's consolidated statement of operations based on the item hedged. The
application of EITF No. 03-11 did not result in a material impact on revenues
and fuel and purchased power in REMA's consolidated statement of operations and
is not expected to have a material impact on the presentation of future
operations. EITF No. 03-11 has no impact on margins or net income. Comparative
financial statements for prior periods have not been reclassified to conform to
this presentation, as it is not required. In addition, it is not practicable to
determine sales and purchases of fuel and purchased power in 2001, 2002 and the
nine months ended September 30, 2003 that would have been shown net if EITF No.
03-11 had been applied to the results of operations historically.

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. 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 REMA's consolidated financial statements.

For additional discussion of derivative and hedging activities, see note 5.

Set-off of Derivative Assets and Liabilities. Where derivative instruments
are subject to a master netting agreement and the criteria of FASB
Interpretation No. 39, "Offsetting of Amounts Related to
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Certain Contracts," are met, REMA presents its derivative assets and liabilities
on a net basis in the consolidated balance sheets. Derivative assets/liabilities
and accounts receivable/payable are presented separately in the consolidated
balance sheets. The derivative assets/liabilities and accounts
receivable/payable are set-off separately in the consolidated balance sheets
although in certain cases contracts permit the set-off derivative
assets/liabilities and accounts receivable/payable with a given counterparty.

(e) GENERAL AND ADMINISTRATIVE EXPENSE.

The general and administrative expenses from affiliates include an
allocation of corporate and administrative services, insurance and utility costs
(including management services, financial and accounting, cash management and
treasury support, legal, information technology system support, office
management and human resources) under REMA's support services agreement with
REPG (see note 3(b)).

(f) PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION EXPENSE.

REMA records property, plant and equipment at historical cost. REMA
expenses all repair and maintenance costs as incurred, including planned major
maintenance. Depreciation is computed using the straight-line method based on
estimated useful lives. Property, plant and equipment includes the following:

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

(1) Building and building improvements include the carrying value of the
Johnstown office building which was written down by $6.5 million in 2003 to
its fair value less costs to sell and is no longer being depreciated. See
note 11.

REMA periodically evaluates property, plant and equipment for impairment
when events or changes in circumstances indicate that the carrying value of
these assets may not be recoverable. The determination of whether an impairment
has occurred is based on an estimate of undiscounted cash flows attributable to
the assets, as compared to the carrying value of the assets. A resulting
impairment loss is highly dependent on the underlying assumptions. During 2002,
REMA recognized $15.0 million in depreciation expense for the early retirement
of power generation units at its Warren facility. During 2003, REMA recorded the
following charges in depreciation expense: $9.6 million for the early retirement
of power generation units at its Sayreville facility and $6.5 million related to
the write-down of an office building to its fair value less costs to sell (see
note 11). As of December 31, 2003, REMA performed impairment analyses of certain
of its property, plant and equipment. In addition, as of November 1, 2002 and
July 1, 2003, REMA performed impairment analyses of all of its property, plant
and equipment as it believed events had indicated that these assets may not be
recoverable. Based on these analyses, REMA recorded no impairments.
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If REMA's wholesale energy market outlook changes negatively, REMA could
have impairments of property, plant and equipment in future periods. In
addition, Reliant Resources' ongoing evaluation of its wholesale energy business
could result in decisions to mothball, retire or dispose of additional
generation assets, any of which could result in impairment charges. See note 12.

(g) GOODWILL AND AMORTIZATION EXPENSE.

REMA records goodwill for the excess of the purchase price over the fair
value assigned to the net assets of an acquisition. Through 2001, REMA amortized
goodwill on a straight-line basis over 35 years. Pursuant to REMA's adoption of
SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142) on January
1, 2002, REMA discontinued amortizing goodwill. See note 4 for a discussion
regarding REMA's adoption of SFAS No. 142. Goodwill amortization expense was
$0.1 million for 2001. Amortization expense was for other intangibles $14.1
million, $14.8 million, and $28.6 million for 2001, 2002 and 2003, respectively.
See also note 4.

REMA periodically evaluates goodwill and other intangibles when events or
changes in circumstances indicate that the carrying value of these assets may
not be recoverable. In 2001, the determination of whether an impairment had
occurred was based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. Effective January 1,
2002, goodwill and other intangibles are evaluated for impairment in accordance
with SFAS No. 142. To date, no impairment has been indicated. For further
discussion of goodwill and other intangible impairment analyses in 2002 and
2003, see note 4.

(h) INCOME TAXES.

REMA uses the asset and liability method of accounting for deferred income
taxes and measures deferred income taxes for all significant income tax
temporary differences. For additional information regarding income taxes, see
note 8.

From the date of REMA's acquisition by Reliant Resources through September
30, 2002, REMA was included in the consolidated income tax return of CenterPoint
Energy, Inc. (CenterPoint Energy), formerly the majority owner of Reliant
Resources. As of October 1, 2002, REMA is included in the consolidated tax
returns of Reliant Resources and calculates its income tax provision on a
separate return basis, whereby Reliant Resources pays all federal income taxes
on REMA's behalf and is entitled to any related tax savings. The difference
between REMA's current federal income tax expense or benefit, as calculated on a
separate return basis, and related amounts paid or received to/from Reliant
Resources, if any, is recorded as adjustments to additional paid-in capital on
REMA's consolidated balance sheets.

(i) CASH.

REMA records as cash and cash equivalents all highly liquid short-term
investments with original maturities or remaining maturities at the date of
purchase of three months or less.

(j) RESTRICTED CASH.

Restricted cash currently represents cash collateral posted to support
REMA's lease obligations under its sale-leaseback transactions. See note 9(a).
As of December 31, 2002 and 2003, REMA's current and long-term restricted cash
totaled $0 and $42.3 million, respectively.

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(k) INVENTORIES.

Inventories consist of materials and supplies, including spare parts, coal,
natural gas and heating oil. All inventory is valued at the lower of average
cost or market.

(l) ENVIRONMENTAL COSTS.

REMA expenses or capitalizes environmental expenditures, as appropriate,
depending on their future economic benefit. REMA expenses amounts that relate to
an existing condition caused by past operations and that do not have future
economic benefit. REMA records liabilities related to expected future costs
related to environmental assessments and/or remediation activities when they are
probable and the costs can be reasonably estimated. See note 10(a) for further
discussion.

(m) ASSET RETIREMENT OBLIGATIONS.

On January 1, 2003, REMA adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). 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. Prior to the adoption of SFAS No. 143, REMA recorded asset
retirement obligations in connection with certain business combinations. These
obligations were recorded at their present values on the dates of acquisition.
REMA's asset retirement obligations are primarily environmental obligations
related to ash disposal site closures.

The impact of the adoption of SFAS No. 143 resulted in a gain of $2.3
million, net of tax of $1.6 million, as a cumulative effect of an accounting
change in REMA's consolidated statement of operations for 2003. The impact of
the adoption of SFAS No. 143 resulted in a January 1, 2003 cumulative effect of
an accounting change to record (a) a $1.0 million increase in the carrying
values of property, plant and equipment, (b) a $0.2 million increase in
accumulated depreciation of property, plant and equipment, (c) a $3.1 million
decrease in asset retirement obligations and (d) a $1.6 million increase in
deferred income tax liabilities.

If REMA had adopted SFAS No. 143 on January 1, 2001, the impact would have
been immaterial to its consolidated income from continuing operations and net
income (loss) for both 2001 and 2002.

The following table presents the detail of REMA's asset retirement
obligations, which are included in other long-term liabilities in its
consolidated balance sheet (in millions):

Balance at January 1, 2003.................................. $ 3.9
Accretion expense........................................... 0.2
Liabilities incurred........................................ 0.1
Payments.................................................... (3.9)
-----
Balance at December 31, 2003................................ $ 0.3
=====

(n) DEFERRED LEASE COSTS.

REMA incurred costs in connection with its sale-leaseback transactions in
2000 (see note 9(a)). These costs are deferred and amortized, using the
straight-line method, over the life of the individual sale-leaseback
transactions. REMA amortized $0.8 million to facilities lease expense in each of
the years ended December 31, 2001, 2002 and 2003. As of December 31, 2002 and
2003, REMA had $22.9 million and

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$22.1 million, respectively, of net deferred lease costs classified in other
long-term assets in its consolidated balance sheets.

(o) DISCLOSURES ABOUT PENSIONS AND OTHER POSTRETIREMENT BENEFITS.

In December 2003, the FASB issued a revision to SFAS No. 132, "Employers'
Disclosures About Pensions and Other Postretirement Benefits -- An Amendment of
FASB Statements No. 87, 88 and 106" (SFAS No. 132 (Revised 2003)). This
statement revises employers' disclosures about pension plans and other
postretirement benefit plans. This statement retains the disclosure requirements
contained in SFAS No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits" (SFAS No. 132), which it replaces. It requires
additional disclosures to those in the original SFAS No. 132 about the assets,
obligations, cash flows and net periodic benefit cost of defined benefit pension
plans and other defined benefit postretirement plans. REMA has adopted these
additional disclosures. See note 7.

(p) NEW ACCOUNTING PRONOUNCEMENTS.

As of February 20, 2004, no standard setting body or authoritative body has
established new accounting pronouncements or changes to existing accounting
pronouncements that would have a material impact to REMA's results of
operations, financial position or cash flows, for which REMA has not already
adopted and/or disclosed elsewhere in these notes.

(3) RELATED PARTY TRANSACTIONS

(A) PROCUREMENT AND MARKETING AGREEMENT

REMA is a party to a procurement and marketing agreement with Reliant
Energy Services under which Reliant Energy Services is entitled to procurement
and power marketing fees. Under the agreement, Reliant Energy Services

- enters into derivative transactions on behalf of REMA to hedge commodity
risks;

- procures coal, fuel oil and emissions allowances on REMA's behalf at a
pass through price;

- procures gas on REMA's behalf at a pass through price or for an index
price plus costs of delivery, depending on when and how the gas is
procured; and

- markets power and surplus gas, fuel oil and emissions allowances on
REMA's behalf.

The amount charged to REMA by Reliant Energy Services for these services
was $4.6 million, $4.4 million and $4.7 million during 2001, 2002 and 2003,
respectively. These amounts are classified in operation and maintenance expense
in the consolidated statements of operations.

Fees charged under the procurement and marketing agreement are subordinated
to certain payments pursuant to the sale-leaseback financing documents,
including lease payments.

(b) SUPPORT SERVICES AGREEMENT

REMA is a party to a support services agreement with REPG under which REPG
will, on an as-requested basis and at cost, provide or procure from other
affiliates or third parties services in support of REMA's business in areas such
as human resources, accounting, finance, treasury, tax, office administration,
information technology, engineering, construction management, environmental,
legal and safety. REPG has agreed to provide these services only to the extent
it or its affiliates provide these services for it or its subsidiaries'
generating assets. REPG charges and allocates costs to REMA for these
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services. Amounts charged and allocated to REMA for these services were $70.3
million, $79.3 million and $92.2 million during 2001, 2002, and 2003,
respectively. On January 1, 2003, REPG refined the methodology it used to
allocate costs to REMA. The current method being used by REPG to allocate
support service costs to REMA is based on REMA's direct labor costs relative to
the direct labor costs of the other entities to which REPG provides similar
services versus the prior method that was based on REMA's gross margin relative
to the gross margin of the other entities to which REPG provides similar
services. As a result of the change in allocation methodology, REMA has been
allocated a higher percentage of costs than would have been allocated under the
previous methodology. All of the allocations in the consolidated financial
statements have been and continue to be 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 REMA had operated as a separate entity. These amounts are classified in
general and administrative expense from affiliates in the consolidated
statements of operations.

Costs charged under the support services agreement are subordinated to
certain payments pursuant to the sale-leaseback financing documents, including
lease payments.

(c) SUBORDINATED LONG-TERM NOTES TO AFFILIATED ENTITY

REMA has notes payable to Reliant Energy Northeast Holdings Inc. (RENH), a
wholly-owned subsidiary of REPG. The notes are due January 1, 2029 and accrue
interest at a fixed rate of 9.4% per annum. As of December 31, 2002 and 2003,
REMA had $683.6 million and $618.7 million, respectively, outstanding under the
notes. Payments under this indebtedness are subordinated to REMA's lease
obligations.

In July 2001, REMA borrowed an additional $106.0 million from RENH. The
borrowing would have matured on July 1, 2029, bore interest at a fixed rate of
9.4% and was unsecured. Repayment of the borrowing was subordinated to REMA's
lease obligations as required by the lease documents. At December 31, 2002, $2.0
million of borrowings were outstanding under this note. The note was paid in
full by REMA in March 2003.

(d) WORKING CAPITAL NOTE

REMA has a revolving note payable to RENH under which REMA may borrow, and
RENH is committed to lend, up to $30 million for working capital needs.
Borrowings under the note will be unsecured and will rank equal in priority with
REMA's lease obligations. REMA may replace this note with a working capital
facility from an unaffiliated lender. Borrowings under the working capital note
bear interest based on the London Inter-Bank Offered Rate (LIBOR). This note
expires in May 2004. RENH plans to renew the working capital note prior to its
expiration. At December 31, 2002 and 2003, there were no borrowings outstanding
under this note.

(e) SUBORDINATED WORKING CAPITAL FACILITY

REMA entered into an irrevocably committed subordinated working capital
facility with RENH. RENH will fund REMA's drawings under this facility through
borrowings or equity contributions irrevocably committed to RENH by Reliant
Resources. REMA may borrow under this facility to pay operating expenditures,
senior indebtedness and rent, but excluding capital expenditures and
subordinated indebtedness. In addition, RENH must make advances to REMA and REMA
must obtain such advances under such facility up to the maximum available
commitment under such facility from time to time if REMA's pro forma coverage
ratio does not equal or exceed 1.1 to 1.0, measured at the time rent under the
leases is due. Subject to the maximum available commitment, drawings will be
made in amounts
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

necessary to permit REMA to achieve a pro forma coverage ratio of at least 1.1
to 1.0. The amount available under the subordinated working capital facility is
$120.0 million through January 1, 2007. Thereafter, the available amount
decreases by $24.0 million on January 2, 2007 and by $24.0 million each
subsequent year through its expiration in 2011. At December 31, 2002 and 2003,
there were no borrowings outstanding under this facility.

(4) 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. REMA
adopted the provisions of the statement effective January 1, 2002, and
discontinued amortizing goodwill into its results of operations. A
reconciliation of 2001 reported net loss adjusted for the exclusion of goodwill
amortization with a comparison of 2002 and 2003 follows:

Intangibles. Other intangible assets consist of the following:

REMA recognizes specifically identifiable intangibles, including air
emissions regulatory allowances, power generation site permits, and water rights
when acquired. REMA has no intangible assets with indefinite lives recorded as
of December 31, 2002 and 2003. REMA amortizes air emission regulatory allowances
primarily on a units-of-production basis as utilized. REMA amortizes power
generation site permits and water rights on a straight-line basis over their
estimated useful lives. All intangibles, excluding goodwill, are subject to
amortization.

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Estimated amortization expense for the next five years is as follows (in
millions):

2004........................................................ $15.3
2005........................................................ 5.9
2006........................................................ 4.9
2007........................................................ 4.9
2008........................................................ 4.8
-----
Total..................................................... $35.8
=====

During 2003, REMA sold certain power generation site permits and water
rights to an affiliate for $19.2 million in cash. The permits and water rights
were no longer needed for REMA's business. There was no gain or loss recorded on
the sale. See note 12.

Goodwill. The following table shows the changes in the carrying amount of
goodwill for 2002 and 2003 (in millions):

As of January 1, 2002....................................... $ 4.6
Purchase adjustments(1)................................... 2.2
As of December 31, 2002..................................... 6.8
Other(2).................................................. (2.9)
-----
As of December 31, 2003..................................... $ 3.9
=====

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

(1) In connection with the acquisition of REMA in 2000, REPG made an $8.2
million payment to the prior owner in the first quarter of 2002 for
post-closing adjustments that resulted in a $2.2 million adjustment to
REMA's goodwill.

(2) In connection with the acquisition of REMA in 2000, REMA recorded certain
environmental liabilities associated primarily with ash disposal site
closures and site contaminations (see note 10(a)). Upon further review in
2003, management determined that $2.9 million of the recorded environmental
liabilities do not represent liabilities. As a result, goodwill was reduced
by $2.9 million to reflect the reversal of these liabilities.

REMA has no goodwill that is deductible for United States income tax
purposes.

During the second quarter of 2002, REMA completed the transitional
impairment test as of January 1, 2002 for the adoption of SFAS No. 142 on its
consolidated financial statements. This transitional impairment test resulted in
no goodwill impairment at REMA.

SFAS No. 142 requires goodwill to be tested at least annually and more
frequently in certain circumstances. The date of REMA's annual impairment test
was November 1 for 2002 and 2003. In addition to the annual impairment tests,
REMA tested its goodwill as of July 1, 2003 as a result of Reliant Resources'
sale of the Desert Basin power generation plant, which required Reliant
Resources 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 Reliant Resources to test the recoverability of goodwill in
the remaining wholesale energy reporting unit as of July 2003. As a result of
Reliant Resources' impairment analysis of its wholesale energy reporting unit,
REMA tested the recoverability of its goodwill. Based on the July 1, 2003 test
and the annual impairment tests, there was no impairment of goodwill during 2002
and 2003.

Potential Future Impairments of Goodwill. If REMA's wholesale energy
market outlook changes negatively, REMA could have impairments of goodwill. In
addition, Reliant Resources' ongoing evaluation of its business could result in
decisions to mothball, retire or dispose of additional generation assets, any of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

which could result in impairment charges related to goodwill, impact REMA's
fixed assets' depreciable lives or result in fixed asset impairment charges. See
note 12.

(5) DERIVATIVE INSTRUMENTS

REMA is exposed to various market risks. These risks arise from the
ownership of assets and operation of the business. REMA routinely utilizes
derivative instruments such as futures, physical forward contracts, swaps and
options to mitigate the impact of changes in electricity, natural gas and fuel
prices on its operating results and cash flows.

Reliant Resources has a risk control framework, which REMA is subject to,
designed to monitor, measure and define appropriate transactions to hedge and
manage the risk in its existing portfolio of assets and contracts and to
authorize new transactions. These risks fall into three different categories:
market risk, credit risk and operational risk. REMA believes that it has
effective procedures for evaluating and managing these risks to which it is
exposed. Key risk control activities include definition of appropriate
transactions for hedging, credit review and approval, credit and performance
risk measurement and monitoring, validation of transactions, portfolio valuation
and daily portfolio reporting including mark-to-market valuation, value-at-risk
and other risk measurement metrics. REMA seeks to monitor and control its risk
exposures through a variety of separate but complementary processes and
committees, which involve business unit management, senior management and
Reliant Resources' board of directors.

The primary types of derivatives REMA uses are described below:

- Futures contracts are exchange-traded standardized commitments to
purchase or sell an energy commodity or financial instrument, or to make
a cash settlement, at a specific price and future date.

- Physical forward contracts are commitments to purchase or sell energy
commodities in the future.

- Swap agreements require payments to or from counterparties based upon the
differential between a fixed price and variable index price (fixed price
swap) or two variable index prices (variable price swap) for a
predetermined contractual notional amount. The respective index may be an
exchange quotation or an industry pricing publication.

- Option contracts convey the right to buy or sell an energy commodity or a
financial instrument at a predetermined price or settlement of the
differential between a fixed price and a variable index price or two
variable index prices.

To reduce the risk from market fluctuations in its results of operations
and the resulting cash flows, REMA may enter into energy derivatives in order to
hedge some expected natural gas and other commodities and sales of electric
power. The derivative portfolios are managed to complement REMA's asset
portfolio, reducing overall risks.

The fair values of REMA's derivative activities as of December 31, 2002 and
2003, are determined by (a) prices actively quoted, (b) prices provided by other
external sources or (c) prices based on models and other valuation methods.

F-164

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Below is the pre-tax income (loss) of REMA's derivative instruments, both
from cash flow hedge ineffectiveness and from derivative mark-to-market income
and losses, for 2001, 2002 and 2003:

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

(1) For 2001, 2002 and 2003, no component of the derivative instruments' gain or
loss was excluded from the assessment of effectiveness.

(2) There were no amounts recognized in 2001, 2002 and 2003 in REMA's results of
operations as a result of the discontinuance of cash flow hedges because it
was probable that the forecasted transaction would not occur.

Below is a reconciliation of REMA's net derivative assets (liabilities) to
accumulated other comprehensive income (loss), net of tax, as of December 31,
2002 and 2003:

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

(1) As of December 31, 2003, REMA expects $4.1 million of accumulated other
comprehensive loss to be reclassified into its results of operations during
2004.

As of December 31, 2002 and 2003, the maximum length of time REMA is
hedging its exposure to the variability in future cash flows for forecasted
transactions, excluding the payment of variable interest on existing financial
instruments, is ten years and nine years, respectively.

Other Derivative Activities. During 2001, Reliant Resources contributed
derivative assets and liabilities to REMA as a result of four structured
transactions involving a series of forward contracts to buy and sell an energy
commodity in 2001 and to buy and sell an energy commodity in 2002. The change in
fair value of these derivative assets and liabilities was recorded in the
statement of consolidated operations for each reporting period. During 2001 and
2002, $54 million of net derivative liabilities and $248 million of net
derivative assets, respectively, were settled related to these transactions,
which was recorded in cash flows from operations; $8 million and $8 million,
respectively, of pre-tax unrealized gains were recognized.

CREDIT RISK.

Credit risk is inherent in REMA's commercial activities and relates to the
risk of loss resulting from non-performance of contractual obligations by a
counterparty. Reliant Resources has broad credit policies and parameters, which
REMA is subject to.

F-165

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Reliant Energy Services enters into hedging and other transactions on
behalf of REMA under its procurement and marketing agreement (see note 3(a)).
Although Reliant Energy Services is the party to the contract, REMA maintains
counterparty credit risk associated with the hedging and other transactions.

Reliant Energy Services seeks to enter into contracts on behalf of REMA
that permit it to net receivables and payables with a given counterparty.
Reliant Energy Services also enters into contracts that enable it to obtain
collateral from a counterparty as well as to terminate upon the occurrence of
certain events of default. The credit risk control organization establishes
counterparty credit limits. Reliant Resources employs tiered levels of approval
authority for counterparty credit limits, with authority increasing from the
credit risk control organization through senior management. Credit risk exposure
is monitored daily and the financial condition of REMA's counterparties is
reviewed periodically.

If any of REMA's counterparties failed to perform, Reliant Energy Services
might be forced to acquire alternative hedging arrangements on behalf of REMA or
be required to replace the underlying commitment at then-current market prices.
In this event, REMA might incur additional losses in addition to amounts owed to
REMA by the counterparty. For information regarding the net provision recorded
in 2001 related to energy sales to Enron, see note 10(a).

As of December 31, 2002, one investment grade counterparty represented 15%
of REMA's total credit exposure, net of collateral. The dollar amount of REMA's
credit exposure to this counterparty was $17.0 million as of December 31, 2002.
As of December 31, 2002, there were no other counterparties representing greater
than 10% of REMA's total credit exposure, net of collateral. As of December 31,
2003, one non-investment grade counterparty represented 18% of REMA's total
credit exposure , net of collateral. The dollar amount of REMA's credit exposure
to this counterparty was $13.9 million as of December 31, 2003. As of December
31, 2003, there were no other counterparties representing greater than 10% of
REMA's total credit exposure, net of collateral.

(6) LONG-TERM DEBT

REMA is obligated to provide credit support for its lease obligations (see
note 9(a)) in the form of letters of credit and/or cash resulting from draws on
such 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 and $16.3
million in letters of credit provided by Reliant Resources in January 2004. The
draw on the letters of credit 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
and did not constitute a default under any of REMA's obligations. Interest on
the term loans is payable at the rate of LIBOR plus 3%. REMA's subsidiaries
guarantee REMA's obligations under the leases and the term loans.

(7) RETIREMENT AND OTHER BENEFIT PLANS

(A) PENSION.

During the first quarter of 2001, REMA's non-union employees participated
in CenterPoint's noncontributory cash balance pension plan. Effective March 1,
2001, REMA no longer accrues benefits under this noncontributory pension plan
for its non-union employees. Effective March 1, 2001, each non-union
participant's unvested pension account balance became fully vested. Participants
may elect to have their accrued benefits (a) left in the CenterPoint pension
plan for which CenterPoint is the plan sponsor,

F-166

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) rolled over to a savings plan or individual retirement account or (c) paid
in a lump-sum or annuity distribution.

Substantially all of REMA's union employees participate in a
noncontributory pension plan (the Union Pension Plan). The Union Pension Plan
provides retirement benefits based on years of service and final average
compensation. The funding policy is to review amounts annually in accordance
with applicable regulations in order to determine contributions necessary to
achieve adequate funding of projected benefit obligations. REMA uses a December
31 measurement date for its pension plan. REMA's pension and funded status are
as follows:

Amounts recognized in the consolidated balance sheets are as follows:

The accumulated benefit obligation for the Union Pension Plan was $9.7
million and $13.1 million at December 31, 2002 and 2003, respectively.

F-167

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net pension cost includes the following components:

The significant weighted average assumptions used to determine the pension
benefit obligation include the following:

The significant weighted average assumptions used to determine the net
pension cost include the following:

As of December 31, 2003 REMA's expected long-term rate of return on pension
plan assets is developed based on third party models. These models consider
expected inflation, current dividend yields, expected corporate earnings growth
and risk premiums based on the expected volatility of each asset category. The
expected long-term rates of return for each asset category are weighted to
determine the overall expected long-term rate of return on pension plan assets.
In addition, peer data and historical returns are reviewed.

REMA's pension plan weighted average asset allocations at December 31, 2002
and 2003 and target allocation for 2004 by asset category are as follows:

F-168

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In managing the investments associated with the pension plans, the
objective is to exceed, on a net-of-fee basis, the rate of return of a
performance benchmark composed of the following indices:

As a secondary measure, asset performance is compared to the returns of a
universe of comparable funds, where applicable, over a full market cycle.

During 2001, 2002 and 2003, REMA made cash contributions of $0.7 million,
$2.9 million and $3.2 million, respectively, to the pension plans. REMA expects
cash contributions to approximate $6.1 million during 2004.

Information for pension plans with an accumulated benefit obligation in
excess of plan assets is as follows:

(b) SAVINGS PLAN.

REMA has two employee savings plans that are tax-qualified plans under
Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and
include a cash or deferred arrangement under Section 401(k) of the Code for
substantially all its employees.

Under the plans, participating employees may contribute a portion of their
compensation, pre-tax or after-tax, generally up to a maximum of 16% of
compensation. The savings plans' matching contribution and any payroll period
discretionary employer contribution will be made in cash; any discretionary
annual employer contribution, as applicable, may be made in Reliant Resources'
common stock, cash or both.

REMA's savings plans benefit expense was $3.9 million, $3.7 million and
$4.6 million in 2001, 2002 and 2003, respectively.

(c) POSTRETIREMENT BENEFITS.

REMA provides some postretirement benefits (primarily medical care and life
insurance benefits) for its union retired employees, substantially all of whom
may become eligible for these benefits when they retire. REMA funds its union
postretirement benefits on a pay-as-you-go basis. REMA uses a December 31
measurement date.

F-169

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REMA's accumulated postretirement benefit obligation and funded status are
as follows:

Amounts recognized in the consolidated balance sheets are as follows:

Net postretirement benefit cost includes the following components:

The significant weighted average assumption used to determine the
accumulated postretirement benefit obligation includes the following:

F-170

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The significant weighted average assumption used to determine the net
postretirement benefit cost includes the following:

The following table shows REMA's assumed health care cost trend rates used
to measure the expected cost of benefits covered by REMA's postretirement plan:

Assumed health care cost trend rates have an effect on the amounts reported
for REMA's health care plans. A one-percentage-point change in assumed health
care cost trend rates would have the following effects as of December 31, 2003:

A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

F-172

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Following were REMA's tax effects of temporary differences between the
carrying amounts of assets and liabilities in the financial statements and their
respective tax bases:

During 2002, Reliant Resources made non-cash equity contributions to REMA
related to current federal income taxes payable of $45.2 million. During 2003,
REMA made non-cash equity distributions to Reliant Resources related to current
federal taxes receivable of $18.1 million (see note 2(h)).

Tax Attribute Carryovers. At December 31, 2003, REMA had approximately $52
million of state net operating loss carryforwards. The state loss carryforwards
can be carried forward to offset future income through the year 2023.

(9) COMMITMENTS

(A) LEASE COMMITMENTS.

Sales-leasebacks. In 2000, REMA entered into separate sale-leaseback
transactions with each of three owner-lessors' respective 16.45%, 16.67% and
100% interests in the Conemaugh, Keystone and Shawville generating facilities,
respectively, acquired in the REMA acquisition during 2000. As lessee, REMA
leases an interest in each facility from each owner-lessor under a facility
lease agreement. REMA expects to make lease payments through 2029 under these
leases, with total cash payments of $1.3 billion remaining as of December 31,
2003. The lease terms expire in 2026 (Shawville facility) and 2034 (Conemaugh
and Keystone facilities). The equity interests in all the subsidiaries of REMA
are pledged as collateral for REMA's lease obligations and the subsidiaries have
guaranteed the lease obligations.

F-173

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Additionally, REMA is obligated to provide credit support for its lease
obligations. See note 6 for discussion. During 2001, 2002 and 2003, REMA made
lease payments of $259.3 million, $137.8 million and $76.8 million,
respectively, to lessors related to its obligations under the sale-leaseback
transactions. Operating lease expense is recorded using the straight-line method
over the life of the individual sale-leaseback transactions. Operating lease
expense, including the amortization of deferred lease costs (see footnote 2(n)),
was $59.6 million, $60.1 million and $59.8 million for the years ended December
31 2001, 2002 and 2003, respectively.

The lease documents contain restrictive covenants that restrict REMA's
ability to, among other things, make dividend distributions unless REMA
satisfies various conditions. As of December 31, 2003, all of these conditions
were met.

The following table sets forth REMA's obligation under these long-term
operating leases (in millions):

2004........................................................ $ 84.4
2005........................................................ 74.7
2006........................................................ 63.7
2007........................................................ 64.6
2008........................................................ 62.1
Thereafter.................................................. 997.2
--------
$1,346.7
========

Other Operating Leases. REMA leases some equipment and vehicles under
noncancelable operating leases extending through 2005. Future minimum rentals
under lease agreements are $92,000 and $74,000 in 2004 and 2005, respectively.

Rent expense incurred under other operating leases aggregated approximately
$0.4 million, $0.3 million and $0.1 million for 2001, 2002 and 2003,
respectively.

(b) OTHER COMMITMENTS.

Fuel Supply and Commodity Transportation Commitments. REMA is a party to
several fuel supply contracts and commodity transportation contracts that have
various quantity requirements and durations that are not classified as
derivatives assets and liabilities and hence are not included in REMA's
consolidated balance sheet as of December 31, 2003. Minimum purchase commitment
obligations under these agreements are as follows, as of December 31, 2003:

F-174

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

As of December 31, 2003, the maximum remaining term under any individual
fuel supply contract and transportation contract is 16 years and 20 years,
respectively.

(10) CONTINGENCIES

(a) LEGAL AND ENVIRONMENTAL MATTERS.

LEGAL MATTERS.

Bankruptcy of Enron Corp. and Its Affiliates. In the fourth quarter of
2001, Enron Corp. filed a voluntary petition for bankruptcy. Accordingly, REMA
recorded a $68.4 million provision, comprised of provisions against 100% of
Enron receivables of $3.7 million and net derivative balances of $64.7 million.
Reliant Energy Services entered into contracts with Enron on behalf of REMA
under Reliant Energy Services' procurement and marketing agreement (see note
3(a)). In 2002, Reliant Energy Services sued Enron Canada Corp., the only Enron
party to Reliant Energy Services' netting agreement which is not in bankruptcy,
in the United States District Court for the Southern District of Texas to
recover amounts owed to Reliant Energy Services, including by and among the
Enron parties. The case is pending. However, in January 2003, Enron sued Reliant
Energy Services in the United States Bankruptcy Court for the Southern District
of New York claiming $13 million based on the unenforceability of the netting
agreement.

The non-trading derivatives with Enron were designated as cash flow hedges
(see note 5). The unrealized net gain on these derivative instruments previously
reported in other comprehensive income (loss) will remain in accumulated other
comprehensive income (loss) and will be reclassified into earnings during the
period in which the originally designated forecasted transactions occur. During
2002 and 2003, a $44.0 million gain and a $8.6 million gain, respectively, was
reclassified into earnings related to these cash flow hedges. As of December 31,
2002 and 2003, the remaining amount to be reclassified into earnings through
2007 was $18.8 million and $10.2 million, respectively.

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 REMA's evaluations
with assistance from third-party consultants and engineers, REMA has recorded
the estimated aggregate costs associated with these environmental liabilities of
$34.7 million and $23.1 million as of December 31, 2002 and 2003 respectively,
of which REMA expects to spend $8.4 million over the next five years.

New Source Review Matters. The United States Environmental Protection
Agency (EPA) has requested information from six of REMA's coal-fired facilities
related to work activities conducted at the sites that may be associated with
various permitting requirements of the Clean Air Act. REMA has 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)
requested from the EPA a copy of all correspondence relating to the EPA's
request for information for one of the six facilities, which request the EPA has
granted. Furthermore, the New York state attorney general's office and the
Pennsylvania Department of Environmental Protection recently requested from the
EPA a copy of all such correspondence relating to all six facilities, which the
EPA granted.

Other Matters. REMA is involved in other legal proceedings before various
courts and governmental agencies regarding matters arising in the ordinary
course of business, some of which involve substantial amounts. Although REMA
cannot predict the outcome of these proceedings, REMA does not expect these
matters to have a material adverse effect on its results of operations,
financial condition or cash flows.

F-175

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC
AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) RELIANT RESOURCES' DEBT COVENANTS.

Both Reliant Resources' March 2003 credit facility and its senior secured
notes restrict REMA's ability to take specific actions, subject to numerous
exceptions that are designed to allow for the execution of Reliant Resources'
and its subsidiaries' business plans in the ordinary course, including the
preservation and optimization of existing investments in the retail energy and
wholesale energy businesses and the ability to provide credit support for
commercial obligations. REMA's failure to comply with these covenants could
result in an event of default that, if not cured or waived, could result in
Reliant Resources being required to repay its borrowings before their due date.

(11) CONSOLIDATION OF PENNSYLVANIA REGIONAL OPERATIONS OFFICE

On January 28, 2003, Reliant Resources announced a plan to consolidate its
Pennsylvania regional operations office into the Pittsburgh area. As part of the
consolidation, REMA relocated certain operations, administration and staff
support functions from the Johnstown, Pennsylvania office to the Pittsburgh
area. REMA plans to sell the Johnstown office. In addition, REMA eliminated
certain employee positions and offered severance benefits to qualifying
employees. To qualify for severance benefits, employees must remain employed
through pre-determined retention dates, which extend through April 2004.

Total severance benefits are estimated at $3.3 million and are being
accrued over the retention period. During 2003, REMA recorded severance expense
totaling $3.3 million and made severance payments totaling $2.3 million. As of
December 31, 2003, REMA's accrued liability for severance benefits totaled $1.0
million. Severance expense is classified in operation and maintenance expense in
REMA's consolidated statements of operations.

As a result of the anticipated sale of the office in Johnstown, REMA
recorded a $6.5 million write-down of the Johnstown office building to its fair
value less cost to sell during 2003. The write-down was recorded to depreciation
expense.

(12) SUBSEQUENT EVENTS

In January 2004, REMA sold certain power generation site permits and water
rights to an affiliate for $19.6 million in cash. The permits and water rights
were no longer needed for REMA's business. There was no gain or loss recorded on
the sale.

On February 12, 2004, Reliant Resources announced a plan, subject to
regulatory approval, to mothball 661 MW of capacity at certain peaking plants
and units that serve the PJM Interconnection, LLC and to retire the Wayne
peaking unit having a capacity of 66 MW. All of the named plants and units are
owned by REMA. REMA tested the Wayne peaking unit for impairment as of December
31, 2003 (see note 2(f)). Based on this test, there was no impairment. In 2004,
REMA adjusted the remaining useful life of the Wayne peaking unit and expects to
record $12.2 million in depreciation expense during 2004 associated with its
early retirement.

* * *

F-176

INDEX TO FINANCIAL STATEMENTS

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

Independent Auditors' Reports............................... F-178
Consolidated Statements of Operations for the Year Ended
December 31, 2001, for the periods from January 1, 2002
through February 19, 2002 and February 20, 2002 through
December 31, 2002 and for the Year Ended December 31,
2003...................................................... F-181
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-182
Consolidated Statements of Cash Flows for the Year Ended
December 31, 2001, for the periods from January 1, 2002
through February 19, 2002 and February 20, 2002 through
December 31, 2002 and for the Year Ended December 31,
2003...................................................... F-183
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) for the Year Ended December
31, 2001, for the periods from January 1, 2002 through
February 19, 2002 and February 20, 2002 through December
31, 2002 and for the Year Ended December 31, 2003......... F-184
Notes to Consolidated Financial Statements.................. F-185
Supplementary Data.......................................... F-227

F-177

INDEPENDENT AUDITORS' REPORT

To the Board of Directors of
Orion Power Holdings, Inc.
Houston, Texas

We have audited the accompanying consolidated balance sheet of Orion Power
Holdings, Inc. and subsidiaries ("the Company") as of December 31, 2002 and
2003, and the related consolidated statements of operations, stockholders'
equity and comprehensive income (loss), and cash flows for the periods from
January 1, 2002 to February 19, 2002 and February 20, 2002 to December 31, 2002
and for the year ended December 31, 2003. These financial statements are the
responsibility of the Company's management. Our responsibility is to express an
opinion on the financial statements based on our audits. The consolidated
financial statements and the financial statement schedules of the Company for
the year ended December 31, 2001, were audited by other auditors who have ceased
operations. Those auditors expressed an unqualified opinion on those financial
statements and stated that such 2001 financial statement schedules, when
considered in relation to the 2001 basic consolidated financial statements taken
as a whole, presented fairly, in all material respects, the information set
forth therein, in their reports dated February 19, 2002 (which report on the
consolidated financial statements includes an explanatory paragraph concerning
the adoption of a new accounting principle in 2001).

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, the 2002 and 2003 consolidated financial statements present
fairly, in all material respects, the financial position of the Company as of
December 31, 2002 and 2003, and the results of its operations and its cash flows
for the periods from January 1, 2002 to February 19, 2002 and February 20, 2002
to December 31, 2002 and for the year ended December 31, 2003, in conformity
with accounting principles generally accepted in the United States of America.

As discussed in notes 2 and 5 to the consolidated financial statements, the
Company changed its accounting for asset retirement obligations and its
presentation of revenues and cost of sales associated with non-trading commodity
derivatives activities in 2003 and changed its method of accounting for goodwill
and other intangibles in 2002.

As discussed above, the consolidated financial statements of the Company
for the year ended December 31, 2001 were audited by other auditors who have
ceased operations. Such financial statements and financial statement schedules
have been revised to give effect to the following transitional disclosures,
expanded disclosures and reclassifications:

- As discussed in note 5, the Company has presented the transitional
disclosures for 2001 as required by Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142).
We audited the adjustments described in note 5 that were applied to
revise the 2001 financial statements to include the transitional
disclosures required by SFAS No. 142, which was adopted by the Company as
of January 1, 2002. Our audit procedures with respect to the disclosure
in note 5 with respect to 2001 included (1) comparing the previously
reported net income to the previously issued financial statements and the
adjustments to reported net income representing amortization expense
(including any related tax effects) recognized in those periods related
to goodwill and intangible assets no longer being amortized as a result
of initially applying SFAS No. 142 (including any related tax effects) to
the Company's underlying analysis obtained from management and (2)
testing the mathematical accuracy of the reconciliation of adjusted net
income to reported net income and the related earnings per share amounts.
F-178

- As discussed in note 4, the Company has presented selected financial
information and unaudited pro forma information for 2001 as if the
acquisition had occurred on January 1, 2001. We audited the expanded
disclosures and our procedures included (1) comparing the previously
reported revenues and net income to the previously issued financial
statements and (2) agreeing the expanded pro forma disclosure amounts to
the Company's underlying analysis obtained from management.

- The financial statements have also been revised to give effect to the
following reclassifications: (1) in note 2(a), for the 2001 financial
statements the Company has presented gains and losses on derivative
instruments net in revenues rather than separately and has also presented
purchased power separately from fuel expense, (2) for the 2001 cash flow
statements, the Company has presented amortization of deferred financing
fees separately, (3) in note 2(i), for 2001 the Company presented the
capitalized interest for the year rather than the cumulative capitalized
interest included in the balance sheet as of December 31, 2001.

We audited these reclassifications that were applied to revise the 2001
financial statements and financial statement schedules to conform to the
presentation of such amounts in the 2003 financial statements and
financial statement schedules. Our audit procedures with respect to the
2001 amounts included (1) comparing the previously reported tabular
presentation of each amount to a reconciliation schedule prepared by
management, (2) testing the mathematical accuracy of the underlying
analysis and (3) determining the reclassifications were consistent with
the 2003 financial statement presentation.

In our opinion, the transitional disclosures, expanded disclosures and
reclassifications to the 2001 financial statements and disclosures and financial
statement schedules described above have been properly applied. However, we were
not engaged to audit, review, or apply any procedures to the 2001 financial
statements or financial statement schedules of the Company other than with
respect to such transitional disclosures, expanded disclosures and
reclassifications and, accordingly, we do not express an opinion or any form of
assurance on the 2001 financial statements taken as a whole.

Our audit was conducted for the purpose of forming an opinion on the 2002
and 2003 basic consolidated statements taken as a whole. The 2002 and 2003
financial statement schedules are presented for the purpose of additional
analysis and are not a required part of the 2002 and 2003 basic consolidated
financial statements. These schedules are the responsibility of the Company's
management. Such schedules have been subjected to the auditing procedures
applied in our audit of the 2002 and 2003 basic consolidated financial
statements and, in our opinion, are fairly stated in all material respects when
considered in relation to the 2002 and 2003 basic consolidated financial
statements taken as a whole.

DELOITTE & TOUCHE, LLP

Houston, Texas
March 5, 2004

F-179

The following is a copy of a report previously issued by Arthur Andersen
LLP (Andersen). The report has not been reissued by Andersen.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Orion Power Holdings, Inc.:

We have audited the accompanying consolidated balance sheets of Orion Power
Holdings, Inc. (a Delaware corporation) and subsidiaries (Orion Power) as of
December 31, 2000 and 2001, and the related consolidated statements of
operations, stockholders' equity and cash flows for each of the three years in
the period ended December 31, 2001. These financial statements are the
responsibility of Orion Power's management. Our responsibility is to express an
opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States. Those standards require that we plan and perform
the audit to obtain reasonable assurance about whether the financial statements
are free of material misstatement. An audit also includes assessing the
accounting principles used and significant estimates made by management, as well
as evaluating the overall financial statement presentation. We believe that our
audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above
present fairly, in all material respects, the financial position of Orion Power
Holdings, Inc. and subsidiaries as of December 31, 2000 and 2001, and the
results of their operations and their cash flows for each of the three years in
the period ended December 31, 2001, in conformity with accounting principles
generally accepted in the United States.

As explained in Note 6 to the financial statements, effective January 1,
2001, Orion Power changed its method of accounting for derivative financial
instruments.

/s/ ARTHUR ANDERSEN LLP

Vienna, Virginia
February 19, 2002

F-180

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

See Notes to the Consolidated Financial Statements
F-181

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to the Consolidated Financial Statements
F-182

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

See Notes to the Consolidated Financial Statements
F-183

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY AND COMPREHENSIVE INCOME (LOSS)

See Notes to the Consolidated Financial Statements
F-184

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

In this report "Orion Power Holdings" refers to Orion Power Holdings, Inc.
"Orion Power" refers to Orion Power Holdings, Inc. and its subsidiaries
collectively unless the context clearly indicates otherwise. Orion Power
Holdings, a Delaware corporation, and subsidiaries own and operate electric
generation facilities in New York, Ohio, Pennsylvania and West Virginia with an
aggregate generating capacity of 6,690 megawatts, as of December 31, 2003. Orion
Power typically sells its wholesale products to electric power retailers, which
are the entities that supply power to consumers. Power retailers include
independent system operators, regulated utilities, municipalities, energy supply
companies, cooperatives and retail "load" or customer aggregators. Orion Power
has grown its business by strategically acquiring, developing and modernizing
non-nuclear generating facilities located in critical locations in regions
across the United States.

On February 19, 2002, Orion Power was acquired by merger (the Merger) by a
wholly-owned subsidiary of Reliant Resources, Inc. (Reliant Resources). The
transaction resulted in the purchase by Reliant Resources of all of Orion Power
Holdings' outstanding shares of common stock for $26.80 per share in cash for an
aggregate purchase price of approximately $2.9 billion. Reliant Resources funded
the acquisition with a $2.9 billion credit facility and $41 million of cash on
hand. As a result of the Merger, Orion Power became a wholly-owned subsidiary of
Reliant Resources.

BASIS OF PRESENTATION

These consolidated financial statements present the results of operations
for the year ended December 31, 2001 and for the periods from January 1, 2002
through February 19, 2002 (the date that Reliant Resources acquired Orion Power)
and February 20, 2002 through December 31, 2002 and for the year ended December
31, 2003. Within these consolidated financial statements, "Current Orion" and
"Former Orion" refer to Orion Power after and before, respectively, the Merger.
The results of operations in these consolidated financial statements also
include general corporate expenses allocated by Reliant Resources to Orion Power
subsequent to the Merger. All of the allocations in the consolidated 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 Orion Power had
operated as a separate entity subsequent to the Merger.

The fair value adjustments related to the Merger, which have been pushed
down to Orion Power from Reliant Resources, primarily included adjustments in
property, plant and equipment, goodwill, contractual rights and obligations,
severance liabilities, debt, unrecognized pension and postretirement benefits
liabilities and related deferred taxes. For additional information regarding the
Merger, see note 4.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) RECLASSIFICATIONS.

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

As discussed in note 5, "Goodwill and Intangibles," Orion Power has
presented the transitional disclosures for 2001 required by SFAS No. 142.
Additionally, as discussed in note 2(f), "Summary of Significant Accounting
Policies -- Property, Plant and Equipment and Depreciation Expense," and in note
5, "Goodwill and Intangibles," for 2001 Orion Power has reclassified air
emissions regulatory allowances and the related accumulated amortization from
net property, plant and equipment to net intangibles." For the 2001 financial
statements and the 2001 pro forma adjustment discussed in note 4, "Business
Acquisitions" Orion Power has presented gains and losses on derivative
instruments net in revenues rather than separately. Orion Power has also
presented purchased power separately from fuel
F-185

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

expense. For the 2001 cash flow statement, Orion Power has presented
amortization of deferred financing fees separately from depreciation and
amortization. In note 2(i), for 2001, Orion Power presented capitalized interest
for the year rather than the cumulative capitalized interest included in the
balance sheet as of December 31, 2001.

(b) USE OF ESTIMATES AND MARKET RISK AND UNCERTAINTIES.

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 these
estimates. Orion Power's critical accounting estimates include: (a) goodwill,
(b) property, plant and equipment, (c) depreciation expense, (d) derivative
activities, (e) contingencies and (f) deferred tax assets valuation allowance
and tax liabilities.

Orion Power is subject to the risk associated with price movements of
energy commodities and the credit risk associated with its commercial
activities. For additional information regarding these risks, see notes 2(d) and
(b). Orion Power is subject to risks relating to the reliability of the systems,
procedures and other infrastructure necessary to operate its business. Orion
Power is also subject to risks relating to changes in laws and regulations; the
outcome of pending lawsuits, governmental proceedings and investigations; the
effects of competition; liquidity concerns in its markets; changes in interest
rates; the availability of adequate supplies of fuel and transportation; weather
conditions; financial market conditions and Orion Power's access to capital; the
creditworthiness or financial distress of Orion Power's counterparties; actions
by rating agencies with respect to Orion Power or its competitors; political,
legal, regulatory and economic conditions and developments; the successful
operation of deregulating power markets and other items.

(c) PRINCIPLES OF CONSOLIDATION.

Orion Power's accounts and those of Orion Power's wholly-owned and
majority-owned subsidiaries are included in the consolidated financial
statements. All significant intercompany transactions and balances are
eliminated in consolidation.

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

In January 2003, the Financial Accounting Standards Board (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, receives a majority of the
entity's expected residual returns, or both. 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.

Orion Power adopted FIN No. 46 on January 1, 2003. FIN No. 46 did not have
any impact on Orion Power's consolidated financial statements.

F-186

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In December 2003, the FASB released FASB Interpretation No. 46 (revised
December 2003) "Consolidation of Variable Interest Entities, an Interpretation
of ARB No. 51" (FIN No. 46R), which replaces FIN No. 46 and modified certain
criteria in determining which entities should be considered as variable interest
entities. Orion Power does not believe the application of FIN No. 46R will have
a material impact to the consolidated financial statements. The application of
FIN No. 46R continues to evolve as the FASB continues to address issues
submitted for consideration. Orion Power will continue to assess the application
of clarified or revised guidance related to FIN No. 46R.

(d) REVENUES AND ACCOUNTING FOR HEDGING ACTIVITIES.

Power Generation Revenues. Orion Power records gross revenue for energy
sales and services related to the electric power generation facilities under the
accrual method and these revenues generally are recognized upon delivery.
Electric power and other energy services are sold at market-based prices through
existing power exchanges or through third-party contracts. Energy sales and
services related to the electric power generation facilities not billed by
month-end are accrued based upon estimated energy and services delivered. See
below for the discussion of the impact of implementation of Emerging Issues Task
Force (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).

Hedging Activities. Effective January 1, 2001, Orion Power adopted
Statement of Financial Accounting Standards (SFAS) No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended (SFAS No. 133), which
establishes accounting and reporting standards for derivative instruments.
Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in
accumulated other comprehensive loss of $33 million.

If certain conditions are met, Orion Power may designate a derivative
instrument as hedging (a) the exposure to variability in expected future cash
flows (cash flow hedge) or (b) the exposure to changes in the fair value of an
asset or liability (fair value hedge). This statement requires that a derivative
be recognized at fair value in the balance sheet whether or not it is designated
as a hedge. Derivative commodity contracts for the physical delivery of purchase
and sale quantities transacted in the normal course of business are designated
as normal purchases and sales exceptions and are not reflected in the
consolidated balance sheets at fair value. 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.

Orion Power designates its derivatives as cash flow hedges only if there is
a high correlation between price movements in the derivative and the item
designated as being hedged. This correlation is measured both at the inception
of the hedge and on an ongoing basis, with an acceptable level of correlation of
at least 80% to 125% for hedge designation. The gains and losses related to
derivative instruments designated as cash flow hedges are deferred in
accumulated other comprehensive income (loss), net of tax, to the extent the
contracts are effective as hedges, and then are recognized in the results of
operations in the same period as the settlement of the underlying hedged
transactions. Once the anticipated transaction occurs, the accumulated deferred
gain or loss recognized in accumulated other comprehensive income (loss) is
reclassified and included in the consolidated statements of operations (a) prior
to October 1, 2003, under the captions (i) fuel expense, in the case of hedging
activities related to physical natural gas or coal purchases, (ii) purchased
power, in the case of hedging activities related to physical power purchases,
(iii) revenues, in the case of hedging activities related to physical power and
natural gas sales transactions and financial transactions and (iv) interest
expense, in the case of interest rate hedging activities and (b) effective
October 1, 2003, under the captions (i) fuel expense, in case of hedging
activities related to physical natural gas or coal purchases and physical
natural gas sales transactions that

F-187

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

do not physically flow, (ii) purchased power, in the case of hedging activities
related to physical power purchases that do physically flow, (iii) revenues, in
the case of hedging activities related to financial transactions, physical power
sales transactions, physical power purchases that do not physically flow and
natural gas sales transactions that do physically flow and (iv) interest
expense, in the case of interest rate hedging activities. Prior to October 1,
2003, revenues, fuel expense and purchased power related to sale and purchase
contracts designated as hedges were generally recorded on a gross basis in the
delivery period.

For a derivative not designated as a hedge, changes in fair value are
recorded as unrealized gains or losses in the results of operations. If and when
correlation ceases to exist at an acceptable level, hedge accounting ceases and
changes in fair value are recognized currently in our results of operations. If
it becomes probable that a forecasted transaction will not occur, we immediately
recognize the respective deferred gains or losses in our results of operations.
The associated hedging instrument is then marked to market through our results
of operations for the remainder of the contract term unless a new hedging
relationship is redesignated. Prior to October 1, 2003, revenues, fuel expense
and purchased power related to sale and purchase contracts designated as hedges
were generally recorded on a gross basis in the delivery period. In July 2003,
the EITF issued EITF No. 03-11, which stated 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.
Reclassification of prior year amounts is not required. Orion Power's sales and
purchases of fuel and purchased power related to its commodity derivative
activities physically deliver and the related settlements are reported on a
gross basis in the consolidated statement of operations. Therefore, EITF No.
03-11 resulted in no change in revenues, fuel expense and purchased power for
the fourth quarter of 2003 and is believed not to have a significant impact on
the presentation of future operations. EITF No. 03-11 has no impact on margins
or net income. Comparative financial statements for prior periods have not been
reclassified to conform to this presentation, as it is not required. In
addition, it is not practicable to determine sales and purchases of fuel and
purchased power in 2001, 2002 and the nine months ended September 30, 2003 that
would have been shown net if EITF No. 03-11 had been applied to the results of
operations historically.

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. 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 the consolidated financial statements.

For additional discussion of derivative and hedging activities, see note 6.

Set-off of Derivative Assets and Liabilities. Where derivative instruments
are subject to a master netting agreement and the criteria of FASB
Interpretation No. 39, "Offsetting of Amounts Related to Certain Contracts," are
met, Orion Power presents its derivative assets and liabilities on a net basis
in the consolidated balance sheets. Derivative assets/liabilities and accounts
receivable/payable are presented separately in the consolidated balance sheets.
The derivative assets/liabilities and accounts receivable/payable are set-off
separately in the consolidated balance sheets although in certain cases
contracts permit the set-off of derivative assets/liabilities and accounts
receivable/payable with a given counterparty.

(e) GENERAL, ADMINISTRATIVE AND DEVELOPMENT EXPENSES.

The general, administrative and development expenses in the consolidated
statements of operations include (a) certain employee-related costs, (b) certain
contractor costs, (c) bad debt expense,
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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(d) corporate and administrative services, as provided by affiliates (including
management services, financial and accounting, cash management and treasury
support, legal, information technology system support, office management and
human resources) and (e) certain benefit costs. See note 3 for discussion of
related party transactions.

(f) PROPERTY, PLANT AND EQUIPMENT AND DEPRECIATION EXPENSE.

Property, plant and equipment is stated at cost. Cost of acquired property,
plant and equipment includes an allocation of the purchase price based on the
asset's fair market value. Orion Power expenses all repair and maintenance costs
as incurred, including planned major maintenance. Depreciation is computed using
the straight-line method based on estimated useful lives commencing when assets,
or major components thereof, are either placed in service or acquired, as
appropriate.

Property, plant and equipment includes the following:

Orion Power recorded depreciation expense of $128 million, $25 million,
$110 million and $132 million for 2001, for January 1, 2002 through February 19,
2002, February 20, 2002 through December 31, 2002, and 2003, respectively.

Orion Power periodically evaluates property, plant and equipment for
impairment when events or changes in circumstances indicate that the carrying
value of these assets may not be recoverable. The determination of whether an
impairment has occurred is based on an estimate of undiscounted cash flows
attributable to the assets, as compared to the carrying value of the assets. A
resulting impairment loss is highly dependent on the underlying assumptions.
There were no impairments recognized for 2001, for January 1, 2002 through
February 19, 2002, February 20, 2002 through December 31, 2002, and 2003. As of
December 31, 2002 and 2003, Orion Power performed impairment analyses of certain
property, plant and equipment. In addition, in November 2002 and July 2003,
Orion Power performed impairment analyses of all of its property, plant and
equipment, as Orion Power believed events had indicated that these assets may
not be recoverable. Based on these analyses, no impairments were recorded.

If the wholesale energy market outlook changes negatively, Orion Power
could have impairments of property, plant and equipment in future periods. In
addition, Orion Power's ongoing evaluation of the wholesale energy business
could result in decisions to mothball, retire or dispose of generation assets,
any of which could result in impairment charges.

See note 14(c) for discussion of Orion Power's Liberty Electric PA, LLC
(Liberty) generating station.

F-189

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(g) GOODWILL AND AMORTIZATION EXPENSE.

Orion Power records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Through 2001, Orion
Power amortized goodwill on a straight-line basis over 30 years. Pursuant to the
adoption of SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142)
on January 1, 2002, Orion Power discontinued amortizing goodwill. See note 5 for
a discussion regarding the adoption of SFAS No. 142. Goodwill amortization
expense for 2001 was $857,000. Amortization expense for other intangibles,
excluding contractual rights and obligations, for 2001, for January 1, 2002
through February 19, 2002, February 20, 2002 through December 31, 2002, and 2003
was $9 million, $1 million, $27 million and $21 million, respectively. See also
note 5.

Orion Power periodically evaluates goodwill and other intangibles when
events or changes in circumstances indicate that the carrying value of these
assets may not be recoverable. Effective January 1, 2002, goodwill and other
intangibles are evaluated for impairment in accordance with SFAS No. 142 (see
note 5). In 2002 Orion Power recognized an impairment charge of $338 million
(pre-tax and after-tax) relating to goodwill. Due to the disposition of one of
Reliant Resources' plants, not owned by Orion Power, goodwill was tested for
impairment effective July 2003. In connection with this analysis, an impairment
of $585 million (pre-tax and after-tax) was recognized. For further discussion
of goodwill and other intangible asset impairment analyses in 2002 and 2003, see
note 5.

(h) STOCK-BASED COMPENSATION PLANS.

Orion Power applied the intrinsic value 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 was recorded when options
were issued with an exercise price equal to or greater than the market price of
the underlying stock on the date of grant. Orion Power complies with the
disclosure requirements of SFAS No. 123, "Accounting for Stock-Based
Compensation" (SFAS No. 123) and SFAS No. 148, "Accounting for Stock-Based
Compensation -- Transition and Disclosure, an amendment to SFAS No. 123" (SFAS
No. 148) and discloses 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. The FASB has announced that it plans to require all companies to expense
the fair value of employee stock options in 2005. The FASB is still evaluating
"fair value" valuation models and other items. Orion Power no longer has
stock-based employee compensation as it is a wholly-owned subsidiary of Reliant
Resources.

Orion Power Holdings granted options to acquire shares of its common stock
at an exercise price less than the market value of Orion Power Holdings' common
stock. As of December 31, 2001, Orion Power recognized deferred compensation of
$5 million to be amortized over the three-year vesting period. Orion Power
recorded $2 million of compensation expense related to these options for the
year ended December 31, 2001.

If compensation costs had been determined as prescribed by SFAS No. 123,
the net income (loss) and per share amounts would have approximated the
following pro forma results for 2001, which take into account the amortization
of stock-based compensation, including stock options, to expense on a straight-
line basis over the vesting periods (in thousands, except per share amounts):

Pro forma net income........................................ $86,071
Pro forma net income per common share-basic................. 0.87
Pro forma net income per common share-assuming dilution..... 0.83

For further information regarding the Orion Power stock-based compensation
plan see note 9.

F-190

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(i) CAPITALIZATION OF INTEREST EXPENSE.

Interest expense is capitalized as a component of major projects under
construction and is amortized over the estimated useful lives of the assets.
During 2001, for January 1, 2002 through February 19, 2002, and February 20,
2002 through December 31, 2002 and during 2003, Orion Power capitalized interest
of $24 million, $2 million, $5 million and $0, respectively.

(j) INCOME TAXES.

Orion Power uses the asset and liability method of accounting for deferred
income taxes and measures deferred income taxes for all significant income tax
temporary differences. For additional information regarding income taxes, see
note 12.

Prior to February 20, 2002, Orion Power filed a consolidated federal income
tax return. Orion Power's pre-acquisition consolidated federal income tax
returns have been filed through the tax year ending February 19, 2002.

From February 20, 2002 through September 30, 2002, as a wholly-owned
subsidiary of Reliant Resources, Orion Power was included in the consolidated
income tax returns of CenterPoint Energy, Inc., formerly the majority owner of
Reliant Resources.

As of October 1, 2002, Orion Power is included in the consolidated income
tax returns of Reliant Resources and calculates its income tax provision on a
separate return basis, whereby Reliant Resources pays all federal income taxes
on Orion Power's behalf and is entitled to any related tax savings. The
difference between Orion Power's current federal income tax expense or benefit,
as calculated on a separate return basis, and related amounts paid or received
to/from Reliant Resources, if any, are recorded in Orion Power's financial
statements as adjustments to additional paid-in capital on Orion Power's
consolidated balance sheet. See note 12 for further discussion.

(k) CASH.

Orion Power records as cash and cash equivalents all highly liquid
short-term investments with original maturities or remaining maturities at date
of purchase of three months or less.

(l) RESTRICTED CASH.

Restricted cash primarily includes cash at certain subsidiaries, the
distribution or transfer of which to Orion Power Holdings or its other
subsidiaries, is restricted by financing and other agreements, but is available
to the applicable subsidiary to use to satisfy certain of its obligations. For a
discussion of Orion Power's various financing agreements, see note 7. The
following table details Orion Power's current and long-term restricted cash by
reporting entity:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) The credit facilities and other debt agreements of certain of Orion Power
Holdings' subsidiaries contain various covenants that include, among others,
restrictions on the payment of dividends to Orion Power Holdings unless
certain conditions are satisfied.

(M) ALLOWANCE FOR DOUBTFUL ACCOUNTS.

Accounts and notes receivable, principally from customers, in the
consolidated balance sheets are net of an allowance for doubtful accounts of $2
million and $7 million at December 31, 2002 and 2003, respectively. The net
provision for doubtful accounts in the consolidated statements of operations for
February 20, 2002 through December 31, 2002, and 2003 was $1 million and $6
million, respectively.

(n) INVENTORY.

Inventory consists of materials and supplies, including spare parts, coal
and heating oil. All inventory is valued at the lower of average cost or market.
Below is a detail of inventory:

(o) ENVIRONMENTAL COSTS.

Orion Power expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. Amounts that relate to
an existing condition caused by past operations and that do not have future
economic benefit are expensed. Orion Power records liabilities related to
expected future costs related to environmental assessments and/or remediation
activities when they are probable and the costs can be reasonably estimated. See
note 14(a) for further discussion.

(p) ASSET RETIREMENT OBLIGATIONS.

On January 1, 2003, Orion Power adopted SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). 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. Prior to the adoption of SFAS No. 143, Orion Power
recorded asset retirement obligations in connection with the respective business
combinations. These obligations were recorded at their present values on the
dates of acquisition. Orion Power's asset retirement obligations primarily
relate to environmental obligations related to ash site closures at Orion
Power's MidWest facilities. The impact of the adoption of SFAS No. 143 resulted
in a gain of $2 million, net of tax of $2 million, which is reflected as a
cumulative effect of an accounting change in the consolidated statement of
operations for 2003.

The impact of the adoption of SFAS No. 143 for Orion Power's operations
resulted in a January 1, 2003 cumulative effect of an accounting change to
record (a) a $1 million increase in the carrying values of property, plant and
equipment, (b) a $44 thousand increase in accumulated depreciation of property,
plant and equipment, (c) a $3 million decrease in asset retirement obligations
and (d) a $2 million increase in deferred income tax liabilities.

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

If Orion Power had adopted SFAS No. 143 on January 1, 2001, the impact
would have been immaterial to consolidated net income (loss) for 2001, for
January 1, 2002 through February 19, 2002 and February 20, 2002 through December
31, 2002.

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

Balance at January 1, 2003.................................. $1,951
Accretion expense........................................... 116
Additions................................................... 60
------
Balance at December 31, 2003................................ $2,127
======

(q) DEFERRED FINANCING COSTS.

Deferred financing costs are costs incurred in connection with obtaining
financings. These costs are deferred and amortized, using the straight-line
method, which approximates the effective interest method, over the life of the
related debt. From October 29, 2002 through December 31, 2003, Orion Power had
incurred approximately $29 million in financing costs related to its 2002
refinancing. Orion Power capitalized $28 million and directly expensed $1
million in fees and other costs related to this refinancing.

During 2001, for January 1, 2002 through February 19, 2002, February 20,
2002 through December 31, 2002 and 2003, Orion Power amortized $16 million, $3
million, $1 million and $10 million of deferred financing costs to interest
expense. As of December 31, 2002 and 2003, $26 million and $17 million,
respectively, of net deferred financing costs were classified in other long-term
assets in the consolidated balance sheets. See note 7 for discussion of Orion
Power's various financing agreements.

(r) CUSTOMER CONCENTRATION.

The following tables represent customers who contributed in excess of 10%
of the consolidated revenues for 2001, for January 1, 2002 through February 19,
2002, February 20, 2002 through December 31, 2002 and 2003 (in millions, except
percentages):

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table represents accounts receivable balances in excess of
10% of the total consolidated accounts receivable balance and the related
percentages as of December 31, 2002 and 2003 (in millions, except percentages):

(s) PREPAID INSURANCE AND PROPERTY TAXES.

Prepaid insurance and property taxes are costs paid in advance (but paid
when due in the ordinary course of business) for insurance and property taxes.
These costs are deferred and amortized, using the straight-line method, over the
service period for which the prepayment pertains.

(t) GUARANTEES AND INDEMNIFICATIONS.

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. Orion Power adopted the reporting
requirements of FIN No. 45 on January 1, 2003. The adoption of FIN No. 45 had no
impact to Orion Power's historical 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 the consolidated financial position or results of
operations as of and for the year ended December 31, 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(e).

(u) DISCLOSURES ABOUT PENSIONS AND OTHER POSTRETIREMENT BENEFITS.

In December 2003, the FASB issued a revision to SFAS No. 132, "Employers'
Disclosures About Pensions and Other Postretirement Benefits -- An Amendment of
FASB Statements No. 87, 88 and 106" (SFAS No. 132 (Revised 2003)). This
statement revises employers' disclosures about pension plans and other
postretirement benefit plans. This statement retains the disclosure requirements
contained in SFAS No. 132, "Employers' Disclosures about Pensions and Other
Postretirement Benefits" (SFAS No. 132), which it replaces. It requires
additional disclosures to those in the original SFAS No. 132 about the assets,
obligations, cash flows and net periodic benefit cost of defined benefit pension
plans and other defined benefit postretirement plans. Orion Power adopted these
additional disclosures. See note 11.

(v) NEW ACCOUNTING PRONOUNCEMENTS.

As of February 20, 2004, no standard setting body or authoritative body has
established new accounting pronouncements or changes to existing accounting
pronouncements that would have a material impact to Orion Power's results of
operations, financial position or cash flows, for which Orion Power had not
already adopted and/or disclosed elsewhere in these notes.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(3) RELATED PARTY TRANSACTIONS

The consolidated financial statements include significant transactions
between Orion Power and Reliant Resources and its other subsidiaries. The
majority of these transactions involve the purchase or sale of energy, capacity,
ancillary services, fuel, emissions allowances or related derivatives or
services (including transportation, transmission and storage services) by
Reliant Energy Services, Inc. (Reliant Energy Services), a wholly-owned
subsidiary of Reliant Resources, from or to Orion Power. The following describes
related party agreements and transactions:

Support Services Agreement. On October 28, 2002, Orion Power entered into
a services arrangement with Reliant Energy Wholesale Service Company (REWSC), a
wholly-owned subsidiary of Reliant Resources. REWSC allocates certain support
services costs to Orion Power based on Orion Power's direct labor costs relative
to the direct labor costs of other entities to which REWSC provides similar
services. Management believes this method of allocation is reasonable. These
allocations are not necessarily indicative of what would have been incurred had
Orion Power been an unaffiliated entity. Orion MidWest and Orion NY may only pay
a fixed amount for certain of these services due to contractual restrictions.
The excess of the allocated amount over the fixed amount has been recorded as a
non-cash equity contribution to Orion Power from Reliant Resources. REWSC billed
Orion MidWest and Orion NY approximately $3 million collectively, which was
included in general, administrative and development expense for the period from
October 28, 2002 through December 31, 2002. In 2003, the amount of support
services costs allocated to Orion Power on this basis by REWSC was $84 million,
of which $14 million was billed to Orion Power and $70 million was recorded as a
non-cash equity contribution from Reliant Resources.

Services Agreements. On October 28, 2002, Orion Power entered into an
agreement with Reliant Energy Services to provide support services to Orion
Power Holdings' subsidiaries, Orion MidWest and Orion NY, and their respective
subsidiaries. Under the support services agreement, Reliant Energy Services will
assist the subsidiaries with the following: the sale and purchase of energy
related products; the purchase and sale of electric transmission service; the
sale and purchase of fuel related products and the sale of allowances for air
emissions credits, in connection with the operation of the Orion MidWest and
Orion NY electric generating facilities. In addition, Reliant Energy Services
will assist in the administration and management of the energy and fuel related
products such as scheduling and dispatch of energy related products and
scheduling and nomination of fuel related products. These arrangements are
provided for a flat monthly fee payable to Reliant Energy Services, plus
out-of-pocket costs and expenses and will continue until 60 days after the final
maturity date of the Orion MidWest and Orion NY credit agreements which mature
in October 2005. From February 20, 2002 through October 27, 2002, these services
were provided under a previous agreement entered into at the time of the Merger.
Purchases from Reliant Energy Services, recorded in fuel expense and purchased
power expense, were $99 million and $43 million and $145 million and $25 million
for February 20, 2002 through December 31, 2002, and 2003, respectively. Sales
to Reliant Energy Services, recorded in revenue, were $20 million and $33
million and for February 20, 2002 through December 31, 2002 and 2003,
respectively.

Technical Services Arrangement. As of July 1, 2002, REWSC agreed to
provide personnel and technical services as required to the operating services
subsidiaries of Orion Power Holdings under an informal agreement. These services
assure that facilities are properly operated and maintained. Amounts incurred
under this agreement for February 20, 2002 through December 31, 2002 and 2003
were approximately $3 million and $6 million, respectively, and were included in
operations and maintenance expense.

Liberty Station Agency Letter Agreement. Effective February 19, 2002,
Liberty Electric Power, LLC (LEP) entered into an agency agreement with Reliant
Energy Services wherein, Reliant Energy Services will act as an agent in certain
transactions (purchase of station energy, scheduling and dispatching
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

services) with PJM Interconnection, LLC (PJM) on behalf of LEP. This agreement
provides for reimbursement to Reliant Energy Services of amounts paid to PJM on
behalf of LEP. The agreement may be terminated by either party upon 10 days
written notice. Amounts incurred under this agreement for February 20, 2002
through December 31, 2002 and 2003 were approximately $0 and $1 million,
respectively, and were included in operations and maintenance expense. Although
this agreement is still in place, there are no longer transactions entered into
under it. Transactions are now conducted under the Liberty energy services
agreement and gas purchase agreement, as described below.

Liberty Energy Services Agreement and Gas Purchase Agreement. On August
20, 2003, LEP entered into an agreement with Reliant Energy Services to provide
the following services to LEP: dispatching of the Liberty station; coordination
with PJM; bidding of all energy related products from the Liberty station into
PJM on behalf of LEP; and fuel scheduling, coordination with fuel transporters
and management of any balancing agreements. Reliant Energy Services receives a
flat monthly fee from LEP for providing these services in the amount of $0.1
million. The agreement had an initial term of 60 days and has been extended on a
month-to-month basis. Amounts incurred in 2003 under this agreement were $0.4
million. In addition, on August 20, 2003, LEP and Reliant Energy Services
entered into a Base Contract for Sale and Purchase of Natural Gas pursuant to
which LEP buys natural gas from Reliant Energy Services. Liberty is required to
pre-pay Reliant Energy Services at least monthly for all gas purchases. The
contract had an initial term of 60 days and has been extended on a
month-to-month basis. Amounts incurred under this agreement in 2003 were $20
million.

Other. From February 20, 2002 through December 31, 2002 and during 2003,
Reliant Resources made net equity contributions to Orion Power totaling $189
million and $81 million, respectively. For February 20, 2002 through December
31, 2002, the contributions were primarily to fund the redemption of the
convertible senior notes, federal income taxes, working capital and interest on
the senior notes, partially offset by a deemed distribution related to current
federal income taxes of $73 million (see note 2(j)). For 2003, the net
contributions were primarily composed of funding interest on the senior notes
and support services allocations from REWSC, partially offset by deemed
distributions related to current federal income taxes.

In May 2003 and November 2003, Reliant Resources contributed $15 million
and $20 million, respectively, to Orion Power, as a partial funding of the
semi-annual interest payment of $24 million on the senior notes due in each of
May 2003 and November 2003. While Reliant Resources has no obligation, it
intends to contribute any funding shortfall for the semi-annual interest
payments due in May 2004 and November 2004 should Orion Power Holdings' funds be
insufficient. See note 7.

(4) BUSINESS ACQUISITIONS

ACQUISITION BY RELIANT RESOURCES.

In February 2002, Reliant Resources acquired all of Orion Power's
outstanding shares of common stock for an aggregate purchase price of $2.9
billion. Reliant Resources funded the acquisition with a $2.9 billion credit
facility and $41 million of cash on hand.

Reliant Resources accounted for the acquisition as a purchase with assets
and liabilities reflected at their estimated fair values. The excess of the
purchase price over the fair value of net assets acquired was recorded as
goodwill for $1.3 billion. The fair value adjustments have been pushed down to
Orion Power from Reliant Resources and primarily included adjustments in
property, plant and equipment, goodwill, contractual rights and obligations,
severance liabilities, debt, unrecognized pension and postretirement benefits
liabilities and related deferred taxes. These fair value adjustments were
finalized in February 2003, based on final valuations of property, plant and
equipment, intangible assets and other assets and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

obligations. There were no additional material modifications to the preliminary
adjustments from December 31, 2002.

Reliant Resources' net purchase price allocated to Orion Power's book value
was as follows, in millions:

Adjustments to property, plant and equipment and other intangibles,
excluding contractual rights, are based primarily on valuation reports prepared
by independent appraisers and consultants.

The following factors contributed to the recognized goodwill of $1.3
billion: commercialization value attributable to Reliant Resources' trading
capabilities, commercialization and synergy value associated with fuel
procurement in conjunction with Reliant Resources' existing generating plants in
the region, Reliant Resources' entry into the New York power market, general and
administrative cost synergies with Reliant Resources' existing PJM power market
generating assets, and Reliant Resources' risk diversification value due to
increased scale, fuel supply mix and the nature of the acquired assets. Of the
resulting goodwill, only $105 million was deductible for United States income
tax purposes. See note 5 for a discussion of the subsequent goodwill impairment
in 2003.

The components of other intangible assets and the related weighted average
amortization period consist of the following, as of the acquisition date:

There was no allocation of purchase price to any intangible assets that are
not subject to amortization. See note 5 for further discussion of goodwill and
intangible assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table presents selected financial information and unaudited
pro forma information for 2001 and 2002, as if the acquisition had occurred on
January 1, 2001 and 2002, as applicable:

These unaudited pro forma results, based on assumptions deemed appropriate,
have been prepared for informational purposes only and are not necessarily
indicative of the amounts that would have resulted if the acquisition by Reliant
Resources had occurred on January 1, 2001 and 2002, as applicable. 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, 2001 and 2002, as applicable. Such amortization included in the pro
forma results above was based on the value of the contractual rights and
obligations at February 19, 2002. The amounts applicable to 2002 were
retroactively applied to January 1, 2002 through February 19, 2002 to arrive at
the pro forma effect on that period. The unaudited pro forma financial
information presented above reflects the acquisition by Reliant Resources in
accordance with SFAS No. 141, "Business Combinations" and SFAS No. 142. See
notes 2(g) and 5.

FORMER ORION ACQUISITION.

The acquisition described below occurred prior to the Merger with Reliant
Resources and amounts described may have been adjusted as a result of the Merger
discussed above or are no longer applicable.

COMPETITIVE POWER VENTURES -- ATLANTIC.

In October 2001, Orion Power purchased one combined-cycle power project
located in Florida from Competitive Power Ventures Holdings, LLC, a subsidiary
of Competitive Power Ventures, Inc., for approximately $26 million in cash
(Atlantic Project). This was a 250 megawatt development project located near
Palm Beach with substantial expansion capability. During 2002, as a result of
the acquisition by Reliant Resources, Orion Power decided to cancel the 250
megawatt Atlantic Project because of capital market and economic considerations.

The acquisition was recorded under the purchase method of accounting. The
purchase price was allocated to assets acquired and liabilities assumed based on
the estimated fair market value at the date of acquisition. The allocation of
the purchase price is as follows:

(5) 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

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

certain intangibles with indefinite lives exceeds their fair values. Orion Power
adopted the provisions of the statement, which apply to goodwill and intangible
assets acquired prior to June 30, 2001 on January 1, 2002, and thus Orion Power
discontinued amortizing goodwill into its results of operations. A
reconciliation of 2001 reported net income and earnings per share to the amounts
adjusted for the exclusion of goodwill amortization with a comparison to 2002
and 2003 follows:

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

(1) Earnings per share were not affected by the exclusion of goodwill
amortization due to the immaterial nature of the amount in 2001. As of the
Merger date all the shares were purchased by Reliant Resources as such, no
earnings per share data is presented subsequent to the Merger date.

Intangibles. Other intangible assets consist of the following:

Orion Power's measurement of the fair value of other intangibles, except
contractual rights, was determined by Orion Power with the assistance of an
independent third party appraiser based on a weighted average approach
considering both an income approach, using future discounted cash flows, and a
market approach, using acquisition multiples, including price per megawatt,
based on publicly available data for recently completed transactions.

Orion Power recognizes specifically identifiable intangibles, including air
emissions regulatory allowances it has been issued or those it is entitled to be
allocated during the remaining useful lives of the plants, contractual rights
and obligations and FERC licenses for its hydroelectric plants, when specific
rights and contracts are acquired. Orion Power amortizes air emissions
regulatory allowances on a units-of-production basis as utilized. The
amortization of other intangibles, including FERC licenses, but excluding
contractual rights, are recorded on a straight-line basis over the lesser of
their contractual or estimated useful lives. Orion Power has no intangible
assets, other than goodwill, with indefinite lives recorded as of December 31,
2003. Therefore, all intangibles, except goodwill, are subject to amortization.

F-199

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Estimated amortization expense, excluding contractual rights and
obligations (see below), for the next five years is as follows (in millions):

2004........................................................ $36
2005........................................................ 19
2006........................................................ 15
2007........................................................ 13
2008........................................................ 11
---
Total..................................................... $94
===

In connection with the Merger, Orion Power recorded the fair value of
certain fuel and power contracts acquired. Orion Power estimated the fair value
of the contracts using forward pricing curves as of the acquisition date over
the life of each contract. Those contracts with positive fair value at the date
of acquisition (contractual rights) were recorded to intangible assets and those
contracts with negative fair values at the date of acquisition (contractual
obligations) were recorded to other long-term liabilities in the consolidated
balance sheet.

Contractual rights and contractual obligations are amortized to fuel
expense and revenues, as applicable, based on the estimated realization of the
fair value established on the acquisition date over the contractual lives. There
may be times during the life of the contract when accumulated amortization
exceeds the carrying value of the recorded assets or liabilities due to the
timing of realizing the fair value established on the acquisition date.

Orion Power amortized $26 million and $29 million of contractual rights and
contractual obligations, respectively, for a net amount of $3 million, for
February 20, 2002 through December 31, 2002. Orion Power amortized $28 million
and $33 million of contractual rights and contractual obligations, respectively,
for a net amount of $5 million during 2003. Estimated amortization of
contractual rights and contractual obligations, excluding Liberty's terminated
tolling agreement (see notes 7(a) and 14(c)), for the next five years is as
follows:

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Goodwill. The following table shows the composition of goodwill for
January 1, 2002 through February 19, 2002, February 20, 2002 through December
31, 2002 and 2003:

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

(1) Fair value adjustments related to the Merger were finalized in February
2003. See note 4.

As of December 31, 2002 and 2003, Orion Power had $105 million and $95
million, respectively, of net goodwill recorded in the consolidated balance
sheets that is deductible for United States income tax purposes for future
periods.

SFAS No. 142 requires goodwill to be tested at least annually and more
frequently in certain circumstances. The date of Orion Power's annual impairment
test was November 1 for 2002 and 2003. 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 to the carrying amount of
that goodwill, to measure the amount of the goodwill impairment, if any.

2002 Annual Goodwill Impairment Test. Orion Power performed an annual
impairment test in 2002 effective November 1, 2002. Based on the fair values
determined by management, with the assistance of an independent appraiser, Orion
Power recorded an impairment of $338 million in the fourth quarter of 2002. The
circumstances leading to the impairment include: a decline in recent acquisition
multiples (price per megawatt) for comparable assets sold due to a significant
increase in the number of assets held for sale across the market as energy
companies attempt to address capital and liquidity concerns; the constrained
development of efficient unregulated markets in which we operate due to
regulatory, capital and liquidity concerns; weaker prices for electric energy,
capacity and ancillary services; and market contraction.

July 2003 Goodwill Impairment Test. On July 9, 2003, Reliant Resources
entered into a definitive agreement to sell a power generation plant, Desert
Basin. The sale closed in October 2003. Orion Power did not own the plant. As a
result of the sale, Reliant Resources was required 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. Reliant Resources was also required to test the
recoverability of goodwill in the remaining wholesale energy reporting unit as
of July 2003.

As a result of the July 2003 test, Orion Power recognized an impairment of
$585 million (pre-tax and after-tax) in the third quarter of 2003. This
impairment was due to a decrease in the estimated fair value of Orion Power.
This change in fair value was primarily due to: reduced projected
commercialization opportunities related to its power generation assets; 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 its existing
portfolio as a result of lowering the estimates of the margins required to
induce new capacity to enter the markets; lower market and comparable public
company values data; and the level of working capital; partially offset by
reductions in

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Orion Power's projected commercial, operational and support groups costs and
lower projected operations and maintenance expense.

2003 Annual Goodwill Impairment Tests. Orion Power performed its annual
goodwill impairment test effective November 1, 2003 and determined that no
additional impairments of goodwill had occurred since July 2003.

Estimation of Fair Value. Orion Power estimates reporting unit fair value
based on a number of subjective factors, including: (a) appropriate weighting of
valuation approaches (income approach, market approach and comparable public
company approach), (b) projections about future power generation margins, (c)
estimates of future cost structure, (d) discount rates for Orion Power's
estimated cash flows, (e) selection of peer group companies for the public
company approach, (f) required level of working capital, (g) assumed terminal
value and (h) time horizon of cash flow forecasts.

The income approach used in the analyses is a discounted cash flow analysis
based on Orion Power's internal forecasts and contains numerous assumptions made
by management and the independent appraiser, any of which if changed could
significantly affect the outcome of the analyses. Orion Power believes the
income approach is the most subjective of the approaches.

Management has determined the fair value of Orion Power, with the
assistance of an independent appraiser. In determining the fair value of Orion
Power in 2003, the following key assumptions were made: (a) the markets in which
Orion Power operates will continue to be deregulated; (b) demand for electricity
will grow, which will result in lower reserve margins; (c) there will be a
recovery in electricity margins over time to a level sufficient such that
companies building new generation facilities can earn a reasonable rate of
return on their investment and (d) the economics of future construction of new
generation facilities will likely be driven by regulated utilities. As part of
this process, all of Orion Power's power generation facilities and those of
others in the regions in which Orion Power operates were modeled. The following
table summarizes certain of these significant assumptions:

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

(1) Depending on the region, the specific rate is projected to be somewhat
higher or lower.

(2) Based on the assumption in 2003 that regulated utilities will be the primary
drivers underlying the construction of new generation facilities, Orion
Power has assumed that the after-tax return on investment will yield a
return representative of a regulated utility's cost of capital (7.5%) rather
than that of an independent power producer (9.0%). Based on changes in
assumed market conditions, including regulatory rules, Orion Power has
changed the projected time horizon for substantially achieving the after-tax
return on investment to 2008-2012 (depending on region). Formerly, Orion
Power had assumed that the time horizon for substantially achieving this
rate of return was 2006-2010.

Potential Future Impairments of Goodwill. Because Orion Power recognized a
goodwill impairment in 2003, in the near future, if actual results of operations
are worse than projected or Orion Power's market outlook changes negatively,
Orion Power could have additional impairments of goodwill that would need to be
recognized. In addition, ongoing evaluations of the wholesale energy business
could result in decisions to mothball, retire or dispose of additional
generation assets, any of which could result in additional impairment charges
related to goodwill, impact Orion Power's fixed assets' depreciable lives or
result in fixed asset impairment charges.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(6) DERIVATIVE INSTRUMENTS

Orion Power is exposed to various market risks. These risks arise from the
ownership of assets and operation of the business. To the extent permitted by
the Orion MidWest and Orion NY credit agreements, Orion Power utilizes
derivative instruments such as futures, physical forward contracts and swaps to
mitigate the impact of changes in electricity, natural gas and fuel prices on
Orion Power's operating results and cash flows. Orion Power utilizes interest
rate swaps to mitigate the impact of changes in interest rates and other
financial instruments to manage various other market risks.

Reliant Resources has a risk control framework, which Orion Power is
subject to, designed to monitor, measure and define appropriate transactions to
hedge and manage the risk in its existing portfolio of assets and contracts and
to authorize new transactions. These risks fall into three different categories:
market risk, credit risk and operational risk. Orion Power believes that it has
effective procedures for evaluating and managing these risks to which it is
exposed. Key risk control activities include definition of appropriate
transactions for hedging, credit review and approval, credit and performance
risk measurement and monitoring, validation of transactions, portfolio valuation
and daily portfolio reporting including mark-to-market valuation, value-at-risk
and other risk measurement metrics. Orion Power seeks to monitor and control its
risk exposures through a variety of separate but complementary processes and
committees, which involve business unit management, senior management and
Reliant Resources' board of directors.

Derivatives primarily used by Orion Power are described below:

- Futures contracts are exchange-traded standardized commitments to
purchase or sell an energy commodity or financial instrument, or to make
a cash settlement, at a specific price and future date.

- Physical forward contracts are commitments to purchase or sell energy
commodities in the future.

- Swap agreements require payments to or from counterparties based upon the
differential between a fixed price and variable index price (fixed price
swap) or two variable index prices (variable price swap) for a
predetermined contractual notional amount. The respective index may be an
exchange quotation or an industry pricing publication.

- Option contracts convey the right to buy or sell an energy commodity or a
financial instrument at a predetermined price or settlement of the
differential between a fixed price and a variable index price or two
variable index prices.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Derivative assets and liabilities at December 31, 2002 and 2003 are as
follows:

(a) DERIVATIVE ACTIVITIES.

To reduce the risk from market fluctuations in the results of operations
and the resulting cash flows, Orion Power may enter into energy derivatives in
order to hedge some expected purchases of electric power, natural gas and other
commodities and sales of electric power (energy derivatives) to the extent
permitted by the Orion MidWest and Orion NY credit agreements. The energy
derivative portfolios are managed to complement the Orion Power asset portfolio,
reducing overall risks.

The fair values of Orion Power's derivative activities as of December 31,
2002 and 2003, are determined by (a) prices actively quoted, (b) prices provided
by other external sources or (c) prices based on models and other valuation
methods.

Cash flow hedge ineffectiveness for 2001, for January 1, 2002 through
February 19, 2002, February 20, 2002 through December 31, 2002 and 2003 was
immaterial. In addition, no component of the derivative instruments' gain or
loss was excluded from the assessment of effectiveness for January 1, 2002
through February 19, 2002, February 20, 2002 through December 31, 2002 and 2003.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Below is a reconciliation of Orion Power's net derivative assets
(liabilities) to accumulated other comprehensive income (loss), net of tax, as
of December 31, 2002 and 2003:

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

(1) As of December 31, 2003, Orion Power expects $1 million of accumulated other
comprehensive loss to be reclassified into the results of operations during
2004.

As of December 31, 2002 and 2003, the maximum length of time Orion Power is
hedging its exposure to the variability in future cash flows for forecasted
transactions, excluding the payment of variable interest on existing financial
instruments, is three years and two years, respectively. As of December 31, 2002
and 2003, the maximum length of time Orion Power is hedging its exposure to the
payment of variable interest rates is seven years and six years, respectively.

For a discussion of Orion Power's interest rate derivative instruments
designated as cash flow hedges, see note 7(b).

(b) CREDIT RISK.

Credit risk is inherent in Orion Power's commercial activities and relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. Reliant Resources has broad credit policies and parameters, to
which Orion Power is subject. Orion Power seeks to enter into contracts that
permit it to net receivables and payables with a given counterparty. Orion Power
also enters into contracts that enable it to obtain collateral from a
counterparty as well as to terminate upon occurrence of certain events of
default. The credit risk control organization establishes counterparty credit
limits. Reliant Resources employs tiered levels of approval authority for
counterparty credit limits, with authority increasing from the credit risk
control organization through senior management. Credit risk exposure is
monitored daily and the financial condition of Orion Power's counterparties is
reviewed periodically.

If any of Orion Power's counterparties failed to perform, Orion Power might
be forced to acquire alternative hedging arrangements or be required to replace
the underlying commitment at then-current market prices. In this event, Orion
Power might incur additional losses in addition to amounts owed to us by the
counterparty. For information regarding the tolling agreement related to
Liberty, see note 14(c).

For counterparties representing greater than 10% of Orion Power's total
credit exposure, see note 2(r).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(7) CREDIT FACILITIES, NOTES AND OTHER DEBT

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

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

(1) The weighted average stated interest rate is for borrowings outstanding as
of December 31, 2002 or 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) The entire balance outstanding under this credit agreement has been
classified as current as of December 31, 2002 and 2003. Included in the
outstanding amount as of December 31, 2003, is $2 million and $2 million of
scheduled principal payments, which were due in October 2003 and January
2004, respectively, for which no payment has been made. As interest payments
due in October 2003 and January 2004 were deferred, additional interest will
be charged on the past due interest amounts. Of the amount shown as current
under the Liberty credit agreement, $11 million matures within 12 months of
December 31, 2003. See below and note 14(c) for further discussion.

(4) As a result of the Merger, debt and interest rate swaps were adjusted to
fair market value as of the acquisition date. Included in the adjustment to
fair value of debt is $74 million and $66 million related to the Orion Power
Holdings senior notes as of December 31, 2002 and 2003, respectively.
Included in the adjustment to fair value of interest rate swaps is $42
million and $22 million related to the Orion MidWest and Orion NY credit
facilities, respectively, as of December 31, 2002. Included in the
adjustment to fair value of interest rate swaps is $28 million and $19
million related to the Orion MidWest and Orion NY credit facilities,
respectively, as of December 31, 2003. Included in interest expense is
amortization of $5 million and $8 million for valuation adjustments for debt
and $25 million and $17 million for valuation adjustments for interest rate
swaps, respectively, for 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 Orion Power Holdings'
subsidiaries have effective restrictions on their ability to pay dividends or
make intercompany loans and advances pursuant to their

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

financing arrangements. The amount of restricted net assets of Orion Power
Holdings' subsidiaries as of December 31, 2003 are approximately $2.7 billion.
Such restrictions are on the net assets of Orion Capital, Liberty and LEP. Orion
MidWest and Orion NY are indirect wholly-owned subsidiaries of Orion Capital.

Maturities. As of December 31, 2003, maturities of all facilities and
other debt were as follows (in millions):

2004........................................................ $ 136(1)
2005........................................................ 1,102(1)
2006........................................................ 10(1)
2007........................................................ 10(1)
2008........................................................ 11(1)
2009 and thereafter......................................... 612(1)
------
Subtotal.................................................. 1,881
Other items included in debt................................ 113
------
Total debt................................................ $1,994
======

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

(1) Included in the amounts for years 2004, 2005, 2006, 2007, 2008 and 2009 and
thereafter are $11 million, $9 million, $10 million, $10 million, $11
million and $211 million, respectively, related to the Liberty credit
agreement and which have all been classified as current liabilities in the
consolidated balance sheet as of December 31, 2003. See below and note 14(c)
for further discussion.

Debt Covenant Compliance. Orion Power was in compliance with all of its
debt covenants as of December 31, 2003, other than under the Liberty credit
agreement. See below for further discussion.

(a) BANKING OR CREDIT FACILITIES AND NOTES.

The following table provides a summary of the amounts owed and amounts
available as of December 31, 2003 under Orion Power's various committed credit
facilities and notes:

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

(1) With consent of the lenders, Liberty has chosen to defer the principal and
interest payments due October 2003 rather than draw on the $17 million
letter of credit posted as debt service reserve. See below and note 14(c)
for further discussion.

(2) As discussed below and in note 14(c), this amount is currently not available
to Liberty.

Orion Power Holdings Senior Notes. Orion Power Holdings has outstanding
$400 million aggregate principal amount of 12% senior notes. In connection with
the Merger, Orion Power Holdings recorded the senior notes at an estimated fair
value of $479 million. The $79 million premium is being amortized to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

interest expense using the effective interest rate method over the life of the
senior notes. The fair value of the senior notes was based on Reliant Resources'
incremental borrowing rates for similar types of borrowing arrangements as of
the acquisition date. The senior notes are senior unsecured obligations of Orion
Power Holdings. Orion Power Holdings is not required to make any mandatory
redemption or sinking fund payments with respect to the senior notes. However,
if at the time such principal or interest are due, dividends, loans or advances
are restricted under the Orion MidWest and Orion NY credit agreements, and funds
generated from Orion Power Holdings' other subsidiaries or from other sources
are insufficient, payment default under Orion Powers Holdings' senior notes may
occur unless Reliant Resources elects to invest additional funds in Orion Power
Holdings, which it is not obligated to do. The senior notes are not guaranteed
by any of Orion Power Holdings' subsidiaries. The senior notes indenture
contains covenants, which bind Orion Power Holdings and certain of its
subsidiaries, that include, among others, restrictions on (a) the payment of
dividends, (b) the incurrence of indebtedness and the issuance of preferred
stock, (c) investments, (d) asset sales, (e) liens, (f) transactions with
affiliates, (g) engaging in unrelated businesses and (h) sale and leaseback
transactions. See note 3.

Orion MidWest and Orion NY Credit Agreements. During October 2002, the
Orion Power Holdings revolving credit facility was prepaid and terminated, and
Orion Power refinanced the Orion MidWest and Orion NY credit agreements. In
connection with these refinancings, Orion Power applied excess cash of $145
million to prepay and terminate the Orion Power Holdings revolving credit
facility and to reduce the term loans and revolving working capital facilities
at Orion MidWest and Orion NY. As of the refinancing date, the amended and
restated Orion MidWest credit agreement included a term loan of approximately
$974 million and a $75 million revolving working capital facility. As of the
refinancing date, the amended and restated Orion NY credit agreement included a
term loan of approximately $353 million and a $30 million revolving working
capital facility. As of December 31, 2002 and 2003, Orion MidWest had $969
million and $884 million, respectively, of term loans outstanding. As of
December 31, 2002 and 2003, Orion NY had $351 million and $334 million,
respectively, of term loans outstanding. The refinancing included an extension
of the maturities of the Orion MidWest and Orion NY credit agreements by three
years to October 2005.

The loans under each facility bear interest at LIBOR plus a margin or at a
base rate plus a margin. The LIBOR margin is 2.75% as of December 31, 2003 and
increases to 3.25% in April 2004 and 3.75% in October 2004. The base rate margin
is 1.75% as of December 31, 2003 and increases to 2.25% in April 2004 and 2.75%
in October 2004.

The amended and restated Orion MidWest credit agreement is secured by a
first lien on substantially all of the assets of Orion MidWest and its
subsidiary. Orion NY and its subsidiaries are guarantors of the Orion MidWest
obligations under the amended and restated Orion MidWest credit agreement. A
substantial portion of the assets of Orion NY and its subsidiaries (excluding
certain plants) are pledged, via a second lien, as collateral for this
guarantee. The amended and restated Orion NY credit agreement is, in turn,
secured by a first lien on a substantial portion of the assets of Orion NY and
its subsidiaries (excluding certain plants). Orion MidWest and its subsidiary
are guarantors of the Orion NY obligations under the amended and restated Orion
NY credit agreement. Substantially all of the assets of Orion MidWest and its
subsidiary are pledged, via a second lien, as collateral for this guarantee.
Orion MidWest's and Orion NY's obligations under the respective agreements are
non-recourse to Orion Power Holdings.

Both the Orion MidWest and Orion NY credit agreements contain affirmative
and negative covenants, including negative pledges, that must be met by each
borrower under its respective facility to borrow funds or obtain letters of
credit, and which require Orion MidWest and Orion NY to maintain a combined debt
service coverage ratio of 1.5 to 1.0. These covenants are not anticipated to
materially restrict either borrower's ability to borrow funds or obtain letters
of credit. The agreements also provide for any available

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

cash at one borrower to be made available to the other borrower to meet
shortfalls in the other borrower's ability to make certain payments, including
operating costs. This is effected through distributions of such available cash
to Orion Capital, a direct subsidiary of Orion Power Holdings formed in
connection with the refinancing. Orion Capital, as indirect owner of each of
Orion MidWest and Orion NY, can then contribute such cash to the other borrower.
The ability of the borrowers to make dividends, loans or advances to Orion Power
Holdings for interest payments or otherwise is restricted. In any event, no
distributions may be made after October 28, 2004 until the earlier of maturity
or retirement. No distributions are anticipated during the remaining terms of
the credit agreements. Any restricted cash, which is not dividended, will be
applied on a quarterly basis to prepay outstanding loans at Orion MidWest and
Orion NY. See note 2(l) for a detail of restricted cash under the Orion MidWest
and Orion NY credit agreements. In addition, the Orion MidWest and Orion NY
credit agreements contain operational covenants governing the commercial terms
of transactions to purchase or sell fuel and energy related products with
Reliant Energy Services and third parties.

Liberty Credit Agreement. In July 2000, LEP and Liberty, indirect
wholly-owned subsidiaries of Orion Power Holdings, 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 in an amount of up to $41 million. In May 2002, the
construction loans were converted to term loans. On the conversion date, Orion
Power Holdings 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
Holdings as credit support was canceled.

The floating rate loans under the Liberty credit agreement bear interest at
LIBOR plus a margin or a base rate plus margin. For the floating rate term loan,
as of December 31, 2003, the LIBOR margin is 1.25% and increases to 1.375% in
May 2005 and 1.625% in May 2008. As of December 31, 2003, the base rate margin
is 0.25% and increased to 0.375% in May 2005 and 0.625% in May 2008. For the
revolving working capital facility, as of December 31, 2003, the LIBOR margin is
1.25% and increases to 1.375% in May 2005. As of December 31, 2003, the base
rate margin is 0.25% and increases to 0.375% in May 2005.

The lenders under the Liberty credit agreement have a security interest in
substantially all of the assets of Liberty and LEP. The outstanding borrowings
related to the Liberty credit agreement are non-recourse to Orion Power Holdings
and all other subsidiaries. The Liberty credit agreement contains affirmative
and negative covenants, including a negative pledge that must be met to borrow
funds or obtain letters of credit. Liberty is currently unable to access the
revolving working capital facility. Additionally, the Liberty credit agreement
restricts Liberty's ability to, among other things, make dividend distributions
unless Liberty satisfies various conditions. See note 2(l) for a detail of
restricted cash under the Liberty credit agreement.

Given that Liberty is currently in default under the credit agreement,
Orion Power has classified the debt as a current liability. Neither Orion Power
Holdings nor any other of its subsidiaries is in default under other debt
agreements due to the credit agreement default at Liberty. See note 14(c).

(b) INTEREST RATE DERIVATIVE INSTRUMENTS.

In connection with the Merger, 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 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 Reliant Resources'
incremental borrowing rates at the acquisition date for similar types of
borrowing arrangements. The value

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of the debt component is amortized to interest expense as interest rate swap
payments are made. See note 6 regarding Orion Power's derivative financial
instruments.

Orion Power has entered into a number of interest rate swap contracts
having an aggregate notional amount of $250 million as of December 31, 2002 and
2003, that hedge the floating interest rate risk associated with the floating
rate long-term debt under the Orion NY credit agreement. As of December 31,
2003, floating rate LIBOR-based interest payments are exchanged for weighted
fixed rate interest payments of 7.13% for the Orion NY credit agreement. Orion
Power has entered into interest rate swap contracts having an aggregate notional
amount of $600 million and $300 million as of December 31, 2002 and 2003,
respectively, that hedge the floating interest rate risk associated with the
floating rate long-term debt under the Orion MidWest credit agreement. As of
December 31, 2003, floating rate LIBOR-based interest payments are exchanged for
weighted fixed rate interest payments of 7.66% for the Orion MidWest credit
agreement. 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 6 for further discussion of Orion Power's cash flow hedges.

(8) STOCKHOLDERS' EQUITY

The Merger (see note 1) resulted in the purchase by Reliant Resources of
all of Orion Power Holdings' outstanding shares of common stock. Subsequently,
all of Orion Power Holdings' common stock was beneficially owned by Reliant
Resources.

In the Merger, a wholly-owned subsidiary of Reliant Resources (Merger
Subsidiary) was merged into Orion Power Holdings. Orion Power Holdings was the
surviving entity. In accordance with the Merger, effective on February 19, 2002,
Orion Power Holdings converted each issued and outstanding share of common
stock, par value $0.01, into the right to receive $26.80 per share in cash
resulting in the cancellation of all issued and outstanding shares, warrants and
options of Orion Power Holdings. Additionally, each share of common stock of
Merger Subsidiary, par value $1.00 per share, issued and outstanding immediately
prior to February 19, 2002 was converted into one share of common stock of Orion
Power Holdings. As of December 31, 2002 and 2003, Orion Power had 1,000 shares
authorized, issued and outstanding with a par value of $1.00 per share.

The following describes Orion Power's equity transactions prior to the
Merger:

The Second Amended and Restated Stockholder's Agreement (the Agreement)
dated November 5, 1999 stated that at the time of a capital call, Orion Power
Holdings would issue warrants to GS Capital Partners II, L.P. (GSCP) and
Constellation Power Source, Inc. (CPS) for shares of Orion Power Holdings common
stock in accordance with certain formulas, as defined in the Agreement. Under
the terms of the original stockholder's agreement between CPS and GSCP, only
GSCP was entitled to receive warrants. The warrants had an exercise price equal
to the subscription price of the common stock ($10.00 or $15.50) and expire on
the tenth anniversary of their issuance. The warrant holder may exercise the
warrants for an equivalent number of shares of Orion Power Holdings common stock
when accompanied by payment of the full exercise price. The warrant holder may
also exercise the warrant without payment and would be entitled to a number of
shares of Orion Power Holdings common stock equivalent to (a) the difference
between the aggregate Current Market Price, as defined, less the aggregate
exercise price, divided by (b) the Current Market Price of one share of common
stock. As of December 31, 2001, 705,900 warrants had been issued to
Constellation Holdings, Inc. No warrants had been exercised as of December 31,
2001. No more capital is subject to call under this agreement and no more
warrants are issuable subsequent to the Merger.

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

On June 6, 2001, Orion Power Holdings completed a $356 million common stock
offering, comprised of 10,400,000 shares sold by Orion Power Holdings and
2,600,000 shares sold by certain selling stockholders at a gross per share
offering price of $27.35, resulting in net proceeds of approximately $273
million. Concurrent with this offering, Orion Power Holdings completed a $200
million offering of 4.50% convertible senior notes.

(9) STOCK OPTION PLAN

In May 1998, Orion Power Holdings adopted the 1998 Stock Incentive Plan
(the plan), which provided for granting of stock options and other equity based
awards to directors, officers, employees and consultants. The plan, as amended,
provided that up to 7,500,000 shares of common stock may be issued pursuant to
such options and other awards. Stock options were granted at an exercise price
as determined by the board of directors or a committee designated by the board
of directors, were exercisable in installments beginning one year from the date
of grant and expired 10 years after the date of grant. The plan permitted the
issuance of either incentive stock options or non-qualified stock options. The
Merger resulted in the cancellation of all of the outstanding shares, warrants
and options of Orion Power Holdings, and as such, the plan was canceled.

Orion Power Holdings granted options to acquire shares of its common stock
at an exercise price less than the fair value of its common stock. As of
December 31, 2001, Orion Power Holdings recognized deferred compensation of $5
million to be amortized over the three-year vesting period. Compensation expense
related to these options of $2 million was recorded for 2001.

The following summarizes options granted to directors, officer and
employees:

Exercise prices for options outstanding as of December 31, 2001, ranged
from $10 to $29.80. The following table provides certain information with
respect to stock options outstanding at December 31, 2001:

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table provides certain information with respect to stock
options exercisable at December 31, 2001:

The weighted average fair value at date of grant for options granted during
2000 and 2001 were $15.60 and $9.64, respectively, and was estimated using the
Black-Scholes option valuation model with the following weighted average
assumptions:

(10) EARNINGS PER SHARE

The following table presents the basic and diluted earnings per share (EPS)
calculation for 2001. As of December 31, 2002 and 2003, all of Orion Power
Holdings' common stock was beneficially owned by Reliant Resources and
therefore, EPS data is not presented for 2002 or 2003 (in thousands, except per
share amounts):

Net income -- for basic EPS................................. $100,603
Effect of dilutive securities:
Convertible securities................................. 3,414
--------
Net Income -- for diluted EPS............................... $104,017
========
Diluted Weighted Average Shares Calculation:
Weighted average shares outstanding......................... 99,071
Plus: Incremental shares from assumed conversions:
Stock options.......................................... 1,163
Warrants............................................... 3,936
Convertible securities................................. 3,414
--------
Weighted average shares assuming dilution................... 107,584
========
Basic EPS................................................. $ 1.02
Diluted EPS............................................... 0.97

(11) RETIREMENT AND OTHER BENEFIT PLANS

(A) PENSION.

Orion Power sponsors multiple noncontributory defined benefit pension plans
covering certain union and non-union employees. Depending on the plan, the
benefit payment is either based on years of service

F-212

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

with final average salary and covered compensation, or in the form of a cash
balance account which grows based on a percentage of annual compensation and
accrued interest.

Orion Power's funding policy is to review amounts annually in accordance
with applicable regulations in order to determine contributions necessary to
achieve adequate funding of projected benefit obligations. Orion Power uses a
December 31 measurement date for its plans. The pension obligation and funded
status are as follows:

Amounts recognized in the consolidated balance sheets are as follows:

The accumulated benefit obligation for all defined benefit plans was $39
million and $46 million at December 31, 2002 and 2003, respectively.

F-213

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net pension cost includes the following components:

The significant weighted average assumptions used to determine the pension
benefit obligation include the following:

The significant weighted average assumptions used to determine the net
pension cost include the following:

As of December 31, 2003, Orion Power's expected long-term rate of return on
pension plan assets is developed based on third party models. These models
consider expected inflation, current dividend yields, expected corporate
earnings growth and risk premiums based on the expected volatility of each asset
category. The expected long-term rates of return for each asset category are
weighted to determine the overall expected long-term rate of return on pension
plan assets. In addition, peer data and historical returns are reviewed.

F-214

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Orion Power's pension plan weighted average asset allocations at December
31, 2002 and 2003 and target allocation for 2004 by asset category are as
follows:

In managing the investments associated with the pension plans, Orion
Power's objective is to exceed, on a net-of-fee basis, the rate of return of a
performance benchmark composed of the following indices:

As a secondary measure, asset performance is compared to the returns of a
universe of comparable funds, where applicable, over a full market cycle.

During 2001, January 1, 2002 through February 19, 2002, February 20, 2002
through December 31, 2002 and 2003, Orion Power made cash contributions of $8
million, $1 million, $5 million and $9 million, respectively, to the pension
plans. Orion Power expects cash contributions to approximate $9 million during
2004.

Information for pension plans with an accumulated benefit obligation in
excess of plan assets is as follows:

Two of Orion Power's pension plans were amended on October 15, 2002. A
third plan contained the following features: subsidized optional forms of
benefits, an early retirement subsidy and a provision for a cost of living
adjustment increase, while the other plans did not include these features. The
two plans were amended to include these additional features. This resulted in a
$2 million increase in the projected benefit obligation in 2002. One of Orion's
pension plans was amended on July 23, 2003 to provide certain plan design
changes in accordance with a collective bargaining agreement, and was amended
again on October 9, 2003 to make certain design changes to the forms of pension
distributions under the plan. This resulted in a $0.7 million increase in the
projected benefit obligation in 2003.

F-215

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) SAVINGS PLAN.

Orion Power has an employee savings plan that is a tax-qualified plan under
Section 401(a) of the Internal Revenue Code of 1986, as amended (Code), and
includes a cash or deferred arrangement under Section 401(k) of the Code for all
Orion Power employees.

Under the plan, participating employees may contribute a portion of their
compensation, pre-tax or after-tax, generally up to a maximum of 18% of
compensation. Orion Power's savings plan matching contribution, any payroll
period discretionary employer contribution and any discretionary annual employer
contribution will be made in cash.

Orion Power's savings plan benefit expense was $8.1 million, $0.4 million,
$1.6 million and $1.5 million in 2001 and for January 1, 2002 through February
19, 2002, February 20, 2002 through December 31, 2002 and 2003, respectively.

(c) POSTRETIREMENT BENEFITS.

Orion Power funds the postretirement benefits on a pay-as-you-go basis.
Orion Power uses a December 31 measurement date for its plans.

Accumulated postretirement benefit obligation and funded status are as
follows:

Amounts recognized in the consolidated balance sheets are as follows:

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Net postretirement benefit cost includes the following components:

The significant weighted average assumptions used to determine the
accumulated postretirement benefit obligation include the following:

The significant weighted average assumptions used to determine the
accumulated postretirement benefit cost include the following:

The following table shows Orion Power's assumed health care cost trend
rates used to measure the expected cost of benefits covered by its
postretirement plan:

F-217

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Assumed health care cost trend rates have a significant effect on the
amounts reported for Orion Power's health care plans. A one-percentage-point
change in assumed health care cost trend rates would have the following effects
as of December 31, 2003:

In December 2003, the Medicare Prescription Drug, Improvement and
Modernization Act of 2003 became law. This law introduces a prescription drug
benefit, as well as a federal subsidy under certain circumstances to sponsors of
retiree health care benefit plans. In January 2004, the FASB issued FASB Staff
Position No. 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003." This
FASB staff position permits sponsors of postretirement health care plans that
provide a prescription drug benefit to make a one time election to defer
accounting for the effects of this law until the earlier of: (a) the issuance of
authoritative guidance on accounting for the federal subsidy or (b) the
occurrence of a significant event that would call for remeasurement of a plan's
assets and obligations, such as a plan amendment, settlement or curtailment.
Orion Power has elected to defer accounting for the effects of this law. The
measurements of Orion Power's accumulated postretirement benefit obligation and
net periodic postretirement benefit cost do not reflect the effect of this law.
When authoritative guidance on accounting for the federal subsidy is issued,
Orion Power will revise its accounting as required.

(d) POSTEMPLOYMENT BENEFITS.

Orion Power records postemployment benefits based on SFAS No. 112,
"Employer's Accounting for Postemployment Benefits," which requires the
recognition of a liability for benefits provided to former or inactive
employees, their beneficiaries and covered dependents, after employment but
before retirement (primarily health care and life insurance benefits for
participants in the long-term disability plan). Net postemployment benefit costs
were insignificant for 2001 and 2002 and $1 million for 2003.

(e) OTHER EMPLOYEE MATTERS.

As of December 31, 2003, approximately 68% of Orion Power's employees are
subject to collective bargaining agreements. The agreements covering 62% of
those employees will expire prior to December 31, 2004.

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ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(12) INCOME TAXES

Orion Power's current and deferred components of income tax expense
(benefit) were as follows:

A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

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

(1) Not meaningful as for February 20, 2002 through December 31, 2002 and 2003,
Orion Power had a pre-tax loss of $217 million and $556 million,
respectively, and income tax expense of $40 million and $2 million,
respectively. The primary reason is due to Orion Power's goodwill
impairments for February 20, 2002 through December 31, 2002 and 2003 of $338
million and $585 million, respectively, for which no tax benefit can be
recognized, as the goodwill is non-deductible.

F-219

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Following were Orion Power's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the consolidated financial
statements and their respective tax bases:

Tax Attribute Carryovers. As of December 31, 2003, Orion Power had state
net operating loss carryovers of $467 million, which are due to expire in tax
years 2015 through 2023.

During 2002, a valuation allowance of $30 million was established as part
of purchase accounting (see note 4). This valuation allowance resulted from
Orion Power's assessment of its future ability to use state net operating
losses. During 2003, Orion Power increased its valuation allowance to $34
million, which results primarily from the assessment of Orion Power's future
ability to use state net operating losses.

(13) COMMITMENTS

(A) LEASE COMMITMENTS.

Orion Power has entered into various non-cancelable operating lease
arrangements for office space, storage space, office furniture and vehicles.
These leases terminate at various dates through 2022.

F-220

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Future minimum payments due under these leases are as follows (in
thousands):

In November 1999, Erie Boulevard entered into a capital lease arrangement
for the land at the Watertown hydroelectric plant located in Potsdam, New York.
This land houses a maintenance facility and a regional headquarters for the
hydroelectric assets. The lease began at the completion of the facility, in
October 2000, and expires in 2015. Under the terms of the lease, the monthly
payments are $10,500. Erie Boulevard has the option to purchase the land for
$450,000 at the end of the lease term.

Total rental expense for 2001, for January 1, 2002 through February 19,
2002, February 20, 2002 through December 31, 2002 and 2003, was $1.8 million,
$0.2 million, $1.6 million and $2.0 million, respectively.

(b) FUEL CONTRACTS AND TRANSPORTATION COMMITMENTS.

Orion Power is a party to fuel supply contracts and commodity
transportation contracts, that have various quantity requirements and durations
that are not classified as derivative assets and liabilities and hence are not
included in the consolidated balance sheet as of December 31, 2003. Minimum
purchase commitment obligations under these agreements are as follows, as of
December 31, 2003:

As of December 31, 2003 the maximum remaining terms under any individual
fuel supply contract and transportation contract is four years and 10 years,
respectively.

(c) PROVIDER OF LAST RESORT CONTRACTS.

One of Orion Power Holdings' subsidiaries is contractually obligated
through the end of 2004 to provide energy to Duquesne Light Company to satisfy
the demands of any customer in its service area that purchases power from
Duquesne Light Company as its "provider of last resort." These contracts do not
F-221

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

specify a minimum or maximum quantity of energy to be supplied. Although Orion
Power expects to produce more energy than needed to meet these contractual
obligations, it is possible that, due to seasonal variations in demand or
operational outages, its subsidiary may occasionally need to purchase energy
from third parties to cover its contractual obligations. Since these events are
likely to occur at times of higher market prices, Orion Power is at risk that
the cost of power purchased may exceed the fixed prices for power under
contracts with Duquesne Light Company. Failure to provide sufficient energy
under the terms of the contracts could give rise to, in addition to other direct
damages, penalties of up to $1,000 per megawatt hour, depending upon the
circumstances of such under delivery. During the period February 20, 2002
through December 31, 2002 and 2003, Orion Power did not incur or pay any
penalties.

(d) COLLATERAL POSTING PROVIDED BY RELIANT RESOURCES.

As a result of credit rating downgrades in the first quarter of 2003,
collateral requirements, which are based on a contractual provision relating to
creditworthiness and market exposure, were triggered pursuant to a provision in
a power contract between Orion MidWest and one of its customers, which required
Orion Power to provide collateral of approximately $16 million. On July 30,
2003, this collateral was posted by Reliant Resources on Orion MidWest's behalf.
There is no obligation by Orion MidWest to repay this collateral to Reliant
Resources. As of December 31, 2003, there have been no changes to the collateral
posted by Reliant Resources on Orion MidWest's behalf.

(e) GUARANTEE.

Together with certain of Reliant Resources' other subsidiaries, Orion Power
Holdings is a guarantor of the obligations under Reliant Resources' Amended and
Restated Credit and Guaranty Agreement dated as of March 28, 2003, subject to
certain limitations under Orion Power Holdings' senior notes. These limitations
limit the amount of the guarantee based on a fixed charge coverage ratio,
consolidated tangible assets and a restricted payment ceiling test, under the
Orion Power Holdings senior notes. Additionally, Orion Power Holdings is the
only limited guarantor of the obligations under Reliant Resources' senior
secured notes issued in July 2003, subject to the same limitations. None of
Orion Power Holdings' subsidiaries guarantee Reliant Resources' senior secured
notes.

Reliant Resources has calculated the aggregate amount permitted to be
guaranteed under both the guarantee for its March 2003 credit facility and the
guarantee for its senior secured notes to be approximately $1.1 billion, which
is the maximum potential amount of future payments. These guarantees mature at
varying dates from 2007 to 2013.

Both Reliant Resources' March 2003 credit facility and its senior secured
notes restrict Orion Power Holdings and its subsidiaries ability to take
specific actions, subject to numerous exceptions that are designed to allow for
the execution of Reliant Resources' and its subsidiaries' business plans in the
ordinary course, including the preservation and optimization of existing
investments in the retail energy and wholesale energy businesses and the ability
to provide credit support for commercial obligations. Orion Power's failure to
comply with these restrictions could result in an event of default under the
Reliant Resources' March 2003 credit facility or its senior secured notes that,
if not cured or waived, could result in Reliant Resources being required to
repay its borrowings before their due date.

(14) CONTINGENCIES

(A) LEGAL AND ENVIRONMENTAL MATTERS.

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 Orion Power's evaluations with assistance from

F-222

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

third-party consultants and engineers, Orion Power has developed remediation
plans for both facilities. As of December 31, 2002 and 2003, Orion Power has
recorded the estimated liability for the remediation costs of $8 million and $7
million, respectively, which it expects to pay out through 2008.

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, Orion Power
estimates that capital expenditures necessary to comply with the order could
equal or exceed $87 million. Orion Power expects 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 December
31, 2002 and 2003, the total estimated liability determined by management with
assistance from third-party engineers and recorded by Orion Power for these
disposal sites was $14 million and $11 million, respectively, of which $1
million is to be paid over the next five years.

New Source Review Matters. The United States Environmental Protection
Agency (EPA) has requested information from two Orion Power facilities, related
to work activities conducted at the sites that may be associated with various
permitting requirements of the Clean Air Act. Orion Power has responded to the
EPA's requests for information. Furthermore, the New York state attorney
general's office recently requested from the EPA a copy of all such
correspondence relating to all facilities, which the EPA granted.

Other Matters. Orion Power is involved in a number of other legal,
environmental and other proceedings before courts and governmental agencies.
Although Orion Power cannot predict the outcome of these proceedings, Orion
Power believes that the effects on the financial statements, if any, from the
disposition of these matters will not have a material adverse effect on its
results of operations, financial condition or cash flows.

(b) TOLLING AGREEMENT FOR LIBERTY'S GENERATING STATION.

LEP owns a 530 MW combined cycle gas fired power generation facility (the
Liberty generating station). Liberty financed the construction costs of the
Liberty generating station with borrowings under a credit agreement of which
$262 million is outstanding as of December 31, 2003. Borrowings under the credit
agreement, which are non-recourse to Orion Power and its affiliates (other than
LEP and Liberty), are secured by pledges of the assets of the Liberty generating
station and of the ownership interest in LEP. See note 7(a).

In July 2003, the counterparty to the tolling agreement under which LEP
sold the generation output of the Liberty generation station filed for
bankruptcy. Subsequently, a federal bankruptcy court issued an order that
terminated the tolling agreement and triggered another event of default under
the Liberty credit agreement. The default under the Liberty credit agreement,
and the possible foreclosure by the lenders upon the assets of the Liberty
generating station, do not constitute an event of default under any other debt
agreements of Orion Power or its affiliates.

F-223

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

To date, the lenders under the Liberty credit agreement have not foreclosed
upon the Liberty generating station. However, there can be no assurance that the
lenders will continue to refrain from exercising such rights. If the lenders
elect to foreclose on LEP, Liberty and/or the Liberty generating station, Orion
Power could incur a pre-tax loss of an amount up to Orion Power's recorded net
book value, with the potential of an additional loss due to an impairment of
goodwill to be allocated to LEP. As of December 31, 2003, the combined net book
value of LEP and Liberty was $346 million, excluding the non-recourse debt
obligations of $262 million. At December 31, 2002 and 2003, Orion Power
evaluated the Liberty generating station and the related intangible asset for
the terminated tolling agreement for impairment. Based on the analyses, there
were no impairments.

In September 2003, LEP sued the corporate guarantor of the counterparty to
the tolling agreement, Gas Transmission Northwest Corporation, seeking payment
of $140 million (the maximum amount of the guarantee) out of the $177 million
termination claim calculated by LEP under the agreement. Subsequently, the
counterparty to the tolling agreement and its corporate guarantors countersued
LEP seeking to collect a $108 million termination payment under the tolling
agreement. The obligations of LEP under the tolling agreement are secured by a
$35 million letter of credit issued under the senior secured revolver of Reliant
Resources. If the letter of credit were to be drawn, Reliant Resources would be
required to reimburse the issuing bank.

In light of current market conditions and the termination of the tolling
agreement, LEP does not expect to have sufficient cash flow to pay both (a) all
of its expenses and to post the collateral required to buy fuel or in respect of
the gas transportation agreements and (b) debt service obligations. Liberty
received temporary deferrals until April 2004 from its lenders for the quarterly
principal installments that were due in October 2003 and January 2004, which
aggregated $4 million. Based on the foregoing, Orion Power is exploring various
strategic options with respect to its subsidiaries' interest in the Liberty
generating station, including, among other things, the execution of a
foreclosure arrangement with the lenders resulting in a transfer of ownership to
the lenders or a sale of Orion Power's interest in the generating station. There
can be no assurances regarding the outcome of this process. A foreclosure of
Orion Power's interest in the generation station would, however, result in an
impairment of the asset on the balance sheet.

If LEP recovers the amount of the termination claim, the lenders are
entitled to require that such amounts be used to pay deferred interest and to
prepay debt under the Liberty credit agreement. Under United States and
Pennsylvania tax laws, it is possible that receipt of a termination payment by
LEP could be deemed taxable income to Orion Power Holdings and its other
subsidiaries.

(15) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of financial instruments, including cash and cash
equivalents and derivative assets and liabilities (see note 6), are equivalent
to their carrying amounts in the consolidated balance sheets. The fair values of
derivative assets and liabilities as of December 31, 2002 and 2003 have been
determined using quoted market prices for the same or similar instruments when
available or other estimation techniques, see note 6.

F-224

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The carrying values and related fair market values of Orion Power's
short-term and long-term debt are detailed as follows (excluding adjustment to
fair value of interest rate swaps and debt under Liberty's credit agreement):

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

(1) Excludes Liberty's fixed rate debt of $165 million and floating rate debt of
$103 million and $97 million as of December 31, 2002 and 2003, respectively,
as there was no active market for this debt. Due to the situation with
Liberty (see note 14(c)), if the holders of Liberty's debt were to have
tried to sell such debt instrument to a third party, the price which could
have been realized would likely be substantially less than the face value of
the debt instrument and substantially less than the carrying value.

(2) As of December 31, 2002, Orion Power had floating rate debt with a carrying
value of $1.4 billion, excluding adjustment to fair value of interest rate
swaps and Liberty's debt. There was no active market for Orion Power's
floating rate debt obligations as of December 31, 2002. Given the liquidity
and credit situation as of December 31, 2002, if the holders of these
borrowings were to have tried to sell such debt instruments to third
parties, the prices which could have been realized could have been
substantially less than the face values of the debt instruments and
substantially less than Orion Power's carrying values.

(3) The fair market values of the fixed rate debt (December 31, 2002 and 2003)
and floating rate debt (for December 31, 2003 only) were based on (a)
Reliant Resources' incremental borrowing rates for similar types of
borrowing arrangements or (b) information from market participants. For $1.2
billion of our floating rate debt, the carrying value equals the fair market
value as of December 31, 2003.

(16) UNAUDITED QUARTERLY INFORMATION

Summarized unaudited quarterly information is as follows:

F-225

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The variances in revenues from quarter to quarter for 2002 and 2003 were
primarily due to (a) the Merger and the related purchase accounting, see note 1,
(b) the seasonal fluctuations in demand for electric energy and energy services
and (c) changes in energy commodity prices. Changes in operating income (loss)
and net income (loss) from quarter to quarter for 2002 and 2003 were primarily
due to:

- the seasonal fluctuations in demand for electric energy and energy
services;

- $2 million, net of tax, cumulative effect of accounting change primarily
in the first quarter of 2003 (only impacted net loss) (see note 2(p));

- the impact of an increase in allocated general and administrative costs
from affiliate;

- changes in energy commodity prices; and

- the timing of maintenance expenses on electric generation plants.

In addition, operating income (loss) and net income (loss) changed from
quarter to quarter in 2002 by:

- the impact of the Merger (see note 4);

- costs related to plant cancellations and equipment impairments in 2002;
and

- $338 million goodwill impairment in the fourth quarter of 2002 (see note
5).

- Also, operating income (loss) and net income (loss) changed from quarter
to quarter in 2003 by the $585 million goodwill impairment in the third
quarter of 2003 (see note 5).

* * *

F-226

The following is a copy of a report previously issued by Arthur Andersen LLP
(Andersen). The report has not been reissued by Andersen.

REPORT OF INDEPENDENT PUBLIC ACCOUNTANTS

To Orion Power Holdings, Inc.:

We have audited in accordance with auditing standards generally accepted in
the United States, the consolidated financial statements of Orion Power
Holdings, Inc. and subsidiaries, incorporated by reference in this Form 10-K,
and have issued our report thereon dated February 19, 2002. Our audit was made
for the purpose of forming an opinion on the basic consolidated financial
statements taken as a whole. The schedule listed in the index of financial
statements is the responsibility of the company's management and is presented
for the purposes of complying with the Securities and Exchange Commission's
rules and is not part of the basic consolidated financial statements. This
schedule has been subjected to the auditing procedures applied in the audit of
the basic consolidated financial statements and, in our opinion, fairly states
in all material respects the financial data required to be set forth therein in
relation to the basic consolidated financial statements taken as a whole.

/s/ ARTHUR ANDERSEN LLP

Vienna, Virginia
February 19, 2002

F-227

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF OPERATIONS

See Notes to the Condensed Financial Statements and Orion Power's Consolidated
Financial Statements
F-228

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
CONDENSED BALANCE SHEETS

See Notes to the Condensed Financial Statements and Orion Power's Consolidated
Financial Statements
F-229

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
CONDENSED STATEMENTS OF CASH FLOWS

See Notes to the Condensed Financial Statements and Orion Power's Consolidated
Financial Statements
F-230

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

These condensed parent company financial statements have been prepared in
accordance with Rule 12-04, Schedule 1 of Regulation S-X, as the restricted net
assets of Orion Power Holdings, Inc.'s . (Orion Power Holdings) subsidiaries
exceed 25% of the consolidated net assets of Orion Power Holdings. This
information should be read in conjunction with the Orion Power Holdings and
subsidiaries (Orion Power) consolidated financial statements included elsewhere
in this filing.

Orion Power Holdings' 100% investments in its subsidiaries have been
recorded using the equity basis of accounting in the accompanying condensed
parent company financial statements. Included in equity in earnings (loss) of
investments in subsidiaries in 2003 is a cumulative effect of accounting change
for a new accounting pronouncement as more fully described in note 2(p) to Orion
Power's consolidated financial statements.

Some amounts from the previous years have been reclassified to conform to
the 2003 presentation of condensed financial information. These
reclassifications do not affect earnings.

For the 2001 cash flow statement, Orion Power Holdings has presented
amortization of deferred financing fees separately from depreciation and
amortization.

(2) CONTRIBUTIONS FROM STOCKHOLDER

In May 2003 and November 2003, Reliant Resources, Inc. (Reliant Resources)
contributed $15 million and $20 million, respectively, to Orion Power Holdings,
as a partial funding of the semi-annual interest payment of $24 million on the
senior notes due in each of May 2003 and November 2003. While Reliant Resources
has no obligation, it intends to contribute any funding shortfall for the
semi-annual interest payments due in May 2004 and November 2004 should Orion
Power Holdings' funds be insufficient. See notes 3 and 7 to Orion Power's
consolidated financial statements.

(3) RESTRICTED NET ASSETS OF SUBSIDIARIES

Certain of Orion Power Holdings' 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
Orion Power Holdings' subsidiaries at December 31, 2002 and 2003 is
approximately $2.2 billion and $2.7 billion, respectively. Such restrictions are
on the net assets of Orion Power Capital, LLC Liberty Electric PA, LLC and
Liberty Electric Power, LLC. Orion Power Midwest, LP and Orion Power New York,
LP are indirect wholly-owned subsidiaries of Orion Power Capital, LLC.

(4) DEBT FACILITIES

For a discussion of Orion Power Holdings' senior notes, which are due in
2010, see note 7 to Orion Power's consolidated financial statements.

(5) COMMITMENTS AND CONTINGENCIES

(A) GUARANTEES

Orion Power Holdings has issued guarantees in conjunction with certain
performance agreements and commodity and derivative contracts and other
contracts that provide financial assurance to third parties on behalf of a
subsidiary. The guarantees on behalf of subsidiaries are entered into primarily
to support or enhance the creditworthiness otherwise attributed to a subsidiary
on a stand-alone basis, thereby facilitating the extension of sufficient credit
to accomplish the relevant subsidiary's intended commercial purposes.
F-231

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

The following tables detail Orion Power Holdings' various guarantees,
including the maximum potential amounts of future payments, assets held as
collateral and the carrying amount of the liabilities recorded on the balance
sheets, if applicable:

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

(1) Orion Power Holdings has guaranteed Reliant Resources' March 2003 credit
facility and senior secured notes. The related debt matures at varying dates
from 2007 to 2013.

(2) Orion Power Holdings has guaranteed the performance of certain of its
wholly-owned subsidiaries' hedging obligations. These guarantees were
provided to counterparties in order to facilitate physical and financial
agreements in fuel and emissions. As of December 31, 2003, the expiration of
certain guarantees was not yet determinable, as they are ongoing. The fair
values of the underlying transactions are included in Orion Power Holdings'
subsidiaries' balance sheets.

(3) Orion Power Holdings has guaranteed the payment obligations of certain
wholly-owned subsidiaries arising under long-term service agreements. These
guarantees have varying expiration dates. As of December 31, 2002,
guarantees with determinable expiration dates expire over varying year's
through December 2014. As of December 31, 2003, the expiration date of
certain guarantees was not yet determinable.

Unless otherwise noted, failure by the primary obligor to perform under the
terms of the various agreements and contracts guaranteed may result in the
beneficiary requesting immediate payment from Orion Power Holdings. To the
extent liabilities exist under the various agreements and contracts that Orion
Power Holdings guarantees, such liabilities are recorded in Orion Power
Holdings' subsidiaries' balance sheets at December 31, 2003. Management believes
the likelihood that Orion Power Holdings would be required to perform or
otherwise incur any significant losses associated with any of these guarantees
is remote.

Together with certain of Reliant Resources' other subsidiaries, Orion Power
Holdings is a guarantor of the obligations under Reliant Resources' Amended and
Restated Credit and Guaranty Agreement dated as of March 28, 2003, subject to
certain limitations under the Orion Power Holdings' senior notes. These
limitations limit the amount of Orion Power Holdings' guarantee based on a fixed
charge coverage ratio, consolidated tangible assets and a restricted payment
ceiling test, under the Orion Power Holdings' senior notes. Additionally, Orion
Power Holdings is the only limited guarantor of the obligations under Reliant

F-232

ORION POWER HOLDINGS, INC.

CONDENSED FINANCIAL INFORMATION
NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

Resources' senior secured notes issued in July 2003, subject to the same
limitations. None of Orion Power Holdings' subsidiaries guarantee Reliant
Resources' senior secured notes.

Both Reliant Resources' March 2003 credit facility and its senior secured
notes restrict Orion Power Holdings' and its subsidiaries' ability to take
specific actions, subject to numerous exceptions that are designed to allow for
the execution of Reliant Resources' and its subsidiaries' business plans in the
ordinary course, including the preservation and optimization of existing
investments in the retail energy and wholesale energy businesses and the ability
to provide credit support for commercial obligations. See note 13(e) to Orion
Power's consolidated financial statements.

(b) LEASES

Orion Power Holdings has entered in various non-cancelable operating lease
arrangements for office space and storage space. These leases terminate in 2005.
Future minimum payments due under these leases are as follows (in thousands):

2004........................................................ $340
2005........................................................ 173
----
$513
====

Total rental expense for 2001, January 1, 2002 through February 19, 2002,
February 20, 2002 through December 31, 2002 and 2003 was $377,000, $43,000,
$275,000 and $445,000, respectively.

(6) CASH DISTRIBUTIONS

Orion Power New York, L.P. made cash distributions to Orion Power Holdings
in 2001 of $86 million and in 2002 as part of a refinancing, repaid a $60
million revolving senior credit facility on behalf of Orion Power Holdings,
which was deemed a distribution to Orion Power Holdings (see note 7 to Orion
Power's consolidated financial statements). No dividends or distributions had
been made to Orion Power Holdings by Orion Power New York, L.P. in 2002 or 2003.
No dividends or distributions had been made to Orion Power Holdings by Orion
Power MidWest, L.P. or Liberty Electric Power, LLC through December 31, 2003.
Orion Power Development Company, Inc. distributed $831,000 to Orion Power
Holdings in 2003. See note 7 to Orion Power's consolidated financial statements
regarding restrictions on cash distributions from Orion Power Holdings'
subsidiaries to Orion Power Holdings.

* * *

F-233

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES

RESERVES
FOR THE PERIOD FEBRUARY 20, 2002 THROUGH DECEMBER 31, 2002 AND
THE YEAR ENDED DECEMBER 31, 2003

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

(1) Charged to other accounts represents obligations established related to
Reliant Resources, Inc.'s acquisition of Orion Power Holdings, Inc. and its
subsidiaries.

(2) Deductions from reserves represents losses or expenses for which the
respective reserves were created. In the case of the uncollectible accounts
reserve, such deductions are net of recoveries of amounts previously written
off.

* * *

F-234

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE.

None.

ITEM 9A. 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

In connection with the evaluation described above, we identified no change
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
our fiscal quarter ended December 31, 2003 that has materially affected, or is
reasonably likely to materially affect, our internal control over financial
reporting.

II-1

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.

The information called for by Item 10, to the extent not set forth in
"Executive Officers" in Item 1, will be set forth in the definitive proxy
statement relating to our 2004 annual meeting of stockholders pursuant to SEC
Regulation 14A. Such definitive proxy statement relates to a meeting of
stockholders involving the election of directors and the portions thereof called
for by Item 10 are incorporated herein by reference pursuant to Instruction G to
Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION.

The information called for by Item 11 will be set forth in the definitive
proxy statement relating to our 2004 annual meeting of stockholders pursuant to
SEC Regulation 14A. Such definitive proxy statement relates to a meeting of
stockholders involving the election of directors and the portions thereof called
for by Item 11 are incorporated herein by reference pursuant to Instruction G to
Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS.

The information called for by Item 12 will be set forth in the definitive
proxy statement relating to our 2004 annual meeting of stockholders pursuant to
SEC Regulation 14A. Such definitive proxy statement relates to a meeting of
stockholders involving the election of directors and the portions thereof called
for by Item 12 are incorporated herein by reference pursuant to Instruction G to
Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

The information called for by Item 13 will be set forth in the definitive
proxy statement relating to our 2004 annual meeting of stockholders pursuant to
SEC Regulation 14A. Such definitive proxy statement relates to a meeting of
stockholders involving the election of directors and the portions thereof called
for by Item 13 are incorporated herein by reference pursuant to Instruction G to
Form 10-K.

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

The information called for by Item 14 will be set forth in the definitive
proxy statement relating to our 2004 annual meeting of stockholders pursuant to
SEC Regulation 14A. Such definitive proxy statement relates to a meeting of
stockholders involving the election of directors and the portions thereof called
for by Item 14 are incorporated herein by reference pursuant to Instruction G to
Form 10-K.

III-1

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K.

(A)(1) RELIANT RESOURCES, INC. AND SUBSIDIARIES FINANCIAL STATEMENTS.

Responsibility for Financial Reporting...................... F-2
Independent Auditors' Report................................ F-3
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-4
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-5
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-6
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) for the Years Ended December
31, 2001, 2002 and 2003................................... F-7
Notes to Consolidated Financial Statements.................. F-10

(A)(2) FINANCIAL STATEMENT SCHEDULES.

Schedule I -- Condensed Financial Information of Reliant
Resources, Inc.
Condensed Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-107
Condensed Balance Sheets as of December 31, 2002 and 2003... F-108
Condensed Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-109
Notes to Condensed Financial Statements..................... F-111
Schedule II -- Reliant Resources, Inc. and
Subsidiaries -- Reserves for the Three Years Ended
December 31, 2003......................................... F-116

The following schedules are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements: III, IV and V.

The following financial statements are included in this report pursuant to
Items 3-10 or 3-16 of Regulation S-X:

RELIANT ENERGY RETAIL HOLDINGS, LLC AND SUBSIDIARIES FINANCIAL STATEMENTS.

Independent Auditors' Report................................ F-118
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-119
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-120
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-121
Consolidated Statements of Member's (Deficit) Equity and
Comprehensive Income (Loss) for the Years Ended December
31, 2001, 2002 and 2003................................... F-122
Notes to Consolidated Financial Statements.................. F-123

RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC AND SUBSIDIARIES FINANCIAL
STATEMENTS.

Independent Auditors' Report................................ F-149
Consolidated Statements of Operations for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-150
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-151
Consolidated Statements of Cash Flows for the Years Ended
December 31, 2001, 2002 and 2003.......................... F-152
Consolidated Statements of Shareholder's Equity and
Comprehensive Income (Loss) for the Years Ended December
31, 2001, 2002 and 2003................................... F-153
Notes to Consolidated Financial Statements.................. F-154

IV-1

ORION POWER HOLDINGS, INC. AND SUBSIDIARIES FINANCIAL STATEMENTS.

Independent Auditors' Reports............................... F-178
Consolidated Statements of Operations for the Year Ended
December 31, 2001, for the Periods from January 1, 2002
through February 19, 2002 and February 20, 2002 through
December 31, 2002 and for the Year Ended December 31,
2003...................................................... F-181
Consolidated Balance Sheets as of December 31, 2002 and
2003...................................................... F-182
Consolidated Statements of Cash Flows for the Year Ended
December 31, 2001, for the Periods from January 1, 2002
through February 19, 2002 and February 20, 2002 through
December 31, 2002 and for the Year Ended December 31,
2003...................................................... F-183
Consolidated Statements of Stockholders' Equity and
Comprehensive Income (Loss) for the Year Ended December
31, 2001, for the Periods from January 1, 2002 through
February 19, 2002 and February 20, 2002 through December
31, 2002 and for the Year Ended December 31, 2003......... F-184
Notes to Consolidated Financial Statements.................. F-185
Condensed Financial Information of Orion Power Holdings,
Inc....................................................... F-227

(A)(3) EXHIBITS

See Index of Exhibits, which index also include the management contracts or
compensatory plans or arrangements required to be filed as exhibits to this Form
10-K by Item 601(b)(10)(iii) of Regulation S-K.

(b) REPORTS ON FORM 8-K.

- Reliant Resources' Current Report (item 12) on Form 8-K filed on November
10, 2003;

- Reliant Resources' Current Report (items 5 and 7) on Form 8-K filed on
November 14, 2003;

- Reliant Resources' Current Report (item 9) on Form 8-K filed on November
14, 2003;

- Reliant Resources' Current Report (item 9) on Form 8-K filed on November
21, 2003;

- Reliant Resources' Current Report (items 5 and 7) on Form 8-K filed on
November 26, 2003;

- Reliant Resources' Current Report (items 5 and 7) on Form 8-K filed on
December 9, 2003;

- Reliant Resources' Current Report (items 2 and 7) on Form 8-K filed on
December 22, 2003; and

- Reliant Resources' Current Report (items 5 and 7) on Form 8-K filed on
December 29, 2003.

IV-2

SIGNATURES

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

RELIANT RESOURCES, INC.

By: /s/ JOEL V. STAFF
------------------------------------
Joel V. Staff
Chairman and Chief Executive Officer
March 8, 2004

Pursuant to the requirements of the Securities Exchange Act of 1934, this
Annual Report on Form 10-K has been signed by the following persons on behalf of
the Registrant and in the capacities and on the dates indicated.

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-K by Item 601(b)(10)(iii) of Regulation S-K.