RELIANT ENERGY INC - 10-K Annual Report

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

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, 2001

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 1-3187
RELIANT ENERGY, INCORPORATED
(Exact name of registrant as specified in its charter)

TEXAS 74-0694415
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification No.)

1111 LOUISIANA
HOUSTON, TEXAS 77002 (713) 207-3000
(Address and zip code of principal executive (Registrant's telephone number, including area
offices) code)

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

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
NONE

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 each of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]

The aggregate market value of the voting stock held by non-affiliates of
Reliant Energy, Incorporated (Company) was $7,365,940,777 as of April 8, 2002,
using the definition of beneficial ownership contained in Rule 13d-3 promulgated
pursuant to the Securities Exchange Act of 1934 and excluding shares held by
directors and executive officers. As of April 8, 2002, the Company had
303,496,317 shares of Common Stock outstanding, including 6,023,880 ESOP shares
not deemed outstanding for financial statement purposes. Excluded from the
number of shares of Common Stock outstanding are 166 shares held by the Company
as treasury stock.

Portions of the definitive proxy statement relating to the 2002 Annual
Meeting of Shareholders of the Company, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2001, are incorporated
by reference in Item 10, Item 11, Item 12 and Item 13 of Part III of this Form
10-K.
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TABLE OF CONTENTS

PART I
Item 1. Business.................................................... 1
Item 2. Properties.................................................. 52
Item 3. Legal Proceedings........................................... 53
Item 4. Submission of Matters to a Vote of Security Holders......... 54

PART II
Item 5. Market for Common Stock and Related Stockholder Matters..... 55
Item 6. Selected Financial Data..................................... 56
Item 7. Management's Discussion and Analysis of Financial Condition
and
Results of Operations..................................... 58
Item 7A. Quantitative and Qualitative Disclosures About Market
Risk........................................................ 121
Item 8. Financial Statements and Supplementary Data................. 132
Item 9. Changes in and Disagreements with Accountants on Accounting
and
Financial Disclosure...................................... 213

PART III
Item 10. Directors and Executive Officers............................ 213
Item 11. Executive Compensation...................................... 213
Item 12. Security Ownership of Certain Beneficial Owners and
Management.................................................. 213
Item 13. Certain Relationships and Related Transactions.............. 213

PART IV
Item 14. Exhibits, Financial Statement Schedules and Reports on Form
8-K......................................................... 213

i

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "intend," "may," "plan," "potential," "predict,"
"should," "will," "forecast," "goal," "objective," "projection," or other
similar words.

We have based our forward-looking statements on our management's beliefs
and assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.

The following list identifies some of the factors that could cause actual
results to differ from those expressed or implied by our forward-looking
statements:

- state, federal and international legislative and regulatory developments,
including deregulation; re-regulation and restructuring of the electric
utility industry; and changes in, or application of environmental, siting
and other laws and regulations to which we are subject;

- timing of the implementation of our business separation plan, including
the receipt of necessary approvals from the Securities and Exchange
Commission (SEC) and an extension relating to a private letter ruling
from the Internal Revenue Service (IRS);

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

- industrial, commercial and residential growth in our service territories;

- our pursuit of potential business strategies, including acquisitions or
dispositions of assets or the development of additional power generation
facilities;

- state, federal and other rate regulations in the United States and in
foreign countries in which we operate or into which we might expand our
operations;

- the timing and extent of changes in commodity prices, particularly
natural gas;

- weather variations and other natural phenomena;

- political, legal and economic conditions and developments in the United
States and in foreign countries in which we operate or into which we
might expand our operations, including the effects of fluctuations in
foreign currency exchange rates;

- financial market conditions and the results of our financing efforts;

- ramifications from the bankruptcy filing of Enron Corp.;

- any direct or indirect effect on our business resulting from the
September 11, 2001 terrorist attacks or any similar incidents or
responses to such incidents;

- the performance of our projects; and

- other factors we discuss in this Form 10-K, including those outlined in
"Management's Discussion and Analysis of Financial Condition and Results
of Operations -- Certain Factors Affecting Our Future Earnings."

You should not place undue reliance on 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 statements.
ii

COMMONLY USED TERMS

Below is a list of terms commonly used in this Form 10-K, along with their
definitions or descriptions. Some of the definitions or descriptions below are
summaries, and you should refer to the corresponding discussion within this Form
10-K for a complete definition or description.

1935 Act.................................. Public Utility Holding Company Act of 1935
Arkla..................................... Reliant Energy Arkla, a division of RERC Corp.
Bbtu...................................... Billion British thermal units
Bcf....................................... Billion cubic feet
Business Separation Plan.................. Our amended business separation plan providing for the
separation of our generation, transmission and
distribution, and retail operations into three different
companies and for the separation of its regulated and
unregulated businesses into two publicly traded
companies, as filed with the Texas Utility Commission
Cal ISO................................... California Independent System Operator
CenterPoint Energy........................ CenterPoint Energy, Inc.
CenterPoint Energy Houston................ CenterPoint Energy Houston Electric, LLC, the
transmission and distribution business of Reliant Energy
after the Restructuring
Contractually mandated auctions........... Auctions to third parties of the installed generating
capacity of our Texas generation business in excess of
amounts included in the state mandated auctions
Distribution.............................. The distribution of our remaining equity interest in the
common stock of Reliant Resources to our shareholders
Entex..................................... Reliant Energy Entex, a division of RERC Corp.
EPA....................................... Environmental Protection Agency
ERCOT..................................... Electric Reliability Council of Texas, Inc.
ERCOT market.............................. The state of Texas, other than a portion of the
panhandle and a portion of the east bordering on
Louisiana
FASB...................................... Financial Accounting Standards Board
FERC...................................... Federal Energy Regulatory Commission
GWh....................................... Gigawatt hours
HAPs...................................... Hazardous air pollutants
IRS....................................... Internal Revenue Service
ISO....................................... Independent System Operator
KWh....................................... Kilowatt-hour
Kyoto Protocol............................ United Nations Framework Convention on Climate Change
Laclede................................... Laclede Gas Company
MACT...................................... Maximum achievable control technology
Minnegasco................................ Reliant Energy Minnegasco, a division of RERC Corp.
MMBtu..................................... Million British thermal units
MMcf...................................... Million cubic feet
MRT....................................... Mississippi River Transmission Corporation
MW........................................ Megawatts

iii

MWh....................................... Megawatt hours
NEA....................................... NEA B.V., the coordinating body for the Dutch
electricity generating sector
NOx....................................... Nitrogen oxides
NRC....................................... Nuclear Regulatory Commission
October 3, 2001 Order..................... Order from the Texas Utility Commission dated October 3,
2001 that established the transmission and distribution
rates that became effective January 1, 2002
Orion Power............................... Orion Power Holdings, Inc.
PJM ISO................................... PJM Interconnection, L.L.C.
PJM market................................ Pennsylvania-New Jersey-Maryland market
PJM West market........................... PJM market in western Pennsylvania
POLR...................................... Provider of last resort
price to beat............................. The price, as set by the Texas Utility Commission, that
retail electric providers affiliated with a former
integrated utility charge residential and small
commercial customers within their affiliated electric
utility's service area
PURPA..................................... Public Utility Regulatory Policies Act of 1978
REFS...................................... Reliant Energy Field Services, Inc.
REGT...................................... Reliant Energy Gas Transmission Company
Reliant Energy HL&P....................... An unincorporated division of Reliant Energy, formerly
an integrated electric utility
Reliant Energy............................ Reliant Energy, Incorporated
Reliant Energy Services................... Reliant Energy Services, Inc.
Reliant Resources......................... Reliant Resources, Inc.
REMA...................................... Reliant Energy Mid-Atlantic Power Holdings, LLC
REPG...................................... Reliant Energy Power Generation, Inc.
REPGB..................................... Reliant Energy Power Generation Benelux N.V. (formerly
UNA N.V.)
REPS...................................... Reliant Energy Pipeline Services, Inc.
RERC...................................... Reliant Energy Resources Corp. and subsidiaries
RERC Corp................................. Reliant Energy Resources Corp.
Restructuring............................. The transactions through which CenterPoint Energy will
become the holding company for Reliant Energy and its
subsidiaries, Reliant Energy and its subsidiaries will
become subsidiaries of CenterPoint Energy, and each
share of Reliant Energy common stock will be converted
into one share of CenterPoint Energy common stock
RTO....................................... Regional Transmission Organization
SEC....................................... Securities and Exchange Commission
Separation................................ The transactions that include the transfers of
substantially all of our unregulated businesses to
Reliant Resources, the Reliant Resources offering, the
Restructuring and the Distribution
SFAS...................................... Statement of Financial Accounting Standards
South Texas Project....................... South Texas Project Electric Generating Station

iv

state mandated auctions................... Auctions of 15% of the output of the installed
generating capacity of our Texas generation business
required by the Texas Electric Restructuring Law
T&D Utility............................... The transmission and distribution operations that were
formerly part of the integrated electric utility under
Reliant Energy HL&P, operated as a functionally separate
unit since January 2002 as required by the Texas
Electric Restructuring Law
TCR....................................... Transmission Congestion Rights
Texas Electric Restructuring Law.......... Texas Electric Choice Plan, Texas Utility Code sec.
39.001, et seq
Texas Genco............................... Texas Genco, LP and the intermediate subsidiaries
through which interests in Texas Genco, LP are held
Texas Genco Option........................ Option, subject to the completion of the Distribution,
granted to Reliant Resources by Reliant Energy to
purchase all of the shares of capital stock of Texas
Genco owned by CenterPoint Energy after Texas Genco
conducts the initial public offering or distribution of
no more than 20% of its capital stock
Texas generation business................. The generating facilities and operations to be
transferred to Texas Genco in the Restructuring
Texas Utility Commission.................. Public Utility Commission of Texas
TMDL...................................... Total Maximum Daily Load program of the Clean Water Act
we, us, our or similar terms.............. Reliant Energy and its subsidiaries prior to the
Restructuring and CenterPoint Energy and its
subsidiaries after the Restructuring
Wires Case................................ March 31, 2000 filing with the Texas Utility Commission,
which resulted in the Commission's October 3, 2001 Order
that set the regulated rates for the T&D Utility to be
effective when electric competition began

v

PART I

ITEM 1. BUSINESS

OUR BUSINESS

GENERAL

We are a diversified international energy services and energy delivery
company that provides energy and energy services primarily in North America and
Western Europe. Reliant Energy, Incorporated (Reliant Energy), a Texas
corporation incorporated in 1906, is the parent company of our consolidated
group of companies and is a utility holding company that conducts electric
utility operations in Texas. Reliant Energy owns all of the common stock of
Reliant Energy Resources Corp. (RERC Corp.), which conducts natural gas
distribution and pipeline operations, and of CenterPoint Energy, Inc.
(CenterPoint Energy), which does not currently conduct any operations. RERC
Corp. is a Delaware corporation that was incorporated in 1996. CenterPoint
Energy is a Texas corporation that was incorporated in August 2001 to become the
holding company for Reliant Energy following the Restructuring (as defined
below). Reliant Energy also owns approximately 83% of the common stock of
Reliant Resources, Inc. (Reliant Resources), which conducts non-utility
wholesale and retail energy operations. Reliant Resources is a Delaware
corporation that was incorporated in August 2000. In this Form 10-K, unless the
context indicates otherwise,

- references to "we," "us" or similar terms mean Reliant Energy and its
subsidiaries prior to the Restructuring described below and CenterPoint
Energy and its subsidiaries after the Restructuring; and

- we refer to RERC Corp. and its subsidiaries as "RERC."

The executive offices of Reliant Energy are located at 1111 Louisiana,
Houston, TX 77002 (telephone number 713-207-3000).

STATUS OF BUSINESS SEPARATION

We are in the process of separating our regulated and unregulated
businesses into two unaffiliated publicly traded companies. In December 2000, we
transferred a significant portion of our unregulated businesses to Reliant
Resources, which, at the time, was a wholly owned subsidiary. Reliant Resources
conducted an initial public offering of approximately 20% of its common stock in
May 2001. In December 2001, our shareholders approved an agreement and plan of
merger by which the following will occur (which we refer to as the
Restructuring):

- CenterPoint Energy will become the holding company for Reliant Energy and
its subsidiaries;

- Reliant Energy and its subsidiaries will become subsidiaries of
CenterPoint Energy; and

- each share of Reliant Energy common stock will be converted into one
share of CenterPoint Energy common stock.

After the Restructuring, we plan, subject to further corporate approvals,
market and other conditions, to complete the separation of our regulated and
unregulated businesses by distributing the shares of common stock of Reliant
Resources that we own to our shareholders (Distribution). Our goal is to
complete the Restructuring and subsequent Distribution as quickly as possible
after all the necessary conditions are fulfilled, including receipt of an order
from the SEC granting the required approvals under the Public Utility Holding
Company Act of 1935 (1935 Act) and an extension from the IRS for a private
letter ruling we have obtained regarding the tax-free treatment of the
Distribution. Although receipt or timing of regulatory approvals cannot be
assured, we believe we meet the standards for such approvals. Please read
"-- Regulation -- Public Utility Holding Company Act of 1935" in Item 1 of this
Form 10-K. We currently expect to complete the Restructuring and Distribution in
the summer of 2002. Please read "-- Business Separation" in Item 1 of this Form
10-K. For information about an informal inquiry by the staff of the Division of
Enforcement of the SEC in connection with an earnings restatement by Reliant
Energy that might impact the approval process, please read "Restatement of
Second and Third Quarter 2001 Results of Operations" in Item 3 of this Form
10-K.

1

We have entered into a number of separation agreements with Reliant
Resources in anticipation of the Restructuring and the Distribution. For
information about these agreements, please read "Reliant Energy's Relationship
with Reliant Resources" in Item 1 of this Form 10-K.

The diagrams on the following page depict our current structure, our
structure after the Restructuring and our structure after the Distribution.
Unless otherwise indicated, ownership interests shown below are 100%. Other
ownership interests indicated below are approximate.

CURRENT STRUCTURE(1)

[GRAPH]

STRUCTURE AFTER RESTRUCTURING

[GRAPH]

STRUCTURE AFTER DISTRIBUTION

[GRAPH]
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(1) As of April 1, 2002.

(2) Owned indirectly through another subsidiary of Reliant Energy or CenterPoint
Energy.

(3) Reliant Energy will become CenterPoint Energy Houston Electric, LLC
(CenterPoint Houston) in the Restructuring. Please read "-- Business
Separation -- Restructuring -- Reliant Energy Conversion" in Item 1 of this
Form 10-K.

(4) RERC Corp. will be renamed CenterPoint Energy Resources Corp. as part of the
Restructuring.

2

BUSINESS SEGMENT OVERVIEW

We conducted our operations in 2001 through the following business
segments:

- Electric Operations;

- Natural Gas Distribution;

- Pipelines and Gathering;

- Wholesale Energy;

- European Energy;

- Retail Energy;

- Latin America; and

- Other Operations.

During 2001, our Electric Operations business segment included our
regulated electric generation, transmission and distribution, and retail
electric sales functions, all of which were operated as an integrated utility
under Reliant Energy HL&P, an unincorporated division of Reliant Energy. As of
January 1, 2002, the generation and retail electric sales functions were
deregulated. Retail electric sales involve the sale of electricity and related
services to end users of electricity, including industrial, commercial and
residential customers. Retail electric sales are now part of the Retail Energy
business segment, which is owned by Reliant Resources. The generation facilities
now operated as a division of Reliant Energy will be operated by a separate
indirect subsidiary of CenterPoint Energy following the Restructuring and will
comprise a new business segment, Electric Generation. The transmission and
distribution functions, which will be conducted through a separate subsidiary,
will remain regulated and will also comprise a new business segment, Electric
Transmission and Distribution. In addition to Retail Energy, the Wholesale
Energy, European Energy and several of the operations in the Other Operations
business segments are currently owned by Reliant Resources. Once we complete the
Distribution, those business segments and operations will no longer be part of
our business. For more information about our business after deregulation and the
completion of the Distribution, please read "Our Business Going Forward" in Item
1 of this Form 10-K.

For information about the revenues, operating income, assets and other
financial information relating to our business segments, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Results of Operations by Business Segment" in Item 7 of this Form
10-K and Note 18 to our consolidated financial statements, which, together with
the notes related to those statements, we refer to in this Form 10-K as our
"consolidated financial statements."

DEREGULATION

In 1999, the Texas legislature adopted the Texas Electric Choice Plan
(Texas Electric Restructuring Law), which substantially amended the regulatory
structure governing electric utilities in Texas in order to allow retail
electric competition for all customers. Retail pilot projects, allowing
competition for up to 5% of each utility's energy demand, or "load" in all
customer classes, began in August 2001 and retail electric competition for all
other customers began in January 2002. Under the Texas Electric Restructuring
Law:

- electric utilities in Texas, including Reliant Energy HL&P, have
restructured or are in the process of restructuring their businesses in
order to separate power generation, transmission and distribution, and
retail electric provider activities into separate units;

- since January 1, 2002, most retail customers of investor-owned electric
utilities in Texas, including the customers of Reliant Energy HL&P, have
been entitled to purchase their electricity from any of a number of
"retail electric providers" that have been certified by the Public
Utility Commission of Texas (Texas Utility Commission);

3

- retail electric providers, who may not themselves own any generation
assets, obtain their electricity from power generation companies, exempt
wholesale generators and other generating entities and provide services
at generally unregulated rates, except that the prices that may be
charged to residential and small commercial customers by retail electric
providers affiliated with a utility within their affiliated electric
utility's service area are set by the Texas Utility Commission (price to
beat) until certain conditions in the Texas Electric Restructuring Law
are met;

- the transmission and distribution of power are performed by transmission
and distribution utilities at rates that continue to be regulated by the
Texas Utility Commission; and

- transmission and distribution utilities in Texas whose generation assets
were "unbundled" pursuant to the Texas Electric Restructuring Law,
including the transmission and distribution utility successor to Reliant
Energy HL&P, may recover generation-related

(i) "regulatory assets," which consist of the Texas jurisdictional
amount reported by the electric utilities as regulatory assets and
liabilities (offset by specified amounts) in their audited financial
statements for 1998; and

(ii) "stranded costs," which consist of the positive excess of the net
regulatory book value of generation assets over the market value of the
assets, taking specified factors into account.

We filed our initial business separation plan with the Texas Utility
Commission in January 2000 and filed amended plans in April 2000 and August
2000. In December 2000, the Texas Utility Commission approved our amended
business separation plan (Business Separation Plan) providing for the separation
of our generation, transmission and distribution, and retail operations into
three different companies and for the separation of our regulated and
unregulated businesses into two publicly traded companies. On October 15, 2001,
we filed an update to the Business Separation Plan with the Texas Utility
Commission indicating that full implementation of the plan could not be achieved
until all regulatory approvals had been received. Since not all regulatory
approvals had been received by the beginning of retail competition on January 1,
2002, we have not fully implemented the Business Separation Plan. However,
beginning January 1, 2002, our generation, transmission and distribution, and
retail electric sales operations have been functionally separated and are
conducted independently as if the Business Separation Plan were completed.

The Texas Electric Restructuring Law permits utilities to recover
regulatory assets and stranded costs through non-bypassable charges authorized
by the Texas Utility Commission, to the extent that such assets and costs are
established in certain regulatory proceedings. The law also authorizes the Texas
Utility Commission to permit utilities to issue securitization bonds based on
the securitization of that charge. On May 31, 2001, the Texas Utility Commission
issued a financing order pursuant to the Texas Electric Restructuring Law
authorizing the issuance of $740 million of transition bonds, plus approximately
$10 million in qualified costs, to recover certain Reliant Energy HL&P
regulatory assets. Pursuant to the financing order, we, through a special
purpose subsidiary, issued $749 million aggregate principal amount of transition
bonds in October 2001 and used the proceeds to reduce our recoverable regulatory
assets by repaying outstanding indebtedness. For more information regarding the
transition bonds issuance and recovery of our regulatory assets, please read
Note 4(a) to our consolidated financial statements. For information regarding
the manner in which we plan to recover our stranded costs, please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- Stranded Costs and Regulatory Assets" in Item 1 of this Form 10-K
and Note 4(a) to our consolidated financial statements.

For additional information regarding the Texas Electric Restructuring Law,
retail competition in Texas and its application to our operations and structure,
please read "-- Business Separation," "Electric Operations" and
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" below, "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Electric Operations" in Item 7 of this Form 10-K and Note 4
to our consolidated financial statements.

4

BUSINESS SEPARATION

Pursuant to the Business Separation Plan, we plan to separate our
businesses into two publicly traded companies (CenterPoint Energy and Reliant
Resources) in order to separate (i) our unregulated businesses from our
regulated businesses and (ii) our generation, transmission and distribution and
retail electric sales functions from each other as required by the Texas
Electric Restructuring Law. Below is an outline of the significant transactions
through which the business separation will be accomplished, some of which have
been completed. In this Form 10-K, we sometimes collectively refer to the
transactions described below, including the transfers of assets to Reliant
Resources, the Reliant Resources offering, the Restructuring and the
Distribution as the "Separation."

Reliant Resources Transfers. In December 2000, we transferred
substantially all of our unregulated businesses to Reliant Resources, including
the operations conducted by our:

- Wholesale Energy business segment;

- European Energy business segment;

- Retail Energy (retail electricity business) business segment;

- Communications business; and

- New Ventures group.

In connection with the transfer of our unregulated businesses to Reliant
Resources, we entered into a number of agreements with Reliant Resources,
including the master separation agreement, providing for, among other things,
the transfer of assets and liabilities to Reliant Resources, as well as interim
and ongoing relationships with Reliant Resources, including the provision by
Reliant Energy of various interim services to Reliant Resources. For information
about these agreements, please read "Reliant Energy's Relationship With Reliant
Resources" in Item 1 of this Form 10-K.

In May 2001, Reliant Resources conducted an initial public offering of
approximately 20% of its outstanding common stock. Pursuant to the master
separation agreement, $1.7 billion of debt owed by Reliant Resources to Reliant
Energy was converted into equity as a capital contribution to Reliant Resources
in connection with the initial public offering.

Restructuring -- Holding Company Formation. After having received the
necessary regulatory approvals, CenterPoint Energy will become the holding
company for Reliant Energy and its subsidiaries as a result of the merger of a
CenterPoint Energy subsidiary with and into Reliant Energy. In the merger, each
outstanding share of Reliant Energy common stock will be converted automatically
into one share of CenterPoint Energy common stock. For information regarding the
special shareholders' meeting at which the merger agreement providing for the
holding company formation was approved, please read Item 4 of this Form 10-K.

Restructuring -- Texas Genco Transfers. In December 2001, we formed Texas
Genco, LP, a Texas limited partnership, as an indirect, wholly owned subsidiary.
In this Form 10-K, we refer to Texas Genco, LP and the subsidiary entities
through which we own Texas Genco, LP individually and collectively as "Texas
Genco," as the context requires. We plan to transfer Reliant Energy HL&P's Texas
generating assets and liabilities associated with those assets to Texas Genco
immediately prior to the consummation of the holding company formation. Texas
Genco will operate our formerly regulated generating assets as a power
generation company selling generation at market prices to Reliant Resources and
other power purchasers in accordance with the separation agreements and the
Texas Electric Restructuring Law and will comprise our new Electric Generation
business segment.

In accordance with provisions of the Texas Electric Restructuring Law
relating to the determination of stranded costs, we plan for Texas Genco to
conduct an initial public offering of approximately 20% of its capital stock by
the end of 2002. If we do not conduct the initial public offering, we may
distribute approximately 20% of Texas Genco's capital stock to our shareholders
in a transaction taxable both to us and our shareholders as part of the
valuation of stranded costs. Reliant Resources holds an option, subject to the
completion of the Distribution, exercisable in 2004 to purchase the Texas Genco
stock owned by CenterPoint
5

Energy after the initial public offering or distribution. For additional
information regarding Texas Genco and Reliant Resources' option to purchase
Texas Genco stock, please read "Reliant Energy's Relationship With Reliant
Resources" and "Electric Operations -- Generation" in Item 1 of this Form 10-K.

Restructuring -- Reliant Energy Conversion. As a result of the holding
company formation and transfer of assets to Texas Genco, Reliant Energy will
become a wholly owned subsidiary of CenterPoint Energy, will hold the
transmission and distribution assets previously held by Reliant Energy HL&P and
will operate those assets subject to regulation by the Texas Utility Commission.
Immediately after the holding company formation, Reliant Energy will convert
from a Texas corporation to CenterPoint Houston, a Texas limited liability
company.

Distribution. As a result of the holding company formation, CenterPoint
Energy will become the owner of all of the shares of Reliant Resources' common
stock currently owned by Reliant Energy. We anticipate that, upon completion of
the Restructuring and subject to board approval, market and other conditions,
CenterPoint Energy will distribute all of the stock it owns in Reliant Resources
to CenterPoint Energy's shareholders, effecting the separation of our operations
into two unaffiliated publicly traded corporations. We have obtained a private
letter ruling from the IRS providing for the tax-free treatment of the
Distribution that is predicated on the completion of the Distribution by April
30, 2002. We have requested an extension of this deadline. While there can be no
assurance that we will receive the extension, we anticipate that we will receive
an extension that allows us to proceed with the Distribution after April 30,
2002.

Please see "-- Status of Business Separation" in Item 1 of this Form 10-K
for diagrams depicting various stages of the Separation.

RERC CORP. RESTRUCTURING

Following the Restructuring, CenterPoint Energy will be a utility holding
company under the 1935 Act and as such will be required to register under the
1935 Act unless it qualifies for an exemption. In order to enable CenterPoint
Energy to comply with the requirements in the exemption in Section 3(a)(1) of
the 1935 Act, we plan to divide the gas distribution businesses conducted by
RERC Corp.'s three unincorporated divisions, Reliant Energy Entex (Entex),
Reliant Energy Arkla (Arkla) and Reliant Energy Minnegasco (Minnegasco), among
three separate business entities. For more information regarding our application
under the 1935 Act and regulation under the 1935 Act, please read
"Regulation -- Public Utility Holding Company Act of 1935" in Item 1 of this
Form 10-K. The entity that will hold the Entex assets will also hold RERC
Corp.'s natural gas pipelines and gathering businesses. For more information
regarding RERC Corp.'s divisions and their operations, please read "Natural Gas
Distribution" and "Pipelines and Gathering" in Item 1 of this Form 10-K. In
addition to regulatory approvals we have obtained, this restructuring will
require approval of the public service commissions of Louisiana, Oklahoma and
Arkansas.

RELIANT ENERGY'S RELATIONSHIP WITH RELIANT RESOURCES

INTERCOMPANY AGREEMENTS

Prior to the initial public offering of Reliant Resources' common stock,
Reliant Energy entered into agreements with Reliant Resources providing for the
separation of their businesses. These agreements generally provided for the
transfer by Reliant Energy of assets relating to Reliant Resources' businesses
and the assumption by Reliant Resources of associated liabilities. Reliant
Energy also entered into other agreements governing various ongoing
relationships between it and Reliant Resources.

Master Separation Agreement. The master separation agreement provides for
the separation of Reliant Energy's assets and businesses from those of Reliant
Resources. It contains agreements relating to subsequent transactions and
several agreements governing the relationship between Reliant Energy and Reliant
Resources in the future. The master separation agreement also provides for
cross-indemnities intended to place sole financial responsibility on Reliant
Resources and its subsidiaries for all liabilities associated with the current
and historical businesses and operations they conduct, regardless of the time
those liabilities arise, and to place sole financial responsibility for
liabilities associated with Reliant Energy's other businesses with Reliant
6

Energy and its other subsidiaries. Reliant Energy and Reliant Resources also
agreed to assume and be responsible for specified liabilities associated with
activities and operations of the other party and its subsidiaries to the extent
performed for or on behalf of their respective current or historical business.
The master separation agreement also contains indemnification provisions under
which Reliant Energy and Reliant Resources will each indemnify the other with
respect to breaches by the indemnifying party of the master separation agreement
or any ancillary agreements.

The master separation agreement provides for the Restructuring and
Distribution, including the formation of Texas Genco, although it does not
obligate Reliant Energy to effect the Distribution. The agreement requires Texas
Genco (and, prior to the Restructuring, Reliant Energy) to auction capacity
remaining after it conducts the mandated auctions of its capacity required by
the Texas Electric Restructuring Law. After certain deductions, Reliant
Resources has the right to purchase 50% (but no less than 50%) of the capacity
that would otherwise be auctioned at the prices to be established in the
auctions required by the master separation agreement. For more information on
these auctions, please read "-- Electric Operations -- Generation -- State
Mandated Capacity Auctions" and "-- Contractually Mandated Capacity Auctions" in
Item 1 of this Form 10-K.

The master separation agreement also requires Reliant Resources to make a
payment to Reliant Energy equal to the amount, if any, required to be credited
to Reliant Energy by Reliant Energy's affiliated retail electric provider
pursuant to the Texas Electric Restructuring Law. This payment, which is
sometimes referred to as the "clawback" payment, will be required unless 40% or
more of the amount of electric power that was consumed before the onset of
retail competition by residential or small commercial customers within Reliant
Energy HL&P's service territory is being served by retail electric providers
other than Reliant Resources by January 1, 2004. The payment by Reliant
Resources will be the lesser of (a) the amount that the price to beat, less
non-bypassable delivery charges, is in excess of the prevailing market price of
electricity during such period per customer or (b) $150, multiplied by the
number of residential or small commercial customers in Reliant Energy HL&P's
service territory that are buying electricity at the price to beat on January 1,
2004 less the number of new customers obtained by Reliant Resources outside
Reliant Energy HL&P's service area. Amounts received from Reliant Resources with
respect to the clawback payment, if any, will be included in the 2004 stranded
cost true-up as a reduction of stranded costs. For additional information
regarding this payment, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Liquidity and Capital
Resources -- Reliant Resources -- unregulated business -- "clawback" Payment to
Reliant Energy" in Item 7 of this Form 10-K. For discussion of the 2004 true-up
proceedings, please read Note 4(a) to our Consolidated Financial Statements.

The master separation agreement contains provisions relating to certain
nuclear decommissioning assets, the exchange of information, provision of
information for financial reporting purposes, dispute resolution, and provisions
limiting competition between the parties in certain business activities and
provisions allocating responsibility for the conduct of regulatory proceedings
and limiting positions that may be taken in legislative, regulatory or court
proceedings in which the interests of both parties may be affected. For
additional information regarding the nuclear decommissioning assets, please read
"Regulation -- Nuclear Regulatory Commission" in Item 1 of this Form 10-K.

Texas Genco Option Agreement. Reliant Energy and Reliant Resources also
entered into an agreement under which, subject to the completion of the
Distribution, Reliant Resources will have an option to purchase all of the
shares of capital stock of Texas Genco owned by CenterPoint Energy after the
initial public offering or distribution of no more than 20% of Texas Genco's
capital stock (Texas Genco Option). The Texas Genco Option may be exercised
between January 10, 2004 and January 24, 2004. The per share exercise price
under the option will be the average daily closing price on the national
exchange for publicly held shares of common stock of Texas Genco for the 30
consecutive trading days with the highest average closing price during the 120
trading days immediately ending January 9, 2004, plus a control premium, up to a
maximum of 10%, to the extent a control premium is included in the valuation
determination made by the Texas Utility Commission relating to the market value
of Texas Genco's common stock equity. The exercise price is also subject to
adjustment based on the difference between the cash dividends paid during the
period there is a public ownership interest in Texas Genco and Texas Genco's
earnings during that period. For additional
7

information regarding recovery of stranded costs, please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- Stranded Costs and Regulatory Assets" in Item 1 of this Form 10-K
and Note 4(a) to our consolidated financial statements.

If Reliant Resources exercises the Texas Genco Option and purchases
CenterPoint Energy's shares of Texas Genco common stock, Reliant Resources will
also be required to purchase all notes and other receivables from Texas Genco
then held by CenterPoint Energy, at their principal amount plus accrued
interest. Similarly, if Texas Genco holds notes or receivables from CenterPoint
Energy, Reliant Resources will assume those obligations in exchange for a
payment to Reliant Resources by CenterPoint Energy of an amount equal to the
principal plus accrued interest. If Reliant Resources does not exercise the
Texas Genco Option, CenterPoint Energy may continue to operate Texas Genco or
sell or otherwise dispose of its operations. If CenterPoint Energy continues to
operate Texas Genco after 2005, it will need to replace or enter into a new
arrangement for the provision of technical services for the operation of Texas
Genco's facilities, which services are currently being provided by Reliant
Resources under the technical services agreement, which is described below and
expires upon Reliant Resources' purchase of Texas Genco shares if it exercises
the Texas Genco Option or in 2005 if the Texas Genco Option is not exercised,
subject to additional conditions.

The purchase of the shares of Texas Genco common stock upon exercise of the
Texas Genco Option by Reliant Resources will be subject to various regulatory
approvals, including Hart-Scott-Rodino antitrust clearance and United States
Nuclear Regulatory Commission (NRC) license transfer approval.

Technical Services Agreement. Reliant Resources provides engineering and
technical support services and environmental, safety and industrial health
services to support operation and maintenance of the generation facilities to be
transferred to Texas Genco under the technical services agreement. Reliant
Resources also provides systems, technical, programming and consulting support
services and hardware maintenance (but excluding plant-specific hardware)
necessary to provide dispatch planning, dispatch and settlement and
communication with the independent system operator, as well as general
information technology services for the generation facilities to be transferred
to Texas Genco. The fees Reliant Resources charges for these services allow it
to recover its fully allocated direct and indirect costs and reimbursement of
all out-of-pocket expenses. Expenses associated with capital investment in
systems and software that benefit both the operation of the generation
facilities to be transferred to Texas Genco and Reliant Resources' facilities in
other regions are allocated on an installed megawatt basis.

Other Agreements. Reliant Energy and Reliant Resources entered into
several other agreements pursuant to the master separation agreement. These
agreements include an employee matters agreement, which addresses asset and
liability allocation relating to Reliant Resources' employees and their
continued participation in Reliant Energy's benefit plans, and a tax allocation
agreement, which governs the allocation of U.S. income tax liabilities and sets
forth agreements with respect to other tax matters. These agreements, along with
the master separation agreement, the Texas Genco Option agreement and the
technical services agreement, are filed as exhibits to this Form 10-K.

COMMON DIRECTORS ON RELIANT RESOURCES' AND RELIANT ENERGY'S BOARD OF DIRECTORS
AND STOCK OWNERSHIP OF MANAGEMENT

Three of Reliant Energy's directors are also directors of Reliant
Resources. One of these directors is Reliant Energy's chairman, president and
chief executive officer. These directors owe fiduciary duties to the
stockholders of each company. As a result, in connection with any transaction or
other relationship involving both companies, these directors may need to recuse
themselves and not participate in any board action relating to these
transactions or relationships. It is anticipated that at the time of
Distribution, one of these directors will resign as a director of Reliant
Energy. In addition, members of Reliant Energy's board of directors and
management own stock in Reliant Resources, and vice versa.

8

ELECTRIC OPERATIONS

GENERAL

Our Electric Operations business segment and the discussion in this section
include only our electric utility operations that traditionally have been
subject to regulation by the Texas Utility Commission and do not include
operations in other states or operations in the state of Texas that are not
regulated by the Texas Utility Commission. For information about our other
power-related operations, please read "Wholesale Energy" in Item 1 of this Form
10-K. In 2001, Reliant Energy HL&P conducted our electric operations as a
traditional integrated electric utility, including generation, transmission and
distribution, and retail electric sales operations. Retail electric sales
involve the sale of electricity and related services to end users of
electricity, including industrial, commercial and residential customers. We
generated, purchased for resale, transmitted, distributed and sold electricity
to approximately 1.7 million customers in a 5,000-square mile area on the Texas
Gulf Coast, including Houston, through the operations of this business segment.

As contemplated by the Texas Electric Restructuring Law, full retail
competition began in Texas on January 1, 2002. In response to the Texas Electric
Restructuring Law and as part of the Separation, we have functionally separated
our generation, transmission and distribution operations and are in the process
of separating those operations among different business entities. In December
2000, prior to the beginning of retail competition, we transferred our retail
electric sales operations to subsidiaries of Reliant Resources, though our
retail customers remained customers of Reliant Energy HL&P until their first
meter reading following the onset of full retail competition on January 1, 2002.
After that date those customers have been entitled to purchase their electricity
from any of a number of certified retail electric providers, including Reliant
Resources. Residential and small commercial customers who did not select another
retail electric provider became customers of Reliant Resources, where the bulk
of those customers have remained to date. For information about the retail
operations we conduct through Reliant Resources, please read "Retail Energy" in
Item 1 of this Form 10-K.

The generation operations in our Electric Operations business segment
remained part of Reliant Energy HL&P throughout 2001, but are now operated
independently of the retail electric sales and transmission and distribution
operations. In this Form 10-K, we sometimes collectively refer to the generating
facilities and operations to be transferred to Texas Genco in the Restructuring
as our "Texas generation business." If Reliant Resources exercises the Texas
Genco Option, the Texas Genco operations will cease to be part of our business
in 2004. If Reliant Resources does not exercise the Texas Genco Option, we may
continue to operate Texas Genco or dispose of its operations. For more
information about the Texas Genco Option, please read "Reliant Energy's
Relationship With Reliant Resources -- Intercompany Agreements -- Texas Genco
Option Agreement" in Item 1 of this Form 10-K.

After the Restructuring, our transmission and distribution operations,
which also were part of Reliant Energy HL&P throughout 2001, will comprise
substantially all of the ongoing operations of the entity now known as Reliant
Energy. As described above in "-- Business Separation," that entity will become
CenterPoint Houston, a limited liability company. In this Form 10-K, we refer to
our transmission and distribution operations, operated since January 1, 2002, as
a functionally separate unit by Reliant Energy and as they will be operated by
CenterPoint Houston after the Restructuring, as the "T&D Utility."

ERCOT MARKET FRAMEWORK

The state of Texas, other than a portion of the panhandle and a portion of
the eastern part of the state bordering on Louisiana, constitutes a single
reliability council (ERCOT market). On July 31, 2001, as part of the transition
to deregulation in Texas, the Electric Reliability Council of Texas, Inc.
(ERCOT) changed its operations from ten control areas, each managed by one of
the utilities in the state, to a single control area managed by ERCOT. The ERCOT
independent system operator (ERCOT ISO) is responsible for maintaining reliable
operations of the bulk electric power supply system in the ERCOT market. Its
responsibilities include ensuring that information relating to a customer's
choice of retail electric provider is conveyed in a timely manner to anyone
needing the information. It is also responsible for ensuring that electricity
production and delivery are accurately accounted for among the generation
resources and wholesale
9

buyers and sellers in the ERCOT market. Unlike independent systems operators in
other regions of the country, ERCOT is not a centrally dispatched power pool and
the ERCOT ISO does not procure energy on behalf of its members other than to
maintain the reliable operations of the transmission system. Members are
responsible for contracting their energy requirements bilaterally. ERCOT also
serves as agent for procuring ancillary services for those who elect not to
provide their own ancillary service requirement.

Members of ERCOT include retail customers, investor and municipally owned
electric utilities, rural electric co-operatives, river authorities, independent
generators, power marketers and retail electric providers. The ERCOT market
operates under the reliability standards set by the North American Electric
Reliability Council. The Texas Utility Commission has primary jurisdiction over
the ERCOT market to ensure the adequacy and reliability of electricity across
the state's main interconnected power grid. For information regarding ERCOT
systems problems and delays, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Our Future Earnings -- Factors Affecting the Results of Our Retail Energy
Operations -- Operational Risks" in Item 7 of this Form 10-K.

As part of the change to a single control area, ERCOT initially established
three congestion zones: north, west and south. These congestion zones are
determined by physical constraints on the ERCOT transmission system that make it
difficult or impossible at times to move power from a zone on one side of the
constraint to the zone on the other side of the constraint. ERCOT will perform
an annual analysis of the transmission capability and constraints in ERCOT to
determine if changes to the congestion zones are required. Any required changes
will take effect January 1 of the following year. Such an analysis was performed
in the fall of 2001 and as a result, ERCOT was reorganized into four congestion
zones on January 1, 2002. The current zones are north, south, west and Houston.
In addition, ERCOT conducts annual and monthly auctions of Transmission
Congestion Rights (TCR) which provide the entity owning TCRs the ability to
financially hedge price differences between zones (basis risk). Entities are
currently limited to owning a maximum of 25% of the available TCRs. The
transmission and distribution, generation and retail load that were formerly
conducted under or served by Reliant Energy HL&P are predominately in the
Houston zone. For additional information regarding these operations, please read
"-- Transmission and Distribution," and "-- Generation" in Item 1 of this Form
10-K. For additional information regarding the retail load obligations of our
Retail Energy business segment, please read "Retail Energy -- Retail Energy
Supply" in Item 1 of this Form 10-K.

TRANSMISSION AND DISTRIBUTION

All of the transmission and distribution operating properties in our
Electric Operations business segment are located in the State of Texas. Our
transmission system carries electricity from power plants to substations and
from one substation to another. These substations serve to connect the power
plants, the high voltage transmission lines and the lower voltage distribution
lines. Unlike the transmission system, which carries high voltage electricity
over long distances, distribution lines carry lower voltage power from the
substation to customers. The distribution system consists of primary
distribution lines, transformers, secondary distribution lines and service
wires.

Under the Texas Electric Restructuring Law, our T&D Utility cannot buy or
sell electricity (except for its own consumption) and thus is no longer subject
to commodity risk. Rates for the T&D Utility will continue to be set by the
Texas Utility Commission, and we will be allowed to provide services under
approved tariffs. Pursuant to the Texas Electric Restructuring Law, the Texas
Utility Commission issued an order (Docket No. 22355) setting rates for the T&D
Utility, which became effective on January 1, 2002. In our appeal of certain
aspects of the order, the Travis County District Court generally upheld the
Texas Utility Commission's order. We may appeal the district court's decision in
the Texas Court of Appeals, but have not yet filed such an appeal. For
additional information regarding those rates, please read "Regulation -- State
and Local Regulations -- Texas -- Electric Operations -- Rate Case" in Item 1 of
this Form 10-K.

Historically, Reliant Energy HL&P paid the incorporated municipalities in
its service territory a franchise fee based on a formula that was usually a
percentage of revenues received from electricity sales for consumption within
each municipality. Since January 1, 2002, the T&D Utility has become responsible
for Reliant Energy HL&P's obligations under these franchise arrangements.
Pursuant to the Texas Electric

10

Restructuring Law, the franchise fee payable by the T&D Utility to each
municipality is based on the megawatt hours (MWh) delivered to customers within
each municipality in 2002 and beyond. The amount per MWh payable by the T&D
Utility is based on the franchise fees paid and the MWh consumed within each
municipality in 1998. We expect the franchise fees payable by the T&D Utility to
remain consistent with the fees paid by Reliant Energy HL&P; however, the new
fees could be higher if electricity sales increase. The T&D Utility would be
able to adjust its rates to recover such an increase only through a general T&D
Utility rate case in which all of its expenses and revenues were subject to
review.

Electric Lines -- Overhead. As of December 31, 2001, we owned 25,998 pole
miles of overhead distribution lines and 3,606 circuit miles of overhead
transmission lines, including 452 circuit miles operated at 69,000 volts, 2,095
circuit miles operated at 138,000 volts and 1,059 circuit miles operated at
345,000 volts.

Electric Lines -- Underground. As of December 31, 2001, we owned 12,701
circuit miles of underground distribution lines and 15.6 circuit miles of
underground transmission lines, including 4.5 circuit miles operated at 69,000
volts and 11.1 circuit miles operated at 138,000 volts.

Substations. As of December 31, 2001, we owned 223 major substation sites
(252 substations) having total installed rated transformer capacity of 64,783
megavolt amperes.

GENERATION

As of December 31, 2001, we owned and operated through our Texas generation
business 12 power generating stations (62 generating units) with a net
generating capacity of 14,095 megawatts (MW), including a 30.8% interest in the
South Texas Project Electric Generating Station (South Texas Project). The South
Texas Project is a nuclear generating station with two 1,250 MW nuclear
generating units. For additional information regarding the South Texas Project,
please read Note 6 to our consolidated financial statements. After the
Restructuring, our Texas generation business will be owned by Texas Genco.
Effective January 1, 2002, our Texas generation business will be reported
separately as a new business segment, Electric Generation. Beginning January 1,
2002, our Texas generation business has been operated as an independent power
producer, with output sold at market prices to a variety of purchasers, which
include Reliant Resources and its subsidiaries. Because of this change,
historical operating data, such as demand and fuel data, may not accurately
reflect the operation of this business subsequent to December 31, 2001.

The Texas market currently has a surplus of generating capacity, which
helps to facilitate a competitive wholesale market. Generators in ERCOT added
6,925 MW of new capacity in 2001. Due to the large quantity of generation built
recently, it is anticipated that the wholesale market in Texas will be extremely
competitive for the next three to five years.

The table below contains information regarding the system capability at
peak demand of our generation facilities, which, during the periods shown, were
dedicated to providing generation for Reliant Energy HL&P's service territory.
Sales of electricity by our Electric Operations business segment during the
summer months have generally been higher than sales during other months of the
year due to the reliance on air conditioning by customers in Houston and in
other parts of Reliant Energy HL&P's service territory.

11

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

(1) Excludes loads on interruptible service tariffs, residential direct load
control and commercial/industrial load cooperative capability. Including
these loads, the maximum hourly demand served was 14,272 MW in 1998, 14,642
MW in 1999, 15,505 MW in 2000 and 14,210 MW in 2001.

(2) Maximum hourly firm demand in 1998 and 2000 was influenced by customer
growth and hotter than normal weather at the time of the system peak. The
extremely hot weather conditions at peak periods in Reliant Energy HL&P's
service area during the summer of 2000 increased system peak load by
approximately 1,100 MW.

(3) At any given time we have the ability to enter, and have entered, into
non-firm contracts for purchased power on the spot market within ERCOT, to
provide additional total capability. The addition of 6,925 MW of capacity in
ERCOT in 2001, during which we experienced normal weather conditions,
resulted in ERCOT reserve margins of 28%, significantly more than the 15%
ERCOT minimum requirement. Although ERCOT historically has set operating
reserve margins for its participants in the Texas market, ERCOT is in the
process of reviewing its reserve margin protocols as a result of changes in
the Texas market since the implementation of the Texas Electric
Restructuring Law. In order to assure capacity to meet future demand
requirements, both ERCOT and the Texas Utility Commission are reviewing
procedures which would require market participants to provide adequate
planning reserves.

(4) Includes 450 MW of firm capacity purchased to meet peak demand.

Facilities. The assets in our Texas generation business are described in
the table below.

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

(1) The designations "Base," "Inter," "Cyclic" and "Peak" indicate whether the
units at the stations described are base-load, intermediate, cyclic or
peaking units, respectively.

(2) The capacity of the W.A. Parish facility was uprated from 3,606 MW to 3,661
MW on November 1, 2001.

(3) The capacity of the Limestone facility was uprated from 1,532 MW to 1,612 MW
on January 1, 2002.

(4) We own a 30.8% interest in the South Texas Project electric generating
station, a nuclear generating plant consisting of two 1,250 MW generating
units.

(5) This facility is a "cogeneration" facility. Please read the discussion
below.

Power generation facilities can generally be categorized by their variable
cost to produce electricity, which determines the order in which they are
utilized to meet fluctuations in electricity demand. The largest component of
variable cost is fuel cost. "Base-load" facilities are those that typically have
low fuel costs to

12

generate electricity and provide power at all times. Base-load facilities are
used to satisfy the base level of demand for power, or "load," that is not
dependent upon time of day or weather. "Peaking" facilities generally have the
highest fuel costs to generate electricity and typically are used only during
periods of highest demand for power. "Intermediate" and "cyclic" facilities have
cost and usage characteristics in between those of base-load and peaking
facilities. Cyclic facilities generally operate with frequent starts and stops,
and generally at lower efficiencies and higher operating costs than base-load
plants. The various tiers of base-load, intermediate, cyclic and peaking
facilities serving a particular region are often referred to as the "supply
curve" or "dispatch curve" for that region. Power generation facilities can also
be categorized as "cogeneration" facilities. Cogeneration is the combined
production of steam and electricity in a generation facility. Cogeneration
facilities typically operate at base load and higher thermal efficiency than
other forms of fossil-fuel-fired generation facilities.

For information regarding the possible impairment for accounting purposes
of these generating assets after the transition to market based rates and the
recovery of these amounts, please read Notes 2(e) and 4(a) to our consolidated
financial statements.

Market Framework. Historically, most power generation in Texas came from
integrated utilities and was sold to retail customers at regulated rates.
However, since 1996, independent power producers have been permitted to sell
their entire load of electricity, capacity and ancillary services to wholesale
purchasers at unregulated rates. Since January 1, 2002, any wholesale producer
of electricity that qualifies as a "power generation company" under the Texas
Electric Restructuring Law and that can access the ERCOT electric grid is
allowed to sell power in the Texas market at unregulated rates. Transmission
capacity, which may be limited, is needed to effect power sales. In the Texas
market, buyers and sellers may negotiate bilateral wholesale capacity, energy
and ancillary services contracts. Also, companies or business units whose power
generation facilities were formerly part of integrated utilities, like our Texas
generation business, must auction entitlements to 15% of their capacity as
described below. Furthermore, buyers and sellers may participate in the spot
market.

Operations and Capacity Auctions Generally. Since January 1, 2002, we have
operated our Texas generation business solely in the wholesale market. We are
required by the Texas Electric Restructuring Law to auction 15% of the capacity
of our Texas generation business and by the master separation agreement to
auction the remainder of the capacity of our Texas generation business. We may
satisfy these capacity auction obligations either by producing electricity in
our own power plants or by purchasing power in wholesale transactions. Our
auction products are only entitlements to capacity dispatched from base,
intermediate, cyclic or peaking units and do not convey a right to receive power
from a particular unit. This enables us to dispatch our commitments in the most
cost-effective manner, but also exposes us to the risk that, depending upon the
availability of our units, we could be required to supply energy from a higher
cost unit, such as an intermediate unit, to meet an obligation for lower cost
generation, such as base-load generation or to obtain the energy on the open
market. In addition, from time to time, we may be required to purchase power
from qualifying facilities under the Public Utility Regulatory Policies Act of
1978 (PURPA). For information about purchased power obligations, please read
"-- Fuel and Purchased Power -- Purchased Power Supply" in Item 1 of this Form
10-K.

Revenues from capacity auctions come from two sources: capacity payments
and fuel payments. Capacity payments are based on the final clearing prices, in
dollars per kilowatt-month, determined during the auctions. We bill for these
payments on a monthly basis just prior to the month of the entitlement. Fuel
payments consist of a variety of charges related to the fuel and ancillary
services scheduled through the auctioned products. We invoice for these fuel
payments on a monthly basis in arrears. Please read "-- Fuel and Purchased
Power" in Item 1 of this Form 10-K.

State Mandated Capacity Auctions. Under the Texas Electric Restructuring
Law, each power generator that is unbundled from an integrated electric utility
in Texas, including our Texas generation business, is required to sell at
auction 15% of the output of its installed generating capacity (state mandated
auctions). This obligation to conduct state mandated auctions will continue
until January 1, 2007, unless before that date the Texas Utility Commission
determines that at least 40% of the electric power consumed before the onset of

13

competition by residential and small commercial customers in the T&D Utility's
service area is being served by retail electric providers not affiliated or
formerly affiliated with us as an integrated utility. The Texas Utility
Commission has determined Reliant Resources is our affiliate and will be an
affiliate of Texas Genco for this purpose. Reliant Resources is not permitted
under the Texas Electric Restructuring Law to purchase capacity sold by us or by
Texas Genco in the state mandated auctions.

The products we are, and Texas Genco will be, required to offer in the
state mandated auctions are determined by rules adopted by the Texas Utility
Commission. The aggregate products sold under the state mandated auctions
consist of 700 MW of base-load, 875 MW of intermediate, 400 MW of cyclic and 150
MW of peaking capacity. These products are sold in the form of "entitlements,"
which consist of obligations to provide 25 MW of capacity for terms of one
month, one year and two years. Texas Utility Commission rules require 50% of
available auctioned products to consist of one-month entitlements, 30% to
consist of one-year strips and 20% to consist of two-year strips. Purchasers of
products offered in the state mandated auctions may resell them to third parties
other than an affiliated retail electric provider.

Contractually Mandated Capacity Auctions. Pursuant to the master
separation agreement, and subject to the permitted reductions described below,
we are, and Texas Genco will be, contractually obligated to auction to third
parties, including Reliant Resources, all of the capacity and related ancillary
services available in excess of amounts included in the state mandated auctions
until the date on which the Texas Genco Option either is exercised or expires
(contractually mandated auctions). We and Texas Genco are permitted to reduce
the amount of capacity sold in the contractually mandated auctions by the amount
required to satisfy:

- our operational requirements associated with the capacity sold pursuant
to the Texas Utility Commission rules, including the rules associated
with state mandated auctions and the price to beat; or

- our obligations to another party under an existing spinning reserve
service agreement.

Texas Utility Commission rules do not restrict the types of products we and
Texas Genco may offer in the contractually mandated auctions. Therefore, we set
the terms of the products offered in these auctions. We structure the products
in the contractually mandated auctions to correspond with operating
characteristics of the underlying generating units, such as heat rates and
minimum load levels. Pursuant to the master separation agreement, Reliant
Resources is entitled to purchase, prior to our submission of capacity to
auction, 50% (but not less than 50%) of the capacity we have available to
auction in the contractually mandated auctions at the prices bid by third
parties in the contractually mandated auctions. Whether or not Reliant Resources
exercises this right, Reliant Resources may submit bids to purchase in the
contractually mandated auctions as well.

Initial Auctions. We conducted state mandated auctions in September 2001
and March 2002 and contractually mandated auctions in October and December 2001
and March 2002. Excluding reserves for planned and forced outages, as a result
of these auctions, our Texas generation business has sold entitlements to all of
its capacity through August 2002, an average of 72% per month of its capacity
through December 2002 and 10% of its capacity for each month in 2003. In the
contractually mandated auctions held so far, Reliant Resources has purchased, on
average, 72% per month of the 2002 capacity sold by us and 58% per month of our
2003 capacity sold in the auctions. These purchases have been made either
through the exercise by Reliant Resources of its contractual rights or through
the submission of bids.

The capacity auctions were consummated at market-based prices that are
substantially below the historical regulated return on the facilities in our
Texas generation business. The Texas Electric Restructuring Law provides for the
recovery in a "true-up" proceeding of any difference between market power prices
received in the capacity auctions and the Texas Utility Commission's earlier
estimates of those market prices. For additional information regarding the
capacity auctions and the related true-up proceeding, please read Note 4 to our
consolidated financial statements.

We intend to conduct an auction in July 2002 to sell the remaining
available capacity for September through December 2002. Beginning in September
2002, we intend to hold auctions to sell remaining capacity for the year 2003.

14

FUEL AND PURCHASED POWER

We rely primarily on natural gas, coal and lignite to fuel the facilities
in our Texas generation business. For information regarding our fuel contracts,
please read Note 14(a) to our consolidated financial statements. The 2000 and
2001 historical energy mix for our Texas generation business is set forth below.
These figures represent the generation and purchased power used to meet system
load and for off-system sales:

As a result of new air emissions standards imposed by federal and state
law, we anticipate longer plant outages in 2002 and higher levels of plant
maintenance in 2003 and subsequent years associated with the installation of
environmental equipment on our generating facilities. These factors could affect
the fuel mix of our Texas generation business. We anticipate that the capital
investment incurred through May 2003 to comply with these air emissions
requirements will be recoverable through the Texas Utility Commission's
determination of stranded costs. Please read "-- Environmental Matters" in Item
1 of this Form 10-K and Note 4 to our consolidated financial statements.

Through December 31, 2001, the Texas Utility Commission provided for the
recovery of most fuel and purchased power costs from customers through a fixed
fuel factor included in electric rates. Following the transition to retail
competition in January 2002, the energy sales of our Texas generation business
are based on the generation capacity entitlement auctions described above. Power
generated from the intermediate, cyclic or peaking entitlements in the capacity
auctions includes a fuel cost component that is tied to the indexed cost of gas,
reducing the risk associated with the price of gas for our Texas generation
business. Successful bidders in these auctions are able to dispatch energy from
their entitlements within the operational constraints of the generating units
supporting the capacity entitlement product they purchased. Under the terms of
the capacity auctions, successful bidders are required to absorb the
corresponding fuel cost for the energy dispatched so that, in effect, we will
recover our dispatch-based fuel costs from these bidders. For additional
information regarding our ability to recover these costs from customers before
and after the inception of retail electric competition, please read
"Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" in Item 1 of this Form 10-K
and Note 4(a) to our consolidated financial statements.

Natural Gas Supply. We obtain our long-term natural gas supply under
contracts with El Paso Merchant Energy-Gas L.P., HPL Resources Company and
Kinder Morgan Texas Pipeline, Inc. Our contract with Kinder Morgan is nearing
the end of its term and we are in the process of negotiating another long-term
contract with them, which we expect to sign in the second quarter of 2002.
Substantially all of our long-term natural gas supply contracts contain pricing
provisions based on fluctuating spot market prices. In 2001, 61% of the natural
gas requirements for our Texas generation business was purchased under these
long-term contracts, including 34% under the contract with Kinder Morgan. The
remaining 39% of natural gas requirements in 2001 was purchased on the spot
market. Based on current market conditions, we believe we will be able to
replace the supplies of natural gas covered under our long-term contracts when
they expire with gas purchased on the spot market or under new long-term or
short-term contracts if we continue to own Texas

15

Genco after 2004. The natural gas consumption and cost information for our Texas
generation business in the year 2001 was as follows:

2001 average daily consumption............................. 535 Bbtu (1)
2001 peak daily consumption................................ 1,282 Bbtu
Average cost of natural gas................................ $ 4.23 per MMBtu (2)

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

(1) Billion British thermal units (Bbtu).

(2) Compared to $3.98 per million British thermal units (MMBtu) in 2000 and
$2.47 per MMBtu in 1999.

Our natural gas requirements are generally more volatile than our other
fuel requirements because we use natural gas to fuel intermediate, cyclic and
peaking facilities and other more economical fuels to fuel base-load facilities.
Although natural gas supplies have been sufficient in recent years, available
supplies are subject to potential disruption due to weather conditions,
transportation constraints and other events. As a result of these factors,
supplies of natural gas may become unavailable from time to time or prices may
increase rapidly in response to temporary supply constraints or other factors.
In 2001, prices for natural gas became more volatile due to market conditions.

Coal and Lignite Supply. We purchased approximately 80% of the fuel
requirements for our four coal-fired generating units at our W.A. Parish
facility under two fixed-quantity, long-term supply contracts with Kennecott
Energy. Kennecott Energy supplies subbituminous coal under these contracts from
mines in the Powder River Basin of Wyoming. The first of these contracts is
scheduled to expire in 2010, and the second is scheduled to expire in 2011. The
price for coal is fixed under one of these contracts through the end of 2002,
after which the price will be tied to spot market prices. The price for coal
under the second contract was approximately three times greater than the spot
market prices for coal as of December 31, 2001. We purchased our remaining coal
requirements for the W.A. Parish facility under short-term contracts. We have
long-term rail transportation contracts with the Burlington Northern Santa Fe
Railroad Company and the Union Pacific Railroad Company to transport coal to the
W.A. Parish facility.

We obtain the lignite used to fuel the two generating units of the
Limestone facility from a surface mine adjacent to the facility. We own the
mining equipment and facilities and a portion of the lignite reserves located at
the mine. During the first six months of 2002, we will obtain our lignite
requirements under a long-term, cost-plus agreement with Westmoreland Coal
Company. We expect to blend petroleum coke with lignite to fuel the Limestone
facility in this period. Beginning July 2002, we will obtain our lignite
requirements under an agreement with Westmoreland Coal Company at a fixed price
determined annually that results in a cost of generation at the Limestone
facility equivalent to the cost of generating with Wyoming coal. We expect the
lignite reserves will be sufficient to provide all of the lignite requirements
of this facility through 2015.

During 2000, we conducted a successful test burn of Wyoming coal at the
Limestone facility. We anticipate using a blend of lignite and Wyoming coal to
fuel the Limestone facility beginning in July 2002 as a component of our
nitrogen oxides (NOx) control strategy. A fuel unloading and handling system is
being installed at the Limestone facility to accommodate the delivery of Wyoming
coal. We expect to obtain Wyoming coal and rail transportation services through
spot and long-term market-priced contracts.

Nuclear Fuel Supply. The South Texas Project satisfies its fuel supply
requirements by acquiring uranium concentrates, converting uranium concentrates
into uranium hexafluoride, enriching uranium hexafluoride and fabricating
nuclear fuel assemblies.

We are a party to numerous contracts covering a portion of nuclear fuel
needs of the South Texas Project for uranium, conversion services, enrichment
services and fuel fabrication. Other than a fuel fabrication agreement that
extends for the life of the South Texas Project plant, these contracts have
varying expiration dates, and most are short to medium term (less than seven
years). Management believes that sufficient capacity for nuclear fuel supplies
and processing exists to permit normal operations of the South Texas Project's
nuclear generating units.

16

Purchased Power Supply. Prior to January 1, 2002, Reliant Energy HL&P
purchased power from various qualifying facilities exercising their rights under
PURPA. These purchases were generally at the discretion of the qualifying
facilities and were made pursuant to a pricing methodology defined in tariffs
approved by the Texas Utility Commission and pursuant to agreements between
Reliant Energy HL&P and the qualifying facilities. Reliant Energy HL&P purchased
a total of 16.4 million MWh and 19 million MWh from qualifying facilities in
2000 and 2001, respectively. Reliant Energy HL&P terminated all but two of its
agreements with the qualifying facilities in 2001 pursuant to the terms of the
agreements. The remaining two agreements expire March 31, 2005. The rights and
obligations under the two remaining agreements will be assigned to Texas Genco
in the Restructuring if they are not assigned to third parties.

As a result of the separation of Reliant Energy HL&P's utility functions,
the T&D Utility will not be subject to PURPA and the Texas Utility
Commission-approved tariffs in place before January 1, 2002 will no longer be
effective. However, our Texas generation business and the retail electric
providers under Reliant Resources will remain subject to PURPA. On January 23,
2002, certain qualifying facilities, including qualifying facilities that have
traditionally delivered power to Reliant Energy HL&P, filed an enforcement
action with the Federal Energy Regulatory Commission (FERC) seeking to force the
Texas Utility Commission to implement PURPA for Texas entities subject to PURPA
(FERC Docket No. EL02-55). On February 15, 2002, FERC filed notice of its
intention not to act on this enforcement action. These qualifying facilities
have the right to appeal this decision in federal court. In the meantime, the
Texas Utility Commission is in the midst of a rulemaking proceeding to determine
whether it has the authority to regulate the PURPA obligations of any entity
and, if so, how such entity will implement its obligations, including a
methodology for pricing of these purchases. We anticipate that this rulemaking
will conclude in the second quarter of 2002. The proposed rule published by the
Texas Utility Commission does not apply to Texas generation businesses. If the
final rule is the same in this respect, our Texas generation business will self-
implement its PURPA obligations and will not be required to seek approval of its
pricing methodology from the Texas Utility Commission.

COMPETITION

The T&D Utility's operations are regulated by the Texas Utility Commission
and are conducted within its service territory pursuant to a Certificate of
Convenience and Necessity issued by the Texas Utility Commission. In order for
another provider of transmission and distribution services to provide such
services in the T&D Utility's territory, it would be required to obtain a
Certificate of Convenience and Necessity in proceedings before the Texas Utility
Commission. Our Texas generation business competes with other power generation
companies, including the now-unregulated generating facilities of other electric
utilities, independent power producers who own generation facilities for the
purpose of selling power in wholesale markets and power produced by cogenerators
and other qualified facilities. Due to the large quantity of generation built
recently in ERCOT, it is anticipated that the wholesale power market in Texas in
which our Texas generation business competes will be extremely competitive for
the next three to five years.

Please read "Electric Operations -- ERCOT Market Framework" in Item 1 of
this Form 10-K and "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Electric Operations" in Item 7
of this Form 10-K, which sections are incorporated herein by reference.

NATURAL GAS DISTRIBUTION

Our Natural Gas Distribution business segment consists of intrastate
natural gas sales to, and natural gas transportation for, residential,
commercial and industrial customers in Arkansas, Louisiana, Minnesota,
Mississippi, Oklahoma and Texas and some non-rate regulated retail gas marketing
operations.

We conduct intrastate natural gas sales to, and natural gas transportation
for, residential, commercial and industrial customers through three
unincorporated divisions of RERC Corp.: Arkla, Entex and Minnegasco. These
operations are regulated as gas utility operations in the jurisdictions served
by these divisions.

17

- Arkla. Arkla provides natural gas distribution services in over 245
communities in Arkansas, Louisiana, Oklahoma and Texas. The largest
metropolitan areas served by Arkla are Little Rock, Arkansas and
Shreveport, Louisiana. In 2001, approximately 65% of Arkla's total
throughput was attributable to retail sales of gas and approximately 35%
was attributable to transportation services.

- Entex. Entex provides natural gas distribution services in over 500
communities in Louisiana, Mississippi and Texas. The largest metropolitan
area served by Entex is Houston, Texas. In 2001, approximately 97% of
Entex's total throughput was attributable to retail sales of gas and
approximately 3% was attributable to transportation services.

- Minnegasco. Minnegasco provides natural gas distribution services in
over 240 communities in Minnesota. The largest metropolitan area served
by Minnegasco is Minneapolis, Minnesota. In 2001, approximately 97% of
Minnegasco's total throughput was attributable to retail sales of gas and
approximately 3% was attributable to transportation services.

The demand for intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers is
seasonal. In 2001, approximately 62% of our Natural Gas Distribution business
segment's total throughput occurred in the first and fourth quarters. These
patterns reflect the higher demand for natural gas for heating purposes during
those periods. For information about our plan to separate the operations of
Arkla, Entex and Minnegasco among different business entities, please read "Our
Business -- RERC Corp. Restructuring" in Item 1 of this Form 10-K.

COMMERCIAL AND INDUSTRIAL MARKETING SALES

Our Natural Gas Distribution business segment's commercial and industrial
marketing sales group provides comprehensive natural gas products and services
to commercial and industrial customers in the region from Southern Texas to the
panhandle of Florida, as well as in the Midwestern United States. In 2001,
approximately 96% of total throughput was attributable to the sale of natural
gas and approximately 4% was attributable to transportation services. Typical
customer contract terms for natural gas sales range from one day to three years.
Our commercial and industrial marketing sales groups' operations may be affected
by seasonal weather changes and the relative price of natural gas. In 2000, the
commercial and industrial marketing sales group exited all retail gas markets in
non-strategic areas of the Northeast and Mid-Atlantic, allowing us to focus
resources and efforts in our core geographical areas of the Gulf South and
Midwest.

SUPPLY AND TRANSPORTATION

Arkla. In 2001, Arkla purchased approximately 53% of its natural gas
supply from Reliant Energy Services, 29% pursuant to third-party contracts, with
terms varying from three months to one year, and 18% on the spot market. Arkla's
major third-party natural gas suppliers in 2001 included Oneok Gas Marketing
Company, Tenaska Marketing Ventures, Marathon Oil Company and BP Energy Company.
Arkla transports substantially all of its natural gas supplies under contracts
with our pipeline subsidiaries.

Entex. In 2001, Entex purchased virtually all of its natural gas supply
pursuant to term contracts, with terms varying from one to five years. Entex's
major third-party natural gas suppliers in 2001 included AEP Houston Pipeline,
Kinder Morgan Texas Pipeline, L.P., Gulf Energy Marketing, Island Fuel Trading
and Koch Energy Trading. Entex transports its natural gas supplies on both
interstate and intrastate pipelines under long-term contracts with terms varying
from one to five years.

Minnegasco. In 2001, Minnegasco purchased approximately 74% of its natural
gas supply pursuant to term contracts, with terms varying from one to ten years,
with more than 20 different suppliers. Minnegasco purchased the remaining 26% on
the daily or spot market. Most of the natural gas volumes under long-term
contracts are committed under terms providing for delivery during the winter
heating season, which extends from November through March. Minnegasco purchased
approximately 67% of its natural gas requirements from four suppliers in 2001:
Tenaska Marketing Ventures, Reliant Energy Services, Pan-Alberta Gas Ltd., and
TransCanada Gas Services Inc. Minnegasco transports its natural gas supplies on
various interstate pipelines under long-term contracts with terms varying from
one to five years.

18

For additional information regarding our ability to pass through changes in
natural gas prices to our customers, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Competitive and Other Factors Affecting RERC
Operations -- Natural Gas Distribution" in Item 7 of this Form 10-K.

Arkla and Minnegasco use various leased or owned natural gas storage
facilities to meet peak-day requirements and to manage the daily changes in
demand due to changes in weather. Minnegasco also supplements contracted
supplies and storage from time to time with stored liquefied natural gas and
propane-air plant production.

Minnegasco owns and operates a 7.0 billion cubic feet (Bcf) underground
storage facility, having a working capacity of 2.1 Bcf available for use during
a normal heating season and a maximum daily withdrawal rate of 50 million cubic
feet (MMcf) per day. Minnegasco also owns ten propane-air plants with a total
capacity of 191 MMcf per day and on-site storage facilities for 11 million
gallons of propane (1.0 Bcf gas equivalent). Minnegasco owns a liquefied natural
gas facility with a 12 million-gallon liquefied natural gas storage tank (1.0
Bcf gas equivalent) with a send-out capability of 72 MMcf per day.

Although available natural gas supplies have exceeded demand for several
years, currently supply and demand appear to be more balanced. Our Natural Gas
Distribution business segment has sufficient supplies and pipeline capacity
under contract to meet its firm customer requirements. However, from time to
time, it is possible for limited service disruptions to occur due to weather
conditions, transportation constraints and other events. As a result of these
factors, supplies of natural gas may become unavailable from time to time or
prices may increase rapidly in response to temporary supply constraints or other
factors.

ASSETS

As of December 31, 2001, we owned approximately 61,000 linear miles of gas
distribution mains, varying in size from one-half inch to 24 inches in diameter.
Generally, in each of the cities, towns and rural areas served by our Natural
Gas Distribution business segment, we own the underground gas mains and service
lines, metering and regulating equipment located on customers' premises and the
district regulating equipment necessary for pressure maintenance. With a few
exceptions, the measuring stations at which we receive gas from our suppliers
are owned, operated and maintained by others, and our distribution facilities
begin at the outlet of the measuring equipment. These facilities, including
odorizing equipment, are usually located on the land owned by suppliers.

COMPETITION

Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive and Other Factors Affecting RERC Operations -- Natural
Gas Distribution" in Item 7 of this Form 10-K, which section is incorporated
herein by reference.

PIPELINES AND GATHERING

Our Pipelines and Gathering business segment operates two interstate
natural gas pipelines as well as gas gathering and pipeline services. Our
pipeline operations are primarily conducted by two wholly owned interstate
pipeline subsidiaries of RERC Corp., Reliant Energy Gas Transmission Company
(REGT) and Mississippi River Transmission Corporation (MRT). Our gathering and
pipeline services operations are conducted by a wholly owned gas gathering
subsidiary, Reliant Energy Field Services, Inc. (REFS), and a wholly owned
pipeline services subsidiary, Reliant Energy Pipeline Services, Inc. (REPS).

Through REFS, we provide natural gas gathering and related services,
including related liquids extraction and other well operating services. As of
December 31, 2001, REFS operated approximately 4,300 miles of gathering
pipelines, which collect natural gas from more than 300 separate systems located
in major producing fields in Arkansas, Louisiana, Oklahoma and Texas. Through
REPS, we provide pipeline project management and facility operation services to
affiliates and third parties.
19

In 2001, approximately 25% of our Pipelines and Gathering business
segment's total operating revenue was attributable to services provided by REGT
to Arkla, and approximately 10% of its total operating revenue was attributable
to services provided by MRT to Laclede Gas Company (Laclede), an unaffiliated
distribution company that provides natural gas utility service to the greater
St. Louis metropolitan area in Illinois and Missouri. An additional 20% of our
Pipelines and Gathering business segment's operating revenues was attributable
to the transportation of gas marketed by Reliant Energy Services. Our Pipelines
and Gathering business segment provides service to Arkla and Laclede under
several long-term firm storage and transportation agreements. REGT and Arkla
have entered into various contracts for firm transportation in Arkla's major
service areas that are currently scheduled to expire in 2005. In February 2002,
MRT negotiated an agreement to extend its existing service relationship with
Laclede for a five-year period subject to acceptance by the FERC.

The business and operations of our Pipelines and Gathering business segment
may be affected by seasonal changes in the demand for natural gas, the relative
price of natural gas in the Midcontinent and Gulf Coast natural gas supply
regions and, to a lesser extent, general economic conditions.

ASSETS

We own and operate approximately 8,100 miles of gas transmission lines. We
also own and operate six natural gas storage fields with a combined daily
deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 55.8 Bcf. REGT also owns a 10% interest, with Gulf
South Pipeline Company, LP, in the Bistineau storage facility with 68.8 Bcf of
working gas capacity and 1.1 Bcf per day of deliverability. REGT's storage
capacity in the Bistineau facility is 18 Bcf (8 Bcf of working gas) with 100
MMcf per day of deliverability. Most of our storage operations are in north
Louisiana and Oklahoma. We also own and operate approximately 4,300 miles of
gathering pipelines that collect gas from more than 300 separate systems located
in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.

COMPETITION

Please read "Management's Discussion and Analysis of Financial Condition
and Results of Operations -- Certain Factors affecting Our Future
Earnings -- Competitive and Other Factors Affecting RERC Operations -- Pipelines
and Gathering" in Item 7 of this Form 10-K, which section is incorporated herein
by reference.

WHOLESALE ENERGY

Our Wholesale Energy business segment, which is conducted through Reliant
Resources, provides energy and energy services with a focus on the competitive
wholesale segment of the United States energy industry. We acquire, develop and
operate electric power generation facilities that are not subject to traditional
cost-based regulation and therefore can generally sell power at prices
determined by the market, subject to regulatory limitations in certain regions.
We also trade and market power, natural gas, natural gas transportation capacity
and other energy-related commodities and provide related risk management
services. Our Wholesale Energy business segment will remain with Reliant
Resources in the Separation and will not be part of our business after the
Distribution.

POWER GENERATION OPERATIONS

As of December 31, 2001, our Wholesale Energy business segment owned or
leased electric power generation facilities with an aggregate net generating
capacity of 11,109 MW located in five regions of the United States. We also had
3,587 MW (3,391 MW, net of 196 MW to be retired upon completion of one facility)
of net generating capacity under construction as of that date. In addition, by
acquiring Orion Power Holdings, Inc. (Orion Power) in February 2002, we added 81
power plants with an aggregate net generating capacity of 5,644 MW and two
development projects with an additional 804 MW of capacity under construction to
our regional portfolios.

20

The following table describes our Wholesale Energy business segment's
electric power generation facilities by region as of December 31, 2001.

REGIONAL SUMMARY OF OUR GENERATION FACILITIES
(AS OF DECEMBER 31, 2001)

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

(1) Unless otherwise indicated, we own a 100% interest in each facility listed.

(2) We use the designations "Base," "Inter," "Peak" and "CoGen" to indicate
whether the facilities described are base-load, intermediate, peaking or
cogeneration facilities, respectively.

(3) We lease a 100%, 16.67% and 16.45% interest in three Pennsylvania
facilities having 613 MW, 285 MW and 281 MW, respectively, through facility
lease agreements having terms of 26.5 years, 33.75 years and 33.75 years,
respectively.

(4) One of our two construction projects in this region will replace one of our
existing facilities upon completion. Therefore, this project is not
included in the facility count for the "Under Construction" group of this
region.

(5) Our two construction projects in the Northeast region and one of our
projects in the Southeast region are owned by off-balance sheet special
purpose entities and are being constructed under construction agency
agreements pursuant to synthetic leasing arrangements. We expect that we
will lease these facilities from their owners upon completion.

21

(6) The 1,120 MW of net capacity under construction is based on 1,316 MW of
capacity currently under construction less 196 MW of operating capacity
that will be retired upon completion of one of the projects.

(7) Five of the six generating units of one of the facilities in this region
are operational while the sixth unit is under construction. This partially
operational facility is included in the facility count for the "Operating"
group of this region.

(8) We own a 50% interest in one of these facilities. An independent third
party owns the other 50%.

(9) Two of the three generating units of one of the facilities in this region
are operational while the third unit is under construction. This partially
operational facility is included in the facility count for the "Operating"
group of this region.

(10) For information about the Texas Genco Option, please read "Reliant Energy's
Relationship with Reliant Resources -- Intercompany Agreements -- Texas
Genco Option Agreement" in Item 1 of this Form 10-K and Note 4(b) to our
consolidated financial statements.

The following table describes our Orion Power electric power generation
facilities by region as of February 28, 2002.

REGIONAL SUMMARY OF OUR ORION POWER FACILITIES
(AS OF FEBRUARY 28, 2002)

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

(1) We use the designations "Base," "Inter" and "Peak" to indicate whether the
facilities described are base-load, intermediate or peaking, respectively.

(2) Two hydro plants with a net generating capacity of approximately 5 MW are
not currently operational.

NORTHEAST REGION

Facilities. As of December 31, 2001, we owned or leased 21 electric power
generation facilities with an aggregate net generating capacity of 4,262 MW
located in the control area of PJM Interconnection, L.L.C. (PJM ISO), the
independent system operator in the Pennsylvania-New Jersey-Maryland market (PJM
market). These facilities are owned or leased by subsidiaries of Reliant Energy
Mid-Atlantic Power Holdings, LLC (REMA), a wholly owned subsidiary of Reliant
Resources. The generating capacity of these facilities consists of approximately
40% of base-load, 40% of intermediate and 20% of peaking capacity, and
represents approximately 7% of the total generation capacity located in the PJM
ISO's control area. For additional information regarding our acquisition of
these facilities, please read Note 3(a) to our consolidated financial
statements.

By acquiring Orion Power in February 2002, we added 78 power generation
facilities, of which 75 are currently operational, with an aggregate net
generating capacity of 4,174 MW to our Northeast regional

22

portfolio. These facilities include 70 hydroelectric facilities, of which 68 are
currently operational, located in central and northern New York State, three
facilities located in New York City, one facility located in East Syracuse, New
York, and four facilities, three of which are currently fully operational,
located in Pennsylvania. The generating capacity of these facilities consists of
approximately 45% of base-load, 35% of intermediate and 20% of peaking capacity.
For a discussion of factors that may affect the future earnings generated by
these Orion Power facilities, please read "Management's Discussion and Analysis
of Financial Condition and Results of Operations -- Certain Factors Affecting
Our Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations -- Integration and Other Risks Associated With Our Orion Power
Assets" and "-- Uncertainty Related to the New York Regulatory Environment" in
Item 7 of this Form 10-K.

We have begun construction on a 795 MW gas-fired base-load and intermediate
facility located in Pennsylvania. We expect this facility will begin commercial
operation in the second quarter of 2003. We have also begun construction on a
521 MW coal-fired base-load facility, also located in Pennsylvania, that will
replace one of our existing facilities. This facility will add 325 MW of
additional capacity to our Northeast regional portfolio, net of the 196 MW of
capacity of the currently existing facility that will be retired upon
commencement of commercial operations of the new facility. We expect this
facility will begin commercial operation near the end of 2004. These facilities
are owned by off-balance sheet special purpose entities and are being
constructed under the terms of separate construction agency agreements pursuant
to synthetic leasing arrangements. Upon completion of the construction of these
facilities, we expect that we will lease these facilities from their owners,
purchase or remarket each facility. For additional information regarding the
construction agency agreements, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Reliant
Resources-unregulated businesses -- Consolidated Sources of Cash -- Off-Balance
Sheet Transactions -- Construction Agency Agreements" in Item 7 of this Form
10-K and Note 14(l) to our consolidated financial statements.

By acquiring Orion Power in February 2002, we added two additional
development projects with an additional 804 MW of capacity under construction.
The first project is the construction of a 550 MW gas-fired base-load facility
located south of Philadelphia, Pennsylvania. We expect this facility will begin
commercial operation in the second quarter of 2002. The second project is the
conversion and upgrade of a peaking facility located near downtown Pittsburgh,
Pennsylvania. We expect this project will be completed by the third quarter of
2002 and will increase the aggregate generating capacity of this facility by 254
MW to a total capacity of 308 MW.

Market Framework. We currently sell the power generated by our Northeast
regional facilities in the PJM market, the wholesale energy market of the State
of New York (New York wholesale market) operated by the New York Independent
System Operator (NYISO) and to buyers in adjacent power markets, such as the
region covered by the East Central Area Reliability Coordinating Counsel (ECAR
market). We also expect to sell power in a newly created extension of the PJM
market in western Pennsylvania (PJM West market). Each of the PJM Market, the
New York wholesale market and the PJM West market operate as centralized power
pools with open-access, non-discriminatory transmission systems administered by
independent system operators approved by the FERC. Although the transmission
infrastructure within these markets is generally well developed and
independently operated, transmission constraints exist between, and to a certain
extent within, these markets. In particular, transmission of power from eastern
Pennsylvania to western Pennsylvania and into New York City may be constrained
from time to time. Depending on the timing and nature of transmission
constraints, market prices may vary from market to market, or between
sub-regions of a particular market. For example, as a result of transmission
constraints into New York City, power prices are generally higher there than in
other parts of the state.

In addition to managing the transmission system for each market, the
respective independent system operator for each of the PJM market, the New York
wholesale market and the PJM West market is responsible for maintaining
competitive wholesale markets, operating the spot wholesale energy market and
determining the market clearing price based on bids submitted by participating
generators in each market. Each independent system operator generally matches
sellers with buyers within a particular market that meet
23

specified minimum credit standards. We sell capacity, energy and ancillary
services into the markets maintained by the applicable independent system
operator for each of these types of products for both real-time sales and
forward-sales for periods of up to one year. Our customers include the members
of each market, consisting of municipalities, electric cooperatives, integrated
utilities, transmission and distribution utilities, retail electric providers
and power marketers. We also sell capacity, energy and ancillary services to
customers in the Northeast region under negotiated bilateral contracts.
Bilateral contracts, in addition to other physical and financial transactions
enable us to hedge a portion of our generation portfolio. For a more complete
description of our hedging strategy and a summary of the consolidated hedge
position of our United States generating assets (other than those in our Texas
generation business, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations -- Risks Associated with Our Hedging and Risk Management Activities"
in Item 7 of this Form 10-K.

Our markets in the Northeast region are subject to constant and significant
regulatory oversight and control and the results of our operations in the region
may be adversely affected by any changes or additions to the current regulatory
structure. Our sales into markets administered by the PJM ISO are governed by
the PJM ISO's operating agreements, tariffs and protocols (PJM Protocols). The
PJM Protocols provide the structure, rules and pricing mechanisms for the PJM
ISO's energy, capacity and ancillary services markets, and establish rates,
terms and conditions for transmission service in the PJM ISO's control area and
the PJM West market, including transmission congestion pricing. Wholesale energy
prices in the markets administered by the PJM ISO are currently capped at $1,000
per megawatt-hour. Lower caps are utilized in other regions and it is possible
that this price cap might be lowered in the future.

Our sales into markets administered by the NYISO are governed by the
NYISO's tariff and protocols (NYISO Protocols). The NYISO Protocols provide the
structure, rules and pricing mechanisms for the NYISO's energy, capacity and
ancillary services markets, and establish rates, terms and conditions for
transmission service in the NYISO's control area. The NYISO Protocols allow load
to respond to high prices in emergency and non-emergency situations. The lack of
programs, however, to implement load response to prices has been cited as one of
the primary reasons for retaining wholesale energy bid caps, which are currently
set at $1,000 per megawatt-hour. Lower price caps are utilized in other regions
and it is possible that this price cap might be lowered in the future.

A capacity market has been established by the NYISO that ensures that there
is enough generation capacity to meet retail energy demand and ancillary
services requirements. All power retailers are required to demonstrate
commitments for capacity sufficient to meet their peak forecasted load plus a
reserve requirement, currently set at 18%. As an extra reliability measure,
power retailers located in New York City are required to procure the majority of
this capacity, currently 80% of their peak forecasted load, from generating
units located in New York City. Because New York City is currently short of this
capacity requirement and the existing capacity is owned by only a few entities,
a price cap has been instituted for in-city generators.

For additional discussion of the impact of current regulations on the
markets in the Northeast region and the related risks of re-regulation, please
read "-- Regulation -- Federal Energy Regulatory Commission" and "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Industry Restructuring, the
Risk of Re-regulation and the Impact of Current Regulations" and "-- Uncertainty
Related to the New York Regulatory Environment" in Item 7 of this Form 10-K.

MIDWEST REGION

Facilities. As of December 31, 2001, we owned two electric power
generation facilities located in the State of Illinois with an aggregate net
generating capacity of 1,063 MW in operation. One of these facilities is a 344
MW gas-fired peaking generation facility located in Shelby County, Illinois. The
first phase of this facility was initially placed in commercial operation in
June 2000 and the second phase was placed in commercial operation in May 2001.
We also have an 873 MW gas-fired peaking generation facility under construction
in Aurora, Illinois. As of December 31, 2001, five of the six generating units
at this facility with

24

an aggregate net generating capacity of 719 MW had been placed in commercial
operation. We expect the remaining unit at this facility will begin commercial
operation in the second quarter of 2002.

By acquiring Orion Power in February 2002, we added three power generation
facilities with an aggregate net generating capacity of 1,470 MW to our Midwest
regional portfolio. Two of these facilities are located in Ohio and one is
located in West Virginia. The generating capacity of these facilities consists
of approximately 50% of base-load, 15% of intermediate and 35% of peaking
capacity. For a discussion of the factors that may affect the future earnings
generated by these Orion Power assets, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Integration and Other Risks Associated With Our Orion Power
Assets" in Item 7 of this Form 10-K.

Market Framework. We sell the power generated by our Midwest regional
facilities into the ECAR market and the region covered by the Mid-America
Interconnected Network Reliability Council (MAIN market). These markets include
all or portions of the states of Illinois, Wisconsin, Missouri, Indiana, Ohio,
Michigan, Virginia, West Virginia, Tennessee, Maryland and Pennsylvania. These
markets are currently in a state of transition and are in the process of
establishing regional transmission organizations (RTO) that would define the
rules and requirements around which competitive wholesale markets in the region
would develop. The FERC has approved proposals by the Midwest Independent System
Operator (Midwest ISO) to administer a substantial portion of the transmission
facilities in the Midwest region. The FERC also has ordered the Alliance RTO,
which had a separate proposal to be the RTO for parts of the Midwest region, to
explore joining the Midwest ISO. As a result, the final market structure for the
Midwest region remains unsettled. The timing of the development of RTO and the
extent to which the Midwest ISO and the Alliance RTO would combine is currently
unknown. In addition, some states within these markets have restructured their
electric power markets to competitive markets from traditional utility monopoly
markets, while others have not. Currently the transmission infrastructure in
these markets is generally owned by non-independent market participants, some of
which are our competitors, which has the potential to create market anomalies.
Transmission constraints exist in these markets and have been managed by the
owners of the transmission infrastructure, subject to transmission tariffs and
protocols regulated by the FERC.

We currently sell power from our facilities in the Midwest region to
customers under bilateral contracts that are generally non-standard with highly
negotiated terms and conditions. Our customers include municipalities, electric
cooperatives, integrated utilities, transmission and distribution utilities and
power marketers. Direct customer sales, in addition to other physical and
financial transactions enable us to hedge a portion of our generation portfolio.
For a more complete description of our hedging strategy and a summary of the
consolidated hedge position of our United States generating assets, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Risks Associated with Our
Hedging and Risk Management Activities" in Item 7 of this Form 10-K.

FLORIDA AND OTHER SOUTHEASTERN MARKETS

Facilities. As of December 31, 2001, we owned, or owned interests in,
three power generation facilities with an aggregate net generating capacity of
979 MW located in the states of Florida and Texas. These facilities include one
gas and oil-fired generation facility with an aggregate net generating capacity
of 619 MW located near Titusville, Florida. This facility can be operated as
either an intermediate or a peaking facility. We also own a 464 MW gas and
oil-fired peaking generation facility in Osceola County, Florida. Two of the
three generating units of this plant with an aggregate net generating capacity
of 310 MW commenced commercial operation in December 2001. We expect the
remaining generating unit at this facility will begin commercial operation in
the second quarter of 2002. In addition, we own a 50% interest in a 100 MW
gas-fired base-load/cogeneration facility located in Orange, Texas. Air Liquide
owns the other 50% interest in this plant which has been in commercial operation
since December 1999.

We have begun construction on an 804 MW gas-fired intermediate/peaking
facility in Choctaw County, Mississippi. We expect this facility will begin
commercial operation in the second quarter of 2003. This facility

25

is being constructed under the terms of a construction agency agreement under a
synthetic leasing arrangement. Upon completion of the construction of this
facility, we will have the right to lease, purchase or remarket the facility.
For additional information regarding the construction agency agreement, please
read "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Future Sources and Uses of
Cash -- Reliant Resources-unregulated businesses -- Consolidated Sources of
Cash -- Off-Balance Sheet Transactions -- Construction Agency Agreements" in
Item 7 of this Form 10-K, and Note 14(l) to our consolidated financial
statements.

Market Framework. We currently conduct the majority of our Southeast
regional operations in the state of Florida. The state of Florida, other than a
portion of the western panhandle, constitutes a single reliability council and
contains approximately 5% of the United States population. The
transmission-owning utilities in Florida have proposed establishing an
independent system operator to assume control of the transmission system and
undertake to define the rules and requirements for a competitive wholesale
market. The timing of the development of an independent system operator for the
Florida market is currently unknown. Under its present structure, the Florida
market is dominated by incumbent utilities. There are a number of statutory and
regulatory restrictions that negatively impact the development of additional
power generation facilities in the region.

We currently sell power from our facilities in the Florida market under
bilateral contracts that are non-standard and highly negotiated for terms and
conditions. Until the rules for system operations are established, we expect
limited trading opportunities will exist in the Florida market. The customers
who participate in power transactions in this region include municipalities,
electric cooperatives and integrated utilities. We sell capacity and energy to
customers in the Florida market, however a market for ancillary services has not
developed. Forward hedging of a portion of our Florida portfolio is generally
accomplished through customer-tailored, multi-year sale agreements as no liquid,
over-the-counter or auction markets currently exist in Florida. For a more
complete description of our hedging strategy and a summary of the consolidated
hedge position of our United States generation assets, please read "Management's
Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Risks Associated with Our
Hedging and Risk Management Activities" in Item 7 of this Form 10-K.

With respect to our facilities in East Texas and Mississippi, several of
the transmission-owning utilities in the Southeast region have formed the
SETrans Grid Company (SETrans RTO) that they are proposing to serve as the
region's RTO. The proposed SETrans RTO would manage, but not own, the
transmission grid in the region and operate forward and spot markets for energy.
The SETrans RTO has filed a status report with the FERC, but has not filed
tariffs or protocols and has not been approved as the region's RTO.

WEST REGION

Facilities. As of December 31, 2001, we owned, or owned interests in,
seven electric power generation facilities with an aggregate net generating
capacity of 4,635 MW located in the states of California, Nevada and Arizona.
These facilities include approximately 20% of base-load, 75% of intermediate and
5% of peaking capacity. Our facilities in the West region include five
facilities with an aggregate net generating capacity of 3,800 MW located in
California. We also own a 50% interest in a 490 MW gas-fired, base-load, peaking
facility located near Las Vegas, Nevada. Sempra Energy owns the other 50%
interest in this plant. In addition, we own a 590 MW gas-fired, base-load,
peaking generation facility in Casa Grande, Arizona. This facility was placed in
commercial operation in the fourth quarter of 2001. We also have a 548 MW
gas-fired, base-load, peaking generation facility under construction in Nevada.
We expect this facility will begin commercial operation in the fourth quarter of
2003.

Market Framework. Our West regional market includes the states of Arizona,
California, Oregon, Nevada, New Mexico, Utah and Washington. Generally we sell
the power generated by our California and Nevada facilities to customers located
in the Los Angeles basin of southern California. We also sell power generated by
our Nevada facility to customers located in southern Nevada. Our customers in
these states include power marketers, investor-owned utilities, electric
cooperatives, municipal utilities and the California

26

Independent System Operator (Cal ISO) acting on behalf of load-serving entities.
We sell power and ancillary services to these customers through a combination of
bilateral contracts and sales made in the Cal ISO's day-ahead and hour-ahead
ancillary services markets and its real-time energy market. The Cal ISO does not
currently maintain a market for capacity; however, a capacity market has
recently been proposed by the Cal ISO under its market mitigation plan for the
California market.

We have agreed to sell up to 100% of the power generated by our Arizona
facility to the Salt River Project Agricultural Improvement and Power District
of the State of Arizona under a long-term power purchase agreement. Bilateral
contracts, in addition to other physical and financial transactions, enable us
to hedge a portion of our generation portfolio. For a more complete description
of our hedging strategy and a summary of the consolidated hedge position of our
United States generating assets, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Risks Associated with Our Hedging and Risk Management
Activities" in Item 7 of this Form 10-K. In addition, although we do not own
generation facilities in the states of Oregon, New Mexico, Utah and Washington,
our trading and marketing operations purchase and deliver energy commodities in
these states.

Our operations in the California market are subject to numerous
environmental and other regulatory restrictions. Permits issued by local air
districts restrict the output of some of our generating facilities. In addition,
certain air districts require us to purchase emission credits to offset NOx
emissions from our facilities.

In response to California's electricity market restructuring initiative,
the FERC issued a series of orders in 1996 and 1997 approving a wholesale market
structure administered by two independent non-profit corporations: the Cal ISO,
responsible for operational control of the transmission system and the purchase
or sale of electricity in "real-time" to balance actual supply and demand, and
the California Power Exchange (Cal PX), responsible for conducting auctions for
the purchase or sale of electricity on a day-ahead or day-of basis. As part of
this market restructuring, California's distribution utilities sold essentially
all of their gas-fired plants to third-party generators. The utilities were
required to sell their remaining generation into the Cal PX markets and purchase
all of their power requirements from the Cal PX markets at market-based rates
approved by the FERC. California's regulatory system initially prohibited the
utilities from entering into forward contracts to cover the bulk of their
customers' requirements. Retail electricity rates were initially frozen at
levels in effect on June 10, 1996, with a 10% rate reduction for residential and
smaller commercial customers. When wholesale power costs began to rise
dramatically in 2000, driven by a combination of factors, including higher
natural gas prices and emission allowance costs, reduction in available
hydroelectric generation resources, increased demand and decreases in net
imports, some of the California utilities were unable to recover their purchased
power costs through the retail rates they were allowed to charge. As a result,
the utilities accumulated huge debts to wholesale power suppliers, including us.
The Cal ISO currently is conducting a major market redesign process that, if
approved by the FERC, could change the structure of the markets operated by the
Cal ISO, including changes to market monitoring and mitigation, congestion
management and capacity obligations. For a discussion of litigation and other
legal proceedings related to energy sales in California, the impact of current
regulations on our West region and related uncertainty associated with the
California wholesale market, please read "-- Regulation -- Federal Energy
Regulatory Commission" in Item 1 of this Form 10-K, "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Affecting the Results of Our Wholesale
Energy Operations -- Uncertainty in the California Market" in Item 7 of this
Form 10-K and Notes 14(f) and 14(g) to our consolidated financial statements.

In Nevada and Arizona, there is presently no RTO in place to manage the
transmission systems or to operate energy markets, although one RTO working
group is evaluating the establishment of an organization that would assume
control, subject to FERC approval, over the transmission systems of the
utilities operating in this region. The FERC has recently expressed its
intention to pursue the establishment of an RTO in the West region.

27

Additionally, in Nevada and Arizona, state-level regulatory initiatives may
impact competition in the electric sector. In Nevada, the state legislature has
passed legislation prohibiting the state's investor-owned utilities from
divesting generation. Similarly, in Arizona, proceedings are pending before the
Arizona Corporation Commission that would allow the Arizona Public Service
Company to avoid a requirement to seek competitive bids for 50% of the Arizona
Public Service Company's generation needs.

ERCOT REGION

Facilities. Through Reliant Resources, we currently own a partially
operational 781 MW gas-fired, combined cycle, cogeneration facility in
Channelview, Texas. 170 MW of this facility's capacity is currently operational
and 611 MW are under construction. We expect the remaining generating units for
this facility will begin commercial operations in the third quarter of 2002.
This facility is not part of our Electric Operations business segment. For more
information on that segment and the facilities that are part of our Texas
generation business, please read "Electric Operations" in Item 1 of this Form
10-K.

Market Framework. For information regarding the market framework of the
ERCOT region, please read "Electric Operations -- ERCOT Market Framework" in
Item 1 of this Form 10-K.

LONG-TERM PURCHASE AND SALE AGREEMENTS

In the ordinary course of business, and as part of our hedging strategy, we
enter into long-term sales arrangements for power, as well as long-term purchase
arrangements. For information regarding our long-term fuel supply contracts,
purchase power and electric capacity contracts and commitments, electric energy
and electric sale contracts and tolling arrangements, please read Notes 5, 14(a)
and 14(b) to our consolidated financial statements. For information regarding
our hedging strategy relating to such long-term commitments, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Wholesale Energy Operations -- Risks Associated with Our
Hedging and Risk Management Activities" in Item 7 of this Form 10-K.

DEVELOPMENT ACTIVITIES

As of December 31, 2001, we had 3,587 MW (3,391 MW, net of 196 MW to be
retired upon completion of one facility) of additional net generating capacity
under construction, including 2,120 MW of facilities owned by off-balance sheet
special purpose entities, that are being constructed under construction agency
agreements pursuant to synthetic leasing arrangements. Upon the completion of
the construction of these facilities, we expect that we will lease these
facilities from their owners. For additional information regarding the
construction agency agreements, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Reliant
Resources-unregulated businesses -- Consolidated Sources of Cash -- Off-Balance
Sheet Transactions -- Construction Agency Agreements" in Item 7 of this Form
10-K and Note 14(l) to our consolidated financial statements.

In addition, Orion Power had three projects totaling 1,054 MW under
construction as of December 31, 2001. However, at this time, we have decided to
postpone a 250 MW project in Florida because of capital market and economic
considerations. With improved capital market conditions and required approvals
from Florida authorities on a newly configured 500 MW design, we would plan to
proceed with construction in the future. Also, Orion Power had two projects
under advanced development as of December 31, 2001, which have been deferred. A
1,088 MW project in Maryland has been postponed due to capital market
considerations and because we believe that the PJM market will be sufficiently
supplied for the next few years. A repowering project in New York City with a
total capacity of 1,608 MW has been postponed until we see an improvement in the
capital markets.

As a result of several recent events, including the United States economic
recession, the price decline of our industry sector in the equity capital
markets and the downgrading of the credit ratings of several of our significant
competitors, the availability and cost of capital for our business and the
businesses of our
28

competitors has been adversely affected. In response to these events and the
intensified scrutiny of companies in our industry sector by the rating agencies,
we have reduced our planned capital expenditures by $2.7 billion over the
2002 -- 2006 time frame.

DOMESTIC TRADING, MARKETING, POWER ORIGINATION AND RISK MANAGEMENT SERVICES
OPERATIONS

In addition to our power generation operations, we trade and market power,
natural gas and other energy-related commodities and provide related risk
management services to our customers. According to Platt's Power Markets Week
and Natural Gas Intelligence Group, we were the third largest power trader and
ninth largest natural gas trader in the United States in 2001. Our domestic
trading, marketing, power origination and risk management operations complement
our domestic power generation operations by providing a full range of energy
management services. These services include management of the sales and
marketing of energy, capacity and ancillary services from these facilities, and
also management of the purchase and sale of fuels and emission allowances needed
to operate these facilities. Generally, we seek to sell a portion of the
capacity of our domestic facilities under fixed-price sale contracts,
fixed-capacity payments or contracts to sell power at a predetermined multiple
of either gas or oil prices. This provides us with certainty as to a portion of
our margins while allowing us to maintain flexibility with respect to the
remainder of our generation output. We evaluate the regional forward power
market versus our own fundamental analysis of projected future prices in the
region to determine the amount of our capacity we would like to sell and the
terms of sale pursuant to longer-term contracts. We also take operational
constraints and operating risk into consideration in making these
determinations. Generally, we seek to hedge a portion of our fuel costs, which
are usually linked to a percentage of our power sales. We also market
energy-related commodities and offer physical and financial wholesale energy
marketing and price risk management products and services to a variety of
customers. These customers include natural gas distribution companies, electric
utilities, municipalities, cooperatives, power generators, marketers or other
retail energy providers, aggregators and large volume industrial customers.

The following table illustrates the growth of our physical power and gas
trading volumes since 1999.

TRADING VOLUMES

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

(1) Million megawatt hours.

(2) Billion cubic feet.

Electric Power Trading and Marketing. We purchase electric power from
other generators and marketers and sell power primarily to electric utilities,
municipalities and cooperatives and other marketing companies. Our trading and
marketing group is also responsible for the marketing of power produced from the
power plants we own. We also provide risk management, physical and financial
fuel purchase and power sales and optimization services to our customers.

Power Origination. Some of our employees focus on developing and providing
customers with long-term customized products (power origination products). These
products are designed and negotiated on a case-by-case basis to meet the
specific energy requirements of our customers. Our power origination teams work
closely with our trading and marketing group and our power generation group to
sell long-term products from our power generation assets. They also work to
leverage our market knowledge to capture attractive opportunities available
through selling products that combine or repackage energy products purchased
from third parties with other third-party products or with products from our
power generation assets. Our efforts to sell power origination products from our
power generation assets have been focused on longer-term forward sales to
municipalities, cooperatives and other companies that serve end users, as well
as sales of near-term products that are not widely traded. Our power origination
products that combine or repackage third-party
29

products are generally highly structured and therefore require the application
of our commercial capabilities (e.g., power trading and asset positions).

Natural Gas Trading and Marketing. We purchase natural gas from a variety
of suppliers under daily, monthly and term, variable-load and base-load
contracts that include either market sensitive or fixed pricing provisions. We
sell natural gas under sales agreements that have varying terms and conditions,
most of which are intended to match seasonal and other changes in demand. We
sold an average of 10.1 Bcf per day of natural gas in 2001, an average of 6.6
Bcf per day in 2000 and an average of 4.8 Bcf per day in 1999, some of which was
sold to the natural gas distribution company subsidiaries of Reliant Energy. We
plan to continue to purchase natural gas to supply to our power plants.

Our natural gas marketing activities include contracting to buy natural gas
from suppliers at various points of receipt, aggregating natural gas supplies
and arranging for their transportation, negotiating the sale of natural gas and
matching natural gas receipts and deliveries based on volumes required by
customers.

We arrange for, schedule and balance the transportation of the natural gas
we market from the supply receipt point to the purchaser's delivery point. We
generally obtain pipeline transportation to serve our customers. Accordingly, we
use a variety of transportation arrangements for our customers, including short-
term and long-term firm and interruptible agreements with intrastate and
interstate pipelines. We also utilize brokered firm transportation agreements
when dealing on the interstate pipeline system. As of December 31, 2001, we held
over two bcf per day of firm transportation in the United States. In the normal
course of business it is common for us to hedge the risk of pipeline
transportation expenses through "basis swaps." To the extent we have
contractually secured pipeline transportation rights in order to fulfill our
obligations to sell gas at specific delivery points, or to acquire gas for our
own requirements at generation facilities as part of our hedging strategy for
power sales, and a pipeline experiences a force majeure event, our ability to
transport gas on a contracted capacity basis could become impaired, which could
affect the integrity of our hedged position.

We also enter into various short-term and long-term firm and interruptible
agreements for natural gas storage in order to offer peak delivery services to
satisfy winter heating and summer electric generating demands. Natural gas
storage capacity allows us to better manage the unpredictable daily or seasonal
imbalances between supply volumes and demand levels. In addition to entering
into contracts of natural gas storage capacity in strategic locations throughout
the country, we are actively pursuing a natural gas storage development plan.
These services are also intended to provide an additional level of performance
security and backup services to our customers.

Other Commodities and Derivatives. We trade and market other
energy-related commodities. We use derivative instruments to manage and hedge
our fixed-price purchase and sale commitments and to provide fixed-price or
floating-price commitments as a service to our customers and suppliers. We also
use derivative instruments to reduce our exposure relative to the volatility of
the cash and forward market prices and to protect our investment in storage
inventories. For additional information regarding our financial exposure to
derivative instruments, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations -- Risks Associated with Our Hedging and Risk Management Activities"
in Item 7 of this Form 10-K and "Quantitative and Qualitative Disclosures About
Market Risk" in Item 7A of this Form 10-K.

Intercontinental-Exchange. In July 2000, we, along with five other natural
gas and power companies, American Electric Power, Aquila Energy, Duke Energy, El
Paso Corporation and Mirant Corporation, made an investment in
Intercontinental-Exchange, a new, web-based, on-line trading platform
(www.intcx.com) for trading various commodities including precious metals, crude
oil and refined products, natural gas and electricity. The other five natural
gas and power companies, along with us, own less than 50% of
Intercontinental -- Exchange. In June 2001, Intercontinental-Exchange acquired
the International Petroleum Exchange. With this acquisition,
Intercontinental-Exchange became the first company to offer both an exchange
trading over-the-counter commodity contracts and an exchange trading commodity
futures contracts. At the same time, Intercontinental-Exchange announced plans
to integrate the two types of exchanges into a single electronic trading
platform. Our decision to invest, as one of a group of natural gas and power
30

companies, in Intercontinental-Exchange was based on a desire to support the
development of a neutral, anonymous, electronic trading platform for bilateral
energy transactions. We believe the commercial success of such an exchange model
will benefit us by contributing to improved price transparency and transaction
liquidity in the wholesale energy markets. The principal online competitors of
Intercontinental-Exchange are currently TradeSpark.com and the NYMEX, a
traditional futures exchange that has announced an online initiative.

Risk Management Controls. For information regarding our risk management
structure and accounting policies, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Trading and
Marketing Operations" in Item 7 of this Form 10-K and "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K.

COMPETITION

For a discussion of competitive factors affecting our Wholesale Energy
business segment, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Wholesale Energy Operations --
Increasing Competition in Our Industry" in Item 7 of this Form 10-K, which
section is incorporated herein by reference.

EUROPEAN ENERGY

Our European Energy business segment, which is conducted through Reliant
Resources, includes 3,476 MW of power generation assets located in the
Netherlands and a related trading and power origination operation. This business
segment includes the operations of Reliant Energy Power Generation Benelux N.V.
(formerly UNA N.V.) (REPGB) and Reliant Energy Trading & Marketing B.V. and its
affiliates.

In 2001, we evaluated strategic alternatives for our European Energy
business segment, including a possible sale. We completed our evaluation and
have determined that given current market conditions and prices, it is not
advisable to sell our European Energy operations. Consequently, we decided to
continue to own and operate our European Energy business segment and expand our
trading and origination activities in Northwest Europe. Our European Energy
business segment will remain with Reliant Resources in the Separation and will
not be part of our business after the Distribution.

EUROPEAN POWER GENERATION OPERATIONS

Facilities. As of December 31, 2001 we owned five electric power
generation facilities in the Netherlands with an aggregate net generating
capacity of 3,476 MW and include approximately 39% of base-load, 36% of
intermediate and 25% of peaking capacity. Our facilities are grouped in three
clusters adjacent to the cities of Amsterdam, Utrecht and Velsen. In 2001, our
generation facilities produced 14 million MWh, an amount which represented
approximately 13% of the electricity production of the Netherlands (excluding
electricity generated by cogeneration or other industrial processes). In
addition to electricity, our generating stations sell heated water produced as a
byproduct of the generation process for use in providing heating (district
heating) to the cities of Amsterdam, Nieuwegein, Utrecht and Purmerend.

In 2001, approximately 51% of our European Energy business segment's
generation output was natural gas-fired, 30% was coal-fired, 18% was blast
furnace gas-fired and less than 1% was oil-fired. Our European Energy business
segment purchases substantially all of its gas fuel requirements under medium to
long-term gas purchase contracts with N.V. Nederlandse Gasunie, the primary
supplier and transporter of natural gas in the Netherlands. The purchase price
and transportation costs for natural gas under these contracts are calculated on
the basis of regulated tariffs.

Our European Energy business segment historically purchased all of its coal
requirements under short-term contracts with a coal trading and supply company
now owned by two of the Dutch generation companies. In December 2001, REPGB and
the other shareholder of the coal trading and supply company agreed to terminate
future coal purchases through this entity effective in mid-2002. Our European
Energy business
31

segment intends to obtain its future coal requirements through short to
medium-term forward purchase contracts on the open market through a variety of
suppliers and brokers.

One of our European Energy generation stations, which has a production
capacity of 144 MW, uses blast furnace gas, an industrial waste gas generated by
a steel plant adjacent to the generation station, as its fuel. Two of our other
European Energy business segment's generation plants have the flexibility to
operate using blast furnace gas. We purchase the blast furnace gas from the
adjacent steel plant under a medium-term and a long-term contract. We purchase
our fuel oil requirements on the open market.

We acquired REPGB in October 1999 for approximately $1.9 billion (based on
the then applicable exchange rate of 2.06 Dutch Guilders (NLG) per U.S. dollar).
For information regarding the acquisition, please read Note 3(b) to our
consolidated financial statements.

Market Framework. Our European Energy business segment produces, buys and
sells electricity, gas and other energy-related commodities in the Northern
European wholesale market. Its generation production activities are centered in
the Netherlands, where it is one of the four large-scale generation companies.
It operates five generation facilities with an installed capacity of 3,476 MW.
Its energy trading and origination operations concentrate their activities
primarily in the Netherlands, Germany and the Scandinavian regions. In the
fourth quarter of 2001, our European Energy business segment expanded its
electricity trading operations to the United Kingdom.

The primary customers of our European Energy business segment are electric
distribution companies, large industrial consumers and energy trading companies.
We sell electricity and other energy-related commodities primarily in the form
of forward purchase contracts transacted in the over the counter markets, on
various European energy exchanges and in individually negotiated transactions
with individual counterparties. To a lesser extent, we also engage in
transactions involving financial energy-related derivative products.

The most significant factor affecting the markets in which our European
Energy business segment operates has been the recent deregulation of the Dutch
and certain other European wholesale energy markets, including access on a
non-discriminatory basis to high voltage transmission grid systems, the
establishment of new energy exchanges and other events. Notwithstanding these
factors, the scope and pace of the future liberalization of the European energy
markets is uncertain. For example, access to some European markets continues to
be subject to transmission and other constraints. In some cases, fuel suppliers
continue to operate in largely regulated markets not yet open to full
competition.

EUROPEAN TRADING AND POWER ORIGINATION OPERATIONS

Our European Energy business segment's trading and power origination
operations are centered in Amsterdam, Netherlands, with additional offices in
London and Frankfurt. Our European Energy business segment trades electricity
and fuel products in the Netherlands, Germany, Austria, Switzerland, the United
Kingdom and the Scandinavian countries. Our marketing operations focus on
distribution companies and large industrial and commercial customers in the
Benelux and German markets. As of December 31, 2001, our European Energy
business segment had entered into forward purchase and sale contracts, and
associated hedging transactions, covering approximately 18.6 million MWh for
delivery in 2002.

Our European Energy business segment's trading and power origination
operations seek to utilize a business model, including risk management and
related control policies, similar to that utilized in our Wholesale Energy
operations in the United States. There are, however, significant differences in
the United States and European markets. Among other things, European energy
markets involve increased currency hedging requirements (the Euro and non-Euro
currencies), and more complicated cross-border tax and transmission tariff
systems than in the United States. In addition, European energy markets are
significantly less mature than United States energy markets in terms of
liquidity, the scope and complexity of trading and marketing products, the use
of standardized market-based trading contracts and other aspects.

In addition, there exist greater uncertainties in some European
jurisdictions as to the enforceability of certain contract-based mechanisms to
hedge risks, such as the enforceability of automatic termination rights and
rights of set -- off upon bankruptcy, limitations on liquidated damages and the
rules by which European
32

courts construct contracts. In many civil law jurisdictions, courts reserve the
right to interpret contracts based upon principles of good faith and fairness as
opposed to a literal construction of the contract.

As of December 31, 2001, we had provided an aggregate of $831 million in
guarantees with respect to contract obligations of our European Energy business
segment.

COMPETITION

For a discussion of competitive factors affecting our European Energy
business segment, please read "Management's Discussion and Analysis of Financial
Condition and Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our European Energy
Operations -- Competition in the European Market" in Item 7 of this Form 10-K,
which section is incorporated herein by reference.

RETAIL ENERGY

Our Retail Energy business segment provides electricity and related
services to retail customers primarily in Texas through Reliant Energy Retail
Services, LLC (Residential Services), Reliant Energy Solutions, LLC (Solutions)
and StarEn Power, LLC (StarEn Power), all of which are wholly owned subsidiaries
of Reliant Resources. Our Retail Energy business segment will remain with
Reliant Resources in the Separation and will not be part of our business after
the Distribution. As a retail electric provider, generally our Retail Energy
business segment procures or buys electricity from wholesale generators at
unregulated rates, sells electricity at generally unregulated rates to its
retail customers and pays the local transmission and distribution regulated
utilities a regulated tariff rate for delivering the electricity to its
customers. Our Retail Energy business segment became a provider of retail
electricity in Texas when that market began opening to retail competition in
late 2001 and fully opened to retail competition in January 2002. In January
2002, our Retail Energy business segment began to provide retail electricity
services to all of the approximately 1.7 million customers of Reliant Energy
HL&P's electric utility located in its service area who did not take action to
select another retail electric provider. Our Retail Energy business segment
provides electricity and related products and services to residential and small
commercial (i.e., small and medium-sized business customers with a peak demand
for power at or below one MW) customers through Residential Services, and offers
customized, integrated electric commodity and energy management services to
large commercial, industrial and institutional (e.g., hospitals, universities,
school systems and government agencies) customers through Solutions for
customers with a peak demand for power of greater than one MW. Residential
Services, Solutions and StarEn Power have been certified as retail electric
providers by the Texas Utility Commission. StarEn Power has been appointed by
the Texas Utility Commission to be the provider of last resort (POLR) in certain
areas of the State of Texas. Under the Texas Electric Restructuring Law, a POLR
is required to offer a standard retail electric service package to requesting
customers of a class designated by the Texas Utility Commission within the
POLR's territory at a fixed, nondiscountable rate.

In preparation for retail electric competition in Texas, Reliant Resources
expanded its infrastructure of information technology systems, business
processes and staffing levels to meet the needs of its retail businesses. These
include a customer care system module and wholesale/retail energy supply, risk
management, e-commerce, scheduling/settlement, customer relationship management
and sales force automation systems. As of December 31, 2001, Reliant Resources
had invested $153 million in retail infrastructure development. For additional
information regarding the Texas retail electric market, please read "-- Market
Framework," "-- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" in Item 1 of this Form 10-K
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Retail Energy Operations -- Competition in the Texas Market"
in Item 7 of this Form 10-K.

RESIDENTIAL SERVICES

Residential Services provides electricity to residential retail and small
commercial customers in Texas. As of January 1, 2002, Residential Services was
the retail electric provider for approximately 1.5 million

33

residential customers located in the Houston metropolitan area, making us the
second largest retail electric provider in Texas as of that date. Residential
Services' marketing strategy for residential customers emphasizes reliability
and trust with our customers, and focuses on savings, value and customer
service. Reliant Resources launched an advertising campaign to reposition its
brand in the Houston and Dallas/ Fort Worth metropolitan areas in the second
half of 2001.

As the affiliated retail electric provider, or successor in interest, to
Reliant Energy HL&P, Residential Services was also the retail electric provider
for approximately 200,000 small commercial customers in the Houston metropolitan
area as of January 1, 2002. Residential Services' marketing strategy for small
commercial customers uses a combination of direct marketing and individual sales
calls to establish its brand and to attract additional customers.

As the affiliated retail electric provider, Residential Services will not
be permitted to sell electricity to residential and small commercial customers
in Reliant Energy HL&P's service territory at a price other than the price to
beat until January 1, 2005, unless before that date the Texas Utility Commission
determines that 40% or more of the amount of electric power that was consumed in
2000 by the relevant class of customers in the service territory is committed to
be served by other retail electric providers. In addition, the Texas Electric
Restructuring Law requires Reliant Resources, as the affiliated retail electric
provider, to make the price to beat available to residential and small
commercial customers in Reliant Energy HL&P's service territory through January
1, 2007, if requested by such customers. For more information about the price to
beat, please read "-- Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Texas Electric Restructuring
Law" in Item 1 of this Form 10-K.

SOLUTIONS

Solutions provides electricity and energy services to the large commercial,
industrial and institutional customers with whom it has signed contracts. In
addition, it provides electricity at previously established default rates to
those large commercial, industrial and institutional customers in the service
territory of Reliant Energy HL&P who have not entered into a contract with
another retail electric provider. The majority of Solutions' revenues will come
from the sale of electricity to its customers. In order to be classified as a
large commercial customer, an electricity customer may aggregate the purchase of
electricity for its own use at multiple locations such that the total peak
demand exceeds one MW.

In addition to providing electricity, Solutions provides customized,
integrated energy solutions, including risk management and energy services
products, and demand side and energy information services to large commercial,
industrial and institutional customers. Since its formation in April 1996,
Solutions has completed over 220 energy services projects for large commercial,
industrial and institutional clients. The services that Solutions provides its
customers include the replacement or upgrade of energy-intensive capital
equipment, the financing of energy-intensive equipment, infrastructure
optimization, substation development and maintenance and power quality
assurance.

Solutions is recognized as the affiliated retail electric provider, or
successor in interest, to Reliant Energy HL&P for large commercial, industrial
and institutional customers. Solutions targets institutional, manufacturing,
industrial and other large commercial customers, including multi-site retailers
and restaurants, petroleum refineries, chemical companies, real estate
management firms, educational institutions and healthcare providers. As of
December 31, 2001, this customer segment in Texas included approximately 1,750
buying organizations consuming an aggregate of approximately 16,000 MW of
electricity at peak demand. As of December 31, 2001, Solutions had signed
contracts with customers representing a peak demand of approximately 3,700 MW
and serving approximately 12,000 meter locations.

STAREN POWER

StarEn Power serves as the POLR in portions of the state of Texas, as
designated by the Texas Utility Commission. For 2002, StarEn Power has been
appointed to serve as the POLR for residential and small commercial customers in
the western portion of the Dallas/Fort Worth metropolitan area formally served
by TXU Electric Company. In addition, StarEn Power has been appointed as the
POLR in the service territory
34

of Reliant Energy HL&P for large commercial, industrial and institutional
customers. The rates and terms under which StarEn Power provides service are
governed by the terms of a settlement agreement between StarEn Power and various
interested parties approved by the Texas Utility Commission. For additional
information regarding StarEn Power's POLR obligations, rates and terms of
service, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Retail Energy Operations --
Obligations as a Provider of Last Resort" in Item 7 of this Form 10-K.

MARKET FRAMEWORK

Generally, under the Texas Electric Restructuring Law, the retail electric
provider procures or buys electricity from wholesale generators, sells
electricity at retail to its customers and pays the transmission and
distribution utility a regulated tariffed rate for delivering electricity to its
customers. All retail electric providers in an area pay the same rates and other
charges for transmission and distribution, whether or not they are affiliated
with the transmission and distribution utility for that area. The transmission
and distribution rates in effect as of January 1, 2002 for each utility were set
through rate cases before the Texas Utility Commission. For more information
regarding the retail market framework in Texas, please read
"-- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" in Item 1 of this Form 10-K
and "Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Retail Energy Operations" in Item 7 of this Form 10-K.

RETAIL ENERGY SUPPLY

In Texas, our Wholesale Energy group and our Retail Energy group work
together in order to determine the price, demand and supply of energy required
to meet the needs of our Retail Energy business segment's customers. Our
Wholesale Energy trading and marketing operations are responsible for commodity
pricing, risk assessment and supply procurement for our Retail Energy business
segment. Our Retail Energy business segment manages retail pricing decisions and
forecasts the demand for the procurement of electricity by the Wholesale Energy
business segment. The costs of our trading, marketing and risk management
services associated with obtaining the electricity supply for our retail
customers in Texas are borne by our Retail Energy business segment. Our
Wholesale Energy group acquires supply for our Retail Energy business segment by
several means. Wholesale Energy may purchase capacity from non-affiliated
parties in the state mandated auctions. Please read "Electric
Operations -- Generation -- State Mandated Capacity Auctions" and
"-- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" in Item 1 of this Form 10-K
for more information about these auctions. Under the terms of the master
separation agreement between Reliant Resources and Reliant Energy, Reliant
Resources is entitled to purchase, prior to our submission of capacity to
auction, 50% (but not less than 50%) of the capacity we have available to
auction in the contractually mandated auctions at the prices bid by third
parties in these auctions. Please read "Electric
Operations -- Generation -- Contractually Mandated Capacity Auctions" in Item 1
of this Form 10-K for more information about these auctions. Whether or not
Reliant Resources exercises the foregoing right, it may submit bids to purchase
in the contractually mandated auctions, but cannot participate in state mandated
auctions conducted by our Texas generation business. Wholesale Energy entered
into bilateral contracts with third parties for capacity, energy and ancillary
services. Wholesale Energy continuously monitors and updates these positions
based on retail sales forecasts and market conditions.

COMPETITION

For a discussion of competitive factors affecting our Retail Energy
business segment, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Retail Energy Operations --
Competition in the Texas Market" in Item 7 of this Form 10-K, which section is
incorporated herein by reference.

35

LATIN AMERICA

Effective December 1, 2000 (Measurement Date), our board of directors
approved a plan to dispose of our Latin America business segment through sales
of its assets. At the time, our major Latin America investments consisted of
interests in cogeneration projects, utilities and other power projects in
Argentina, Brazil and Colombia. We began disposing of our Latin America assets
and reporting the results of our Latin America business segment as "discontinued
operations" in our 2000 consolidated financial statements in accordance with
Accounting Principles Board (APB) Opinion No. 30 "Reporting the Results of
Operations -- Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions," (APB
Opinion No. 30).

By December 2001, we had disposed of all of our Latin America assets except
for our Argentine investments, which consisted of a 100% interest in a
corporation formed to develop, own and operate a 160 MW cogeneration project
(Argener) located at a steel plant near San Nicolas, Argentina and a 90%
interest in a utility in north-central Argentina (EDESE). We were in
negotiations to dispose of Argener and EDESE, but the negotiations terminated in
December 2001 in light of recent adverse economic developments in Argentina.
Under applicable accounting rules, because we were not able to dispose of
Argener and EDESE within one year of the Measurement Date, our remaining
investments in our Latin America business segment are no longer classified as
discontinued operations, and the related amounts have been reclassified into
continuing operations in our consolidated financial statements. We will continue
to evaluate options related to the future disposition of these assets. For more
information regarding the accounting treatment of our Latin America business
segment, please read Note 19 to our consolidated financial statements.

OTHER OPERATIONS

In 2001, our Other Operations business segment included:

- the operations of Reliant Energy Thermal Systems, Inc. (Thermal Systems);

- the operations of Reliant Energy Power Systems, Inc. (Power Systems);

- the operations of our communications business (Communications);

- the operations of our venture capital division (New Ventures);

- various office buildings and other real estate used in our business
operations;

- unallocated corporate costs; and

- intersegment eliminations.

Except for Thermal Systems and Power Systems, we conducted the operations
of our Other Operations business segment through Reliant Resources and one or
more of its subsidiaries. After the Separation, our Other Operations business
segment will consist primarily of Thermal Systems, Power Systems, office
buildings and other real estate used in our business operations and unallocated
corporate costs.

RELIANT ENERGY THERMAL SYSTEMS

Thermal Systems provides energy management services to commercial and
industrial consumers. These services include operations and maintenance
services, energy management services, distributed generation services,
Internet-based facilities/energy management services, temporary cooling and
electrical services, project and construction management services and
engineering consulting services. Thermal Systems also owns an interest in the
Northwind Houston L.P. (Northwind) district energy system in partnership with a
third party. Northwind provides chilled water services to selected buildings in
Houston's downtown central business district. Northwind's customers include
Astros Field, and various office buildings, hotels and high-rise residential
developments. Thermal Systems and the third party have an agreement in principle
concerning Thermal System's purchase of the third party's interest in Northwind.

36

RELIANT ENERGY POWER SYSTEMS

Power Systems is developing a natural-gas-fueled proton exchange membrane
fuel cell system targeted at the domestic residential market. Power Systems
licenses core technology from Texas A&M University and has developed additional
fuel cell technology focused on pursuing its goal of developing and building a
low-cost, low-pressure fuel cell using commercially available materials and
volume manufacturing design techniques.

NEW VENTURES

Our New Ventures division manages our existing new technology investments
and identifies and invests in promising new technologies and businesses that
relate to our energy services operations. Focus areas for investment include
distributed generation, clean energy and energy industry software and systems.

Generally, we make our investments either directly or indirectly as limited
partners in venture capital funds. As of December 31, 2001, we have invested
approximately $35 million in five venture capital funds with an energy and
utility focus and have made commitments to invest an additional $11 million in
these funds. As of December 31, 2001, these funds held investments in 43
companies. Excluding our investment in Grande Communications, Inc. discussed
below, New Ventures' direct investment portfolio consists of eight companies
with a total of $7 million invested as of December 31, 2001.

In September 2000, we committed to make a $25 million investment in Grande
Communications, Inc., which was completed in August 2001. Grande Communications
is a Texas-based communications company building a deep fiber broadband network
that will offer bundled services, including high-speed Internet, all-distance
telephone and advanced cable entertainment to homes and businesses. We invested
a further $1 million in Grande Communications in October 2001 as part of a
larger debt and equity financing for the company. Grande Communications has
announced its intention to build a broadband network in the Houston area and has
secured a cable franchise from the City of Houston. The Houston build out will
be in addition to the Central Texas cities of Austin, San Marcos, and San
Antonio which are already under development.

COMMUNICATIONS

During the third quarter of 2001, we decided to exit our Communications
business. The business served as a facility-based competitive local exchange
carrier and Internet services provider and owned network operations centers and
managed data centers in Houston and Austin. Our exit plan was substantially
completed in the first quarter of 2002. For more information regarding the
exiting of our Communications business, please read Note 20 to our consolidated
financial statements.

OUR BUSINESS GOING FORWARD

Our business and operations are changing significantly as a result of the
Texas Electric Restructuring Law and the Separation. Below is a summary of the
principal changes to our business and operations that have occurred and that we
anticipate will occur due to the Texas Electric Restructuring Law and the
Separation.

Separation of Reliant Energy HL&P's Operations. Because the Texas Electric
Restructuring Law requires the separation of generation, transmission and
distribution and retail electric sales operations of electric utilities in
Texas, Reliant Energy HL&P no longer operates as a traditional,
vertically-integrated utility. The retail electric sales operations of Reliant
Energy HL&P were transferred to, and have been operated by, subsidiaries of
Reliant Resources. Since January 1, 2002, retail customers of Reliant Energy
HL&P and other investor-owned electric utilities in Texas have been entitled to
purchase their electricity from any of a number of certified retail electric
providers, including Reliant Resources, at generally unregulated rates. Reliant
Energy (of which Reliant Energy HL&P is an unincorporated division) no longer
provides retail electric services to customers, except through Reliant
Resources, and, upon completion of the Distribution, such services will be
provided at rates separately and independently of CenterPoint Energy by Reliant
Resources and its subsidiaries and by other retail electric providers.

37

Since January 1, 2002, we have been selling electric energy from our Texas
generation business to wholesale purchasers, including retail electric
providers, at unregulated rates pursuant to the state mandated auctions and the
contractually mandated auctions. We plan to transfer our Texas generation
business to Texas Genco in connection with the Restructuring. Pursuant to the
Texas Genco Option, Reliant Resources has the option to acquire our interest in
Texas Genco in 2004. As a result of these changes, our Texas generation
operations are no longer conducted as part of an integrated utility and will
comprise a new business segment in 2002, Electric Generation.

Distribution of Reliant Resources' Stock and New Business Segment. We have
transferred substantially all of our unregulated businesses to Reliant Resources
and its subsidiaries. When we complete the Separation, CenterPoint Energy's
business will consist principally of regulated operations. We anticipate that
upon completion of the Separation described above, CenterPoint Energy's business
segments will consist of the following:

- Electric Transmission and Distribution;

- Electric Generation;

- Natural Gas Distribution;

- Pipelines and Gathering; and

- Other Operations.

The Wholesale Energy, European Energy, Retail Energy and unregulated portions of
our Other Operations business segments will be conducted by Reliant Resources as
a separate publicly traded company.

For information regarding the effect of the changes in our business and
operations on our future earnings, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Factors Associated with the Business
Separation, Restructuring and Distribution" in Item 7 of this Form 10-K.

REGULATION

We are subject to regulation by various federal, state, local and foreign
governmental agencies, including the regulations described below.

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

Current Status. Reliant Energy is both a public utility holding company
and an electric utility company as defined in the 1935 Act; however, it is
exempt from regulation as a registered holding company pursuant to Section
3(a)(2) of the 1935 Act. Although RERC Corp. is a gas utility company as defined
under the 1935 Act, it is not a holding company within the meaning of the 1935
Act. Reliant Energy and RERC Corp. are currently subject to regulation under the
1935 Act with respect to certain acquisitions of voting securities of other
domestic public utility companies and utility holding companies.

Section 33(a)(1) of the 1935 Act exempts foreign utility company affiliates
of Reliant Energy and RERC Corp. from regulation as "public utility companies,"
thereby permitting Reliant Energy and RERC Corp. to invest in foreign utility
companies without becoming subject to registration under the 1935 Act as a
registered holding company and without approval by the SEC. The exemption,
however, is subject to the SEC having received certification from each state
commission having jurisdiction over the retail rates of any electric or gas
utility company affiliated with Reliant Energy or RERC Corp. that such
commission has the authority and resources to protect ratepayers subject to its
jurisdiction and that it intends to exercise its authority. The Texas Utility
Commission and the state regulatory commissions exercising jurisdiction over
RERC Corp. (Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas)
have provided a certification to the SEC subject, however, to the right of such
commissions to revise or withdraw their certifications as to any future
acquisitions of a foreign utility company. The Texas Utility Commission and the
state regulatory commissions of Arkansas and Minnesota have imposed limitations
on the amount of investments that can be made by
38

utility companies (including Reliant Energy and RERC Corp.) in foreign utility
companies and, in some cases, foreign electric wholesale generating companies.
These limitations are based upon a utility company's consolidated net worth,
retained earnings, and debt and stockholders' equity. We currently do not plan
to make any incremental investments in foreign utility companies.

Subject to some limited exceptions, Section 33(f)(1) of the 1935 Act
prohibits us, as a public utility company, from issuing any security for the
purpose of financing the acquisition, ownership or operation of a foreign
utility company, or assuming any obligation or liability in respect of any
security of a foreign utility company.

Under the Energy Policy Act of 1992, 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 1935 Act as an exempt
wholesale generator (EWG). All but two of our electric generation facilities
owned by Reliant Resources have received determinations of EWG status from the
FERC. If any of these subsidiaries loses its EWG status, we would have to
restructure our organization or risk being subjected to regulation under the
1935 Act. The two electric generation facilities in which Reliant Resources owns
interests that are not EWGs are "qualifying facilities" under PURPA. As such,
these facilities, and the subsidiaries who own them, also are exempted from
regulation under the 1935 Act.

Impact on the Restructuring. SEC approval is required for CenterPoint
Energy to acquire Reliant Energy and its subsidiary companies. As a result of
the Restructuring, CenterPoint Energy will be a holding company within the
meaning of the 1935 Act and, as such, required to register under the 1935 Act
unless it is able to qualify for exemption. Section 3(a)(1) of the 1935 Act
provides an exemption for a holding company if it and each of its material
public utility subsidiary companies carry on their utility operations
substantially and predominantly in a single state in which they are all
organized. While we believe that CenterPoint Energy will ultimately be in
compliance with the requirements for exemption under Section 3(a)(1), RERC Corp.
initially will be a material subsidiary with significant out-of-state utility
operations. As described in our application to the SEC, we plan to bring
CenterPoint Energy into full compliance with the standards of Section 3(a)(1) by
separating the Entex, Arkla and Minnegasco operations of RERC Corp. into
separate business entities. We are in the process of obtaining the necessary
state approvals for the RERC Corp. separation.

In the interim, CenterPoint Energy must either obtain a temporary exemption
from registration or else register under the 1935 Act until the separation of
RERC Corp. is completed. We have previously submitted a request for a temporary
exemption for CenterPoint Energy but believe that the new holding company could
also register and obtain the necessary authority under the 1935 Act to operate
during this interim period consistent with our business plan.

Following the Distribution, Reliant Resources and its subsidiaries would
not be subject to the provisions of the 1935 Act either as subsidiaries or
affiliates of CenterPoint Energy.

Proposals to Repeal the 1935 Act. In recent years, several bills have been
introduced in Congress that would repeal the 1935 Act. Repeal or significant
modification to the 1935 Act could have a significant impact on us and the
electric utility industry. At this time, however, we are not able to predict the
outcome of any bills to repeal the 1935 Act or the outlook for additional
legislation in 2002.

FEDERAL ENERGY REGULATORY COMMISSION

Natural Gas. The transportation and sale for resale of natural gas in
interstate commerce is subject to regulation by the FERC under the Natural Gas
Act and the Natural Gas Policy Act of 1978, as amended. The FERC has
jurisdiction over, among other things, the construction of pipeline and related
facilities used in the transportation and storage of natural gas in interstate
commerce, including the extension, expansion or abandonment of these facilities.
The rates charged by interstate pipelines for interstate transportation and
storage services are also regulated by the FERC.

39

REGT and MRT periodically file applications with the FERC for changes in
their generally available maximum rates and charges designed to allow them to
recover their costs of providing service to customers (to the extent allowed by
prevailing market conditions), including a reasonable rate of return. These
rates are normally allowed to become effective after a suspension period, and in
some cases are subject to refund under applicable law, until such time as the
FERC issues an order on the allowable level of rates. REGT currently is
operating under such rates approved by the FERC that took effect in February
1995. MRT currently is operating under such rates that took effect in October
2001, pursuant to a rate case settlement approved by the FERC on January 16,
2002.

On February 9, 2000, the FERC issued Order No. 637, which introduces
several measures to increase competition for interstate pipeline transportation
services. Order No. 637 authorizes interstate pipelines to propose
term-differentiated and peak/off-peak rates, and requires pipelines, including
MRT and REGT, to make tariff filings to expand pipeline service options for
customers. REGT and MRT made Order No. 637 compliance filings in 2000. On March
29, 2002, the FERC issued an order accepting, subject to certain modifications,
a settlement agreement that would resolve REGT's Order No. 637 proceeding. On
November 21, 2001, MRT filed with the FERC for approval of a settlement intended
to resolve the MRT Order No. 637 compliance proceeding. The settlement was
uncontested. No action on the settlement has yet been taken by the FERC.

On May 31, 2001, the FERC issued an order on rehearing establishing hearing
procedures to evaluate MRT's request for authority to recover four Bcf of
undercollected lost and unaccounted for gas over a three-year period. A
settlement resolving all issues in this case, among other things, was filed with
the FERC on November 5, 2001. The FERC approved the settlement on January 16,
2002.

Electricity. Under the Federal Power Act, 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
applicable to their wholesale sales or transmission of electricity in interstate
commerce. All of Reliant Resources' generation subsidiaries sell power at
wholesale and are public utilities under the Federal Power Act with the
exception of two facilities in Texas, which are qualifying facilities and not
regulated as public utilities. The facilities in our Texas generation business
are located in ERCOT and therefore are not public utilities subject to the
FERC's jurisdiction under the Federal Act. The FERC has authorized our public
utility subsidiaries to sell electricity and related services at wholesale at
market-based rates. In its orders authorizing market-based rates, the FERC also
has granted these subsidiaries waivers of many of the accounting, record keeping
and reporting requirements that are imposed on public utilities with cost-based
rate schedules.

The FERC's orders accepting the market-based rate schedules filed by our
subsidiaries or their predecessors, as is customary with such orders, reserve
the right to revoke or limit our market-based rate authority if the FERC
subsequently determines that any of our affiliates possess excessive market
power. If the FERC were to revoke or limit our market-based rate authority, we
would have to file, and obtain the FERC's acceptance of, cost-based rate
schedules for all or some of our sales. In addition, the loss of market-based
rate authority could subject us to the accounting, record keeping and reporting
requirements that the FERC imposes on public utilities with cost-based rate
schedules. Sales from our Electric Operations business segment are not subject
to FERC jurisdiction because ERCOT is not connected to a national grid.

The FERC issued Order No. 2000 in December 1999. Order No. 2000, which
applies to all FERC jurisdictional transmission providers, describes the FERC's
intention to promote the establishment of large RTOs and sets forth the minimum
characteristics and functions of RTOs. Among the basic minimum characteristics
are that the RTOs must be independent of market participants and must be of
sufficient scope and geographical configuration. Order No. 2000 also encourages
RTOs to work with each other to minimize or eliminate "seams" issues between
RTOs that operate as barriers to inter-regional transactions. The FERC's goal is
to encourage the growth of a robust competitive wholesale market for
electricity. Although jurisdictional transmission providers are not required to
join RTOs, they are encouraged to do so. Under Order No. 2000, RTOs were to be
operational by December 15, 2001. However, because RTO development was in
different stages in different regions of the country, the FERC issued an order
on November 7, 2001 extending

40

the deadline until it resolves issues relating to geographic scope and
governance of qualifying RTOs across the country and issues relating to business
and procedural needs. For organizations to accomplish the functions of Order No.
2000, the FERC is taking steps to create business standards and protocols to
facilitate RTO formation. However, there can be no assurance that the FERC's
goals will be achieved. Also there is considerable state-level resistance in
some regions, including regions in which we operate, to the formation of RTOs.
At least 14 separate organizations, covering the substantial majority of all the
FERC jurisdictional transmission providers, are in various stages of
organization and have made at least preliminary filings with the FERC. Our T&D
Utility is not subject to the FERC's jurisdiction, except with respect to
certain high voltage, direct current ties linking ERCOT to the Southwest Power
Pool, and therefore does not have to join an RTO.

Trading and Marketing. Our domestic electric trading and marketing
operations outside of ERCOT are also subject to the FERC's jurisdiction under
the Federal Power Act. As a gas marketer, we make sales of natural gas in
interstate commerce at wholesale pursuant to a blanket certificate issued by the
FERC, but the FERC does not otherwise regulate the rates, terms or conditions of
these gas sales. We also have subsidiaries that are "public utilities" under the
Federal Power Act, and their wholesale sales of electricity in interstate
commerce are subject to FERC-filed rate schedules that authorize them to make
sales at negotiated, market-based rates.

In authorizing market-based rates for various of our subsidiaries, the FERC
has imposed some restrictions on these entities' transactions with Reliant
Energy HL&P, including a prohibition on the receipt of goods or services on a
preferential basis. The FERC also has imposed restrictions on natural gas
transactions between Reliant Resources' public utility subsidiaries and Reliant
Energy's natural gas pipeline subsidiaries to preclude any preferential
treatment. Similar restrictions apply to transactions between Reliant Resources
and Reliant Energy HL&P under Texas utility regulatory laws.

Hydroelectric Facilities. The majority of our generating facilities
located in the state of New York are hydroelectric facilities, many of which are
subject to the FERC's exclusive authority under the Federal Power Act to license
non-federal hydroelectric projects located on navigable waterways and federal
lands. These FERC licenses must be renewed periodically and can include
conditions on operation of the project at issue.

STATE AND LOCAL REGULATIONS

TEXAS

Electric Operations -- The Texas Electric Restructuring Law. In June 1999,
the Texas legislature adopted the Texas Electric Restructuring Law, which
substantially amended the regulatory structure governing electric utilities in
Texas in order to allow and encourage retail competition. Retail pilot projects
allowing competition for up to 5% of each utility's load in all customer classes
began in August 2001, and retail electric competition for all other customers
began in January 2002.

The Texas Electric Restructuring Law required electric utilities in Texas
to restructure their businesses in order to separate power generation,
transmission and distribution, and retail electric sales activities into three
different units, whether commonly or separately owned. As a result of the Texas
Electric Restructuring Law, retail sales of electricity to residential,
commercial and industrial customers must now be made by "retail electric
providers." Generally, the retail electric providers that have been certified by
the Texas Utility Commission obtain electricity from power generation companies,
exempt wholesale generators and other generating entities at unregulated rates,
sell electricity at generally unregulated rates to their retail customers and
pay the transmission and distribution utility a regulated tariff rate for
delivering the electricity to their customers. For additional information
regarding these transmission and distribution utility tariff rates, please read
"-- Electric Operations -- Rate Case" in Item 1 of this Form 10-K. Retail
electric providers are not permitted to own or operate generation assets and, as
a general rule, their prices are not subject to traditional cost-of-service rate
regulation. Retail electric providers that are affiliates of, or successors in
interest to, electric utilities may compete substantially statewide for these
sales, but prices they may charge to residential and small commercial customers
within the affiliated electric utility's certificated service territory are
subject to a fixed, specified price set by the Texas Utility Commission at the
outset of retail competition (price to beat) that is subject to potential
adjustments up to two times per year. All of our retail activities, including
41

activities conducted by retail electric providers in Texas, are now conducted by
Reliant Resources and its subsidiaries.

Wholesale power generators will continue to sell electric energy to
purchasers, including retail electric providers, at unregulated rates. To
facilitate a competitive market, each power generator affiliated with a
transmission and distribution utility is required to sell at auction 15% of the
output of its installed generating capacity. This auction obligation continues
until January 1, 2007, unless the Texas Utility Commission determines before
that date that at least 40% of the quantity of electric power consumed in 2000
by residential and small commercial customers in the affiliated transmission and
distribution utility's service area is being served by retail electric providers
not affiliated with the incumbent utility. An affiliated retail electric
provider may not purchase capacity sold by its affiliated power generation
company in the state mandated capacity auction. For additional information
regarding the state mandated auctions, please read "Electric
Operations -- Generation -- State Mandated Capacity Auctions" in Item 1 of this
Form 10-K and Note 4(a) to our consolidated financial statements.

Municipally-owned utilities and electric cooperatives have the option to
open their markets to retail competition any time after January 1, 2002.
However, until a municipally-owned utility or electric cooperative adopts a
resolution opting to open its market to retail competition, it may not offer
electric energy at unregulated prices to retail customers outside its service
area. In November 2001, Nueces Electric Cooperative and San Patricio Electric
Cooperative received Texas Utility Commission approval of required filings
necessary to open their markets to retail competition. Some large Texas cities,
including San Antonio and Austin, are served by municipally-owned utilities that
have not announced when or if they will open their markets to competition.

In December 2001, the Texas Utility Commission established the price to
beat which the retail electric providers operated under Reliant Resources are
required to charge their residential and small commercial customers for
electricity sales in Reliant Energy HL&P's service territory. The price to beat
was set at a level resulting in an estimated 17% reduction to pre-existing rates
for residential customers and an estimated 22% reduction to pre-existing rates
for small commercial customers.

New, unaffiliated retail electric providers that enter a particular market
may sell electricity to residential and small commercial customers at any price,
including a price below the price to beat. By allowing non-affiliated retail
electric providers to provide retail electric service to customers in an
electric utility's traditional service territory at any price, including a price
below the price to beat, the Texas Electric Restructuring Law is designed to
encourage competition among retail electric providers. Affiliated retail
electric providers will not be permitted to sell electricity to residential and
small commercial customers in the transmission and distribution utility's
traditional service territory at a price other than the price to beat until
January 1, 2005, unless before that date the Texas Utility Commission determines
that 40% or more of the amount of electric power that was consumed in 2000 by
the relevant class of customers in the certificated service area of the
affiliated transmission and distribution utility is committed to be served by
other retail electric providers. In addition, the Texas Electric Restructuring
Law requires the affiliated retail electric provider to make the price to beat
available to residential and small commercial customers in the traditional
service area of the related incumbent utility through January 1, 2007. The price
to beat only applies to electric services provided to residential and small
commercial customers (i.e. customers with an aggregate peak demand at or below
one MW). Electric services provided to large commercial, industrial and
institutional customers (i.e. customers with an aggregate peak demand of greater
than one MW), whether by the affiliated retail electric provider or a
non-affiliated retail electric provider, may be provided at any negotiated
price.

The Texas Utility Commission's regulations allow an affiliated retail
electric provider to adjust the wholesale energy supply cost component or "fuel
factor" included in its price to beat based on a percentage change in the price
of natural gas. The fuel factor included in our price to beat was initially set
by the Texas Utility Commission at the then average forward 12 month gas price
strip of approximately $3.11/MMBtu. In addition, the affiliated retail electric
provider may also request an adjustment as a result of changes in its price of
purchased energy. In such a request, the affiliated retail electric provider may
adjust the fuel factor to the extent necessary to restore the amount of headroom
that existed at the time the initial price to beat fuel factor

42

was set by the Texas Utility Commission. An affiliated retail electric provider
may request that its price to beat be adjusted twice a year. Currently, we
cannot estimate with any certainty the magnitude and timing of the adjustments
required, if any, and the eventual impact of such adjustments on headroom. To
the extent that the adjustments are not received on a timely basis, our Retail
Energy business segment's results of operations may be adversely affected. Based
on forward gas prices at the end of March 2002, the retail electric providers
operated under Reliant Resources estimate they would be able to increase their
price to beat by between approximately 4-5%.

The Texas Electric Restructuring Law requires the affiliated retail
electric provider to reconcile and credit to the affiliated transmission and
distribution utility in early 2004 any positive difference between the price to
beat, reduced by a specified delivery charge, and the prevailing market price of
electricity unless the Texas Utility Commission determines that, on or prior to
January 1, 2004, 40% or more of the amount of electric power that was consumed
in 2000 by residential or small commercial customers, as applicable, within the
affiliated transmission and distribution utility's traditional service territory
is committed to be served by other non-affiliated retail electric providers. If
the 40% test is not met, the reconciliation and credit will be in the form of a
payment from Reliant Resources to CenterPoint Energy, not to exceed $150 per
customer. For additional information regarding this payment, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Liquidity and Capital Resources -- Reliant Resources-unregulated
businesses -- "Clawback" Payment to Reliant Energy" in Item 7 of this Form 10-K.

The Texas Electric Restructuring Law requires the Texas Utility Commission
to designate retail electric providers as POLRs in areas of the state in which
retail competition is in effect. A POLR is required to offer a standard retail
electric service package for each class of customers designated by the Texas
Utility Commission at a fixed, nondiscountable rate approved by the Texas
Utility Commission, and is required to provide the service package to any
requesting retail customer in the territory for which it is the POLR. In the
event that another retail electric provider fails to serve any or all of its
customers, the POLR is required to offer that customer the standard retail
service package for that customer class with no interruption of service. For
additional information regarding the obligations of StarEn Power, a subsidiary
of Reliant Resources, as a POLR, and regarding the Texas retail market framework
in general, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Retail Energy Operations" in
Item 7 of this Form 10-K.

Electric Operations -- Rate Case. On October 3, 2001, the Texas Utility
Commission issued an order setting the rates to be charged by the T&D Utility
for delivery of electricity beginning in January 2002. The order resulted from a
March 31, 2000 filing (Wires Case) with the Texas Utility Commission as required
by the Texas Electric Restructuring Law. The Wires Case set the regulated rates
for the T&D Utility to be effective when electric competition began. This
regulated wires rate, or non-bypassable delivery charge, includes the
transmission and distribution rate, a system benefit fund fee, a nuclear
decommissioning fund charge, a municipal franchise fee and a transition charge
associated with securitization of regulatory assets. In addition, we are
required to make a final fuel reconciliation filing under the terms of the Texas
Electric Restructuring Law on or before July 1, 2002. For additional information
regarding the effects of the Texas Utility Commission's October 3, 2001 order,
please read Note 4 to our consolidated financial statements.

Electric Operations -- Fuel Filings. For additional information regarding
the fuel filings of our Texas generation business for the recovery of
under-recovered fuel costs, please read Note 4(c) to our consolidated financial
statements.

Electric Operations -- Stranded Costs and Regulatory Assets. The Texas
Electric Restructuring Law provides for the recovery of stranded costs and
regulatory assets resulting from the unbundling of generation facilities and the
related onset of retail competition. Stranded costs include the positive excess
of the regulatory net book value of generation assets over the market value of
the assets, taking into account a utility's generation assets, any above-market
purchased power costs and any deferred debits relating to a utility's mandatory
discontinuance of the application of certain accounting standards for
generation-related assets. The Texas Electric Restructuring Law provides several
alternatives for the determination of stranded costs, and pursuant to the master
separation agreement we have agreed to use the "partial stock valuation"

43

methodology under which we plan to cause Texas Genco to either issue and sell in
an initial public offering or to distribute to our shareholders no more than 20%
of Texas Genco's common stock. Under this methodology, the Texas Utility
Commission will employ the trading price of the stock on a national exchange
over a defined period to arrive at the market value of Texas Genco in order to
assess our stranded costs in a proceeding that we will file in 2004. In
accordance with the Texas Electric Restructuring Law, beginning on January 1,
2002, and ending when the true-up proceeding is completed in January 2004, any
difference between market power prices received in the generation capacity
auction and the Texas Utility Commission's earlier estimates of those market
prices will be included in the 2004 stranded cost true-up. This component of the
true-up is intended to ensure that neither the customers nor Reliant Energy is
disadvantaged economically as a result of the two-year transition period by
providing this pricing structure. For more information about stranded costs,
please read "Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Electric Operations -- Generation" in Item 7 of this Form
10-K and Note 4(a) to our consolidated financial statements.

Our regulatory assets include the Texas generation business-related portion
of the amount reported by us in our 1998 Form 10-K as "regulatory assets and
liabilities," offset by the applicable portion of generation-related investment
tax credits permitted under the Internal Revenue Code. Pursuant to a financing
order issued by the Texas Utility Commission, we issued, through an indirect
wholly owned subsidiary, $749 million aggregate principal amount of transition
bonds in October 2001 and used the proceeds to reduce our recoverable regulatory
assets by repaying other indebtedness. For more information about the transition
bonds and recovery of regulatory assets, please read Note 4(a) to our
consolidated financial statements.

We will make a filing in January 2004 in a true-up proceeding provided for
by the Texas Electric Restructuring Law. The purpose of this proceeding will be
to quantify and reconcile the amount of stranded costs, differences in the
capacity auction prices and Texas Utility Commission estimates, unreconciled
fuel costs and other regulatory assets associated with our Texas generation
business not previously securitized by the transition bonds. We will be required
to establish and support the amounts of these costs in order to recover them.
For more information about the true-up proceeding, please read Note 4(a) to our
consolidated financial statements.

Electric Operations -- Other. Currently, the T&D Utility conducts its
electric utility operations under a certificate of convenience and necessity
granted by the Texas Utility Commission. The certificate of convenience and
necessity covers the present service area and facilities of our Electric
Operations business segment. In addition, the T&D Utility holds non-exclusive
franchises from the incorporated municipalities in the service territory of our
Electric Operations business segment. These franchises give the T&D Utility the
right to operate its transmission and distribution system within the streets and
public ways of these municipalities for the purpose of delivering electric
service to the municipality, its residents and businesses. None of these
franchises expires before 2007.

OTHER STATES

Natural Gas Distribution. In almost all communities in which our Natural
Gas Distribution business segment provides service, RERC operates under
franchises, certificates or licenses obtained from state and local authorities.
The terms of the franchises, with various expiration dates, typically range from
10 to 30 years. None of our Natural Gas Distribution business segment's material
franchises expire before 2005. We expect to be able to renew expiring
franchises. In most cases, franchises to provide natural gas utility services
are not exclusive.

Substantially all of our Natural Gas Distribution business segment's retail
sales are subject to traditional cost-of-service regulation at rates regulated
by the relevant state public service commissions and, in Texas, by the Texas
Railroad Commission and municipalities we serve. For additional information
regarding our ability to recover increased costs of natural gas from our
customers, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting Our Future
Earnings -- Competitive and Other Factors Affecting RERC Operations -- Natural
Gas Distribution" in Item 7 of this Form 10-K.

44

On November 21, 2001, Arkla filed a rate case (Docket 01-243-U) with the
Arkansas Public Service Commission seeking an increase in rates for its Arkansas
customers of approximately $47 million on an annual basis. Arkla's last rate
increase was authorized in 1995. In the rate filing, Arkla maintains that its
rate base has grown by $183 million, and its operating expenses have increased
from $93 million to $106 million on an annual basis and, therefore, Arkla's
current rates for service to Arkansas customers do not provide a reasonable
opportunity for Arkla to cover its operating costs and earn a fair return on its
investment. A decision in the case is expected by the fourth quarter of 2002.

NUCLEAR REGULATORY COMMISSION

We are required by NRC regulations to estimate from time to time the
amounts required to decommission our ownership share of the South Texas Project
and are required to maintain funds to satisfy that obligation when the plant
ultimately is decommissioned. We currently collect through our electric rates
amounts calculated to provide sufficient funds at the time of decommissioning to
discharge these obligations. Those funds are maintained in a nuclear
decommissioning trust (Nuclear Decommissioning Trust). Under the Texas Electric
Restructuring Law, funds for decommissioning nuclear facilities like the South
Texas Project continue to be subject to cost of service rate regulation and are
collected by the T&D Utility through a non-bypassable charge from transmission
and distribution customers. Funds collected will be deposited into the Nuclear
Decommissioning Trust.

When our Texas generation business is transferred to Texas Genco, we will
transfer beneficial ownership in the Nuclear Decommissioning Trust to Texas
Genco, as the licensee of the facility. In connection with that transfer, we
have obtained a private letter ruling from the IRS to confirm that such funds
will continue to receive tax treatment they currently hold following the
transfer so long as Reliant Energy and its successor continue to own the
controlling interest in Texas Genco. After the Restructuring, the T&D Utility
will continue to collect amounts authorized under its rates for nuclear
decommissioning and will pay the amounts collected to Texas Genco for deposit
into the Nuclear Decommissioning Trust. Texas Genco will be responsible for
complying with NRC requirements for decommissioning. Under the master separation
agreement, however, the T&D Utility is obligated to collect from its customers
amounts required to decommission the South Texas Project in the event the funds
in the Nuclear Decommissioning Trust prove to be inadequate to satisfy the
licensee's obligations, and the T&D Utility has agreed to indemnify Texas Genco
from responsibility for additional amounts required even if they are not
collected from customers.

While our current funding levels exceed NRC minimum requirements, no
assurance can be given that the amounts held in trust will be adequate to cover
the actual decommissioning costs of the South Texas Project. Such costs may vary
because of changes in the assumed date of decommissioning and changes in
regulatory requirements, technology and costs of labor, materials and waste
burial. Nor can assurance be given that the current tax treatment accorded funds
maintained in the Nuclear Decommissioning Trust or additional amounts deposited
can be maintained if Reliant Resources exercises the Texas Genco Option.

For information regarding the NRC's regulation of nuclear decommissioning
trust funds, please read Note 14(k) to our consolidated financial statements.

THE NETHERLANDS

Prior to the deregulation of the Dutch wholesale market in 2001, our
European Energy business segment sold its generating output to a national
production pool and, in return, received a standardized remuneration. The
remuneration included fuel cost, return of and on capital and operation and
maintenance expenses. Under a transitional agreement which expired in 2000, the
non-fuel portion of this amount was fixed during the period 1997 through 2000.
For additional information, please read "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our European Energy
Operations -- Competition in the European Market" and "-- Deregulation of the
Dutch Market" in Item 7 of this Form 10-K.

In 2001, the wholesale energy market of our European Energy business
segment's primary market in the Netherlands was opened to competition. Our
European Energy business segment continues to be subject to
45

regulation by a number of national and European regulatory agencies and
regulations relating to the environment, labor, tax and other matters. For
example, our European Energy business segment's operations are subject to the
regulation of Dutch and European Community anti-trust authorities, who have
extensive authority to investigate and prosecute violations by energy companies
of anti-monopolistic and price-fixing regulations. In addition, our European
Energy business segment must also comply with various national and regional grid
codes and other regulations establishing access to transmission systems. Many of
the significant suppliers and customers of our European Energy business segment
are subject to continued regulation by various energy regulatory bodies that
have the authority to establish tariffs for such entities. The impact of
regulations on these entities has an indirect impact on our European Energy
business segment.

In some European countries, it is uncertain to what extent companies
trading in energy, fuel and other commodities (physical and financial) might be
deemed subject to regulation as brokers and dealers under local securities laws.
To the extent that its operations are deemed subject to these laws, our European
Energy business segment could become subject to minimum capitalization,
licensing and reporting requirements similar to those which exist for securities
broker and dealer firms. Although our European Energy business segment believes
that its operations are currently outside the scope of such regulations, no
assurance can be given as to the future positions of these regulatory agencies
regarding the applicability of these regulations to our European Energy business
segment's operations.

ENVIRONMENTAL MATTERS

GENERAL ENVIRONMENTAL ISSUES

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 pollutants into 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. In order to comply with these
requirements, we will spend substantial amounts from time to time to construct,
modify and retrofit equipment, acquire air emission allowances for operation of
our facilities, and to clean up or decommission disposal or fuel storage areas
and other locations as necessary.

If we do not comply with environmental requirements that apply to our
operations, regulatory agencies could seek to impose on us civil, administrative
and/or criminal liabilities as well as seek to curtail our operations. Under
some statutes, private parties could also seek to impose upon us civil fines or
liabilities for property damage, personal injury and possibly other costs.

We anticipate investing up to $532 million in capital and other special
project expenditures between 2002 and 2006 for environmental compliance, $397
million of which is comprised of projected expenditures for CenterPoint Energy
and its subsidiaries after the Distribution and $135 million of which is
comprised of projected expenditures for Reliant Resources and its subsidiaries
after the Distribution. In addition, environmental capital expenditures for the
recently acquired Orion Power assets over this period are estimated to be $241
million. We are currently reviewing these estimates. For additional information
regarding environmental expenditures, please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Certain Factors
Affecting Our Future Earnings -- Environmental Expenditures" in Item 7 of this
Form 10-K and Note 14(f) to our consolidated financial statements.

AIR EMISSIONS

As part of the 1990 amendments to the Federal Clean Air Act, requirements
and schedules for compliance were developed for attainment of health-based
standards. As part of this process, standards for the emission of NOx, a product
of the combustion process associated with power generation and natural gas
compression, are being developed or have been finalized. The standards require
reduction of emissions from our power generating units in the United States and
some of our natural gas compression facilities. We believe the reductions will
require substantial expenditures in the years 2002 through 2004, with possible
additional expenditures after that for our facilities in Texas. The Texas
Electric Restructuring Law provides for stranded cost recovery of costs incurred
before May 1, 2003 to achieve the NOx reduction requirements. The post-2004
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requirements in Texas are currently being litigated, and the outcome of the
litigation cannot be predicted at this time. Our facilities in the Netherlands
were in compliance with applicable Dutch NOx emission standards through the year
2001. New NOx reduction targets have recently been adopted in the Netherlands
which will require a 50% reduction in NOx emissions from 2000 levels by 2010.
The reductions may be achieved through the installation of emission control
equipment or through the participation in a planned market-based emission
trading system. We currently believe that our Dutch facilities will not be
required to install NOx controls or purchase emission credits until the 2005
through 2006 time period. Projected emission control costs are estimated to be
approximately $30 million, although this investment may be offset to some extent
or delayed if a market-based trading program develops.

The Environmental Protection Agency (EPA) has announced its determination
to regulate hazardous air pollutants (HAPs), including mercury, from coal-fired
and oil-fired steam electric generating units under Section 112 of the Clean Air
Act. The EPA plans to develop maximum achievable control technology (MACT)
standards for these types of units. The rulemaking for coal and oil-fired steam
electric generating units must be completed by December 2004. Compliance with
the rules will be required within three years thereafter. The MACT standards
that will be applicable to the units cannot be predicted at this time and may
adversely impact our results of operations. In addition, a request for
reconsideration of the EPA's decision to impose MACT standards has been filed
with the EPA. We cannot predict the outcome of the request.

In 1998, the United States became a signatory to the United Nations
Framework Convention on Climate Change (Kyoto Protocol). The Kyoto Protocol
calls for developed nations to reduce their emissions of greenhouse gases.
Carbon dioxide, which is a major byproduct of the combustion of fossil fuel, is
considered to be a greenhouse gas. If the United States Senate ultimately
ratifies the Kyoto Protocol, any resulting limitations on power plant carbon
dioxide emissions could have a material adverse impact on all fossil fuel fired
facilities, including those belonging to us. The European Union, of which the
Netherlands is a member, has adopted the Kyoto Protocol as the goal for
greenhouse gas emission targets. We expect REPGB, our Dutch subsidiary, through
use of "green fuels" and efficiency improvements, will be able to meet its
portion of the target reductions.

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, six of our coal-fired facilities operated
through Reliant Resources have received requests for information related to work
activities conducted at those sites, as have two of our recently acquired Orion
Power facilities. 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 currently contemplated for the facilities and result in the
imposition of penalties.

In February 2001, the United States Supreme Court upheld a previously
adopted EPA ambient air quality standards for fine particulate matter and ozone.
While attaining these new standards may ultimately require expenditures for air
quality control system upgrades for our facilities, regulations addressing
affected sources and required controls are not expected until after 2005.
Consequently, it is not possible to determine the impact on our operations at
this time.

Multi-pollutant air emission initiative. On February 14, 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 (SO2), NOx, and
mercury. In addition, a voluntary program for greenhouse gas emissions is
proposed as an alternative to the Kyoto Protocol discussed above. The
implementation of the initiative, if approved by the United States Congress,
would be a market-based program beginning in 2008 and phased full compliance by
2018. Fossil fuel-fired power plants in the United States would be affected by
the adoption of this program, or other legislation currently pending in the
United States Congress addressing similar issues. Such programs would require

47

compliance to be achieved by the installation of pollution controls, the
purchase of emission allowances or curtailment of operations.

WATER ISSUES

In July 2000, the EPA issued final rules for the implementation of the
Total Maximum Daily Load program of the Clean Water Act (TMDL). The goal of the
TMDL rules is to establish, over the next 15 years, the maximum amounts of
various pollutants that can be discharged into waterways while keeping those
waterways in compliance with water quality standards. The establishment of TMDL
values may eventually result in more stringent discharge limits in each
facility's discharge permit. Such limits may require our facilities to install
additional water treatment, modify operational practices or implement other
wastewater control measures. Certain members of the United States Congress have
expressed concern to the EPA about the TMDL program and the EPA, in October
2001, extended the effective date of the regulation until April 2003.

In November 2001, the EPA promulgated rules that impose additional
technology based requirements on new cooling water intake structures. Proposed
rules for existing intake structures have also been issued. It is not known at
this time what requirements the final rules for existing intake structures will
impose and whether our existing intake structures will require modification as a
result of such requirements. The process by which the intake structure rules
were written was contentious and litigation is expected. Court action in
response to this expected litigation could result in unforeseen changes in the
requirements.

A number of efforts are under way within the EPA to evaluate water quality
criteria for parameters associated with the by-products of fossil fuel
combustion. These parameters include arsenic, mercury and selenium. Significant
changes in these criteria could impact station discharge limits and could
require our facilities to install additional water treatment equipment. The
impact on us as a result of these initiatives is unknown at this time.

LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION

Under the purchase agreements between Sithe Energies and Reliant Energy
Power Generation, Inc. (REPG), a subsidiary of Reliant Resources, relating to
some of our Northeast regional facilities, and in the transaction with Orion
Power, Reliant Resources, with a few exceptions, assumed liability for
preexisting conditions, including some ongoing remediations at the electric
generating stations. Funds for carrying out any identified actions have been
included in our planning for future requirements, and we are not currently aware
of any environmental condition at any of our facilities that we expect to have a
material adverse effect on our financial position, results of operation or cash
flows.

A prior owner of one of our Northeast facilities entered into a Consent
Order Agreement with the Pennsylvania Department of Environmental Protection
(PaDEP) to remediate a coal refuse pile on the property of the facility. We
expect the remediation will cost between $10 million and $15 million. Under the
acquisition agreements between Sithe Energies and GPU, Inc. (GPU) relating to
some of our Northeast regional facilities, GPU has agreed to retain
responsibility for up to $6 million of environmental liabilities associated with
the coal refuse site at this facility. We will be responsible for any amounts in
excess of that $6 million. In August 2000 we signed a modified consent order
that committed us to complete the remediation work no later than November 2004.
In addition to the coal refuse site at this facility, we had liabilities
associated with six future ash disposal site closures and six current site
investigations and environmental remediations. We expect to pay approximately
$16 million over the next five years to monitor and remediate these sites.

Under the New Jersey Industrial Site Recovery Act (ISRA), owners and
operators of industrial properties are responsible for performing all necessary
remediation at the facility prior to the closing of a facility and the
termination of operations, or undertaking actions that ensure that the property
will be remediated after the closing of a facility and the termination of
operations. In connection with the acquisition of facilities from Sithe
Energies, Reliant Resources has agreed to take responsibility for any costs
under ISRA relating to the four New Jersey properties they purchased. They
estimate that the costs to fulfill their
48

obligations under ISRA will be approximately $10 million. However, these
remedial activities are still in the early stages. Following further
investigation the scope of the necessary remedial work could increase, and we
could, as a result, incur greater costs.

One of our Florida generation facilities operated through Reliant Resources
discharges wastewater to percolation ponds which in turn, percolate into the
groundwater. Elevated levels of vanadium and sodium have been detected in
groundwater monitoring wells. A noncompliance letter has been received from the
Florida Department of Environmental Protection. A study to evaluate the cause of
the elevated constituents has been undertaken. At this time, if remediation is
required, the cost, if any, is not anticipated to be material.

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 because of maintenance, repairs, replacement or damage
to the asbestos itself. We have planned for the proper management, abatement and
disposal of asbestos and lead-based paint at our facilities in our financial
planning.

Manufactured Gas Plant Sites. RERC and its predecessors operated a
manufactured gas plant until 1960 adjacent to the Mississippi River in Minnesota
formerly known as Minneapolis Gas Works. RERC has substantially completed
remediation of the main site other than ongoing water monitoring and treatment.
The manufactured gas was stored in separate holders. RERC is negotiating cleanup
of one such holder. There are six other former manufactured gas plant sites in
the Minnesota service territory. Remediation has been completed on one site. Of
the remaining five sites, RERC believes that two were neither owned nor operated
by RERC. RERC believes it has no liability with respect to the sites we neither
owned nor operated.

At December 31, 2000 and 2001, RERC had accrued $18 million and $23
million, respectively, for remediation of the Minnesota sites. At December 31,
2001, the estimated range of possible remediation costs was $11 million to $49
million. The cost estimates of the Minneapolis Gas Works site are based on
studies of that site. The remediation costs for the other sites are based on
industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites remediated, the
participation of other potentially responsible parties, if any, and the
remediation methods used.

Issues relating to the identification and remediation of manufactured gas
plants are common in the natural gas distribution industry. RERC has received
notices from the United States Environmental Protection Agency and others
regarding its status as a potentially responsible party for other sites. Based
on current information, RERC has not been able to quantify a range of
environmental expenditures for potential remediation expenditures with respect
to other manufactured gas plant sites.

Hydrocarbon Contamination. In August 2001, a number of Louisiana residents
who live near the Wilcox Aquifer filed suit against RERC Corp., Reliant Energy
Pipeline Services, Inc., other Reliant Energy entities and third parties (Docket
No. 460, 916-Div. "B"), in the 1st Judicial District Court, Caddo Parish,
Louisiana. The suit alleges that we and the other defendants allowed or caused
hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath
property owned or leased by the defendants and is the sole or primary drinking
water aquifer in the area. The quantity of monetary damages sought is
unspecified. For additional information regarding this suit and the remediation
of the site, please read note 14(f) to our consolidated financial statements.

Other Minnesota Matters. At December 31, 2000 and 2001, RERC had recorded
accruals of $4 million and $5 million, respectively, for other environmental
matters in Minnesota for which remediation may be required. At December 31,
2001, the estimated range of possible remediation costs was $4 million to $8
million.

MERCURY CONTAMINATION

Like similar companies, our pipeline and natural gas distribution
operations have in the past employed elemental mercury in measuring and
regulating equipment. It is possible that small amounts of mercury may
49

have been spilled in the course of normal maintenance and replacement operations
and that these spills may have contaminated the immediate area around the meters
with elemental mercury. We have found this type of contamination in the past,
and we have conducted remediation at sites found to be contaminated. Although we
are not aware of additional specific sites, it is possible that other
contaminated sites may exist and that remediation costs may be incurred for
these sites. Although the total amount of these costs cannot be known at this
time, based on our experience and that of others in the natural gas industry to
date and on the current regulations regarding remediation of these sites, we
believe that the cost of any remediation of these sites will not be material to
our financial position, results of operations or cash flows. For additional
information regarding environmental expenditures associated with mercury
contamination, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- Certain Factors Affecting our Future
Earnings -- Environmental Expenditures -- Water, Mercury and Other Expenditures"
in Item 7 of this Form 10-K.

Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, or CERCLA, owners and operators of facilities from 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 aware of any liabilities under CERCLA that would have a material
adverse effect on us, our financial position, results of operations or cash
flows.

EUROPEAN ENERGY

European and Dutch environmental laws are among the most stringent in the
industrial world. Under Dutch environmental laws, an environmental permit is
required to be maintained for each generation facility. As is customary in Dutch
practice, our European Energy business segment has, together with other industry
participants, entered into various contractual agreements with the national
government on specific environmental matters, including the reduction of the use
of coal and other fossil fuel. The environmental laws also address public
safety. We believe our European Energy business segment holds all necessary
authorizations and approvals for its current operations.

The European Union, of which the Netherlands is a member, adopted the Kyoto
Protocol as the goal for greenhouse gas emission targets. For further discussion
of the protocol, please read "-- Air Emissions." We believe our European Energy
business segment will meet its current portion of target reductions because of
its use of "green fuels" and efficiency improvements to its facilities.

NOx reduction targets will require a 50% reduction in NOx emissions from
2000 levels by 2010. The reductions may be achieved through the installation of
emission control equipment or through the participation in a planned
market-based emission trading system. Our European facilities are in compliance
with current and applicable Dutch NOx emission standards. Based on current
factors, we believe that our European facilities will not be required to install
NOx controls or purchase emission credits until the 2005-2006 time period.

We estimate that we will spend approximately $30 million in emission
control and other environmental costs associated with our European Energy
business segment for the period 2002 through 2006. In addition, we expect to
spend approximately $18 million in asbestos and other environmental remediation
programs during this period.

OTHER

We have been named, along with numerous others, as a defendant in a number
of lawsuits filed by a large number of individuals who claim injury due to
exposure to asbestos while working at sites along the Texas Gulf Coast. Most of
these claimants have been workers who participated in construction of various
industrial

50

facilities, including power plants, and some of the claimants have worked at
locations owned by us. We anticipate that additional claims like those received
may be asserted in the future, and we intend to continue our practice of
vigorously contesting claims that we do not consider to have merit. Although
their ultimate outcome cannot be predicted at this time, we do not believe,
based on our experience to date, that these matters, either individually or in
the aggregate, will have a material adverse effect on our financial position,
results of operations or cash flows.

EMPLOYEES

As of December 31, 2001, we had 16,563 full-time employees. The following
table sets forth the number of our employees by business segment as of December
31, 2001:

The number of our employees who were represented by unions or other
collective bargaining groups as of December 31, 2001 include (i) Electric
Operations, 2,735; (ii) Natural Gas Distribution, 1,542; (iii) Wholesale Energy,
810; and (iv) European Energy, 745.

EXECUTIVE OFFICERS OF RELIANT ENERGY
(AS OF MARCH 1, 2002)

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

(1) Effective as of the Restructuring, these individuals will continue to serve
in the indicated capacities for CenterPoint Energy. Effective as of the
Distribution, these individuals will resign their positions with CenterPoint
Energy, except that Mr. Letbetter will continue to serve as non-executive
Chairman of the CenterPoint Energy Board of Directors.

(2) Effective as of the Distribution, Mr. McClanahan will become President and
Chief Executive Officer of CenterPoint Energy.

51

Mr. Letbetter has served as Chairman of Reliant Energy since January 2000
and as President and Chief Executive Officer of Reliant Energy since June 1999.
He has been a director of Reliant Energy since 1995. He has served in various
executive officer capacities with Reliant Energy since 1978.

Mr. Harvey has served as Vice Chairman of Reliant Energy since June 1999.
Prior to joining Reliant Energy, he served as a director in the Houston office
of McKinsey & Company, Inc.

Mr. Naeve has served as Vice Chairman of Reliant Energy since June 1999 and
as Chief Financial Officer of Reliant Energy since 1997. Between 1997 and 1999,
he served as Executive Vice President and Chief Financial Officer of Reliant
Energy. He has served in various executive officer capacities with Reliant
Energy since 1988.

Mr. Perkins has served as President and Chief Operating Officer, Reliant
Energy Wholesale Group, and as President and Chief Operating Officer, Reliant
Energy Power Generation, Inc. since 1998. In 1998, Mr. Perkins served as
President and Chief Operating Officer of the Reliant Energy Power Generation
Group. Between 1996 and 1998, Mr. Perkins served as Vice President -- Corporate
Planning and Development.

Mr. Kelly has served as Executive Vice President, General Counsel and
Corporate Secretary of Reliant Energy since 1997. Between 1984 and 1997, he
served as Senior Vice President, General Counsel and Corporate Secretary of
Reliant Energy.

Ms. Ricciardello has served as Chief Accounting Officer of Reliant Energy
since June 2000 and as Senior Vice President since June 1999. Between 1999 and
2000, she served as Senior Vice President and Comptroller of Reliant Energy. She
also served as Vice President and Comptroller of Reliant Energy from 1996 to
1999. She has served in various executive officer capacities with Reliant Energy
since 1993.

We currently expect that at the time of the Distribution, David M.
McClanahan will become President and Chief Executive Officer of CenterPoint
Energy. Mr. McClanahan, who is 52 years old, has served as Vice Chairman of
Reliant Energy since October 2000 and as President and Chief Operating Officer
of Reliant Energy's Regulated Group since 1999. He served as President and Chief
Operating Officer of Reliant Energy HL&P from 1997 to 1999. He has served in
various executive officer capacities with Reliant Energy since 1986.

ITEM 2. PROPERTIES

CHARACTER OF OWNERSHIP

We own or lease our principal properties in fee, including our corporate
office space and various real property and facilities relating to our generation
assets and development activities. Most of our electric lines and gas mains are
located, pursuant to easements and other rights, on public roads or on land
owned by others.

Substantially all of the real estate, electric distribution system
properties, buildings and franchises owned directly by Reliant Energy (excluding
real estate and other properties of subsidiaries of Reliant Energy) are subject
to a lien created under a Mortgage and Deed of Trust dated as of November 1,
1944 (as supplemented, Mortgage) between Reliant Energy and South Texas
Commercial National Bank of Houston (JP Morgan Chase Bank, as Successor
Trustee). The lien of the Mortgage excludes cash, stock in subsidiaries and
certain other assets. Additionally, properties owned by subsidiaries of Reliant
Energy are subject to liens of creditors of the respective subsidiaries. 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.

ELECTRIC OPERATIONS

For information regarding the properties of our Electric Operations
business segment, please read "Electric Operations" in Item 1 of this Form 10-K,
which information is incorporated herein by reference.

52

NATURAL GAS DISTRIBUTION

For information regarding the properties of our Natural Gas Distribution
business segment, please read "Natural Gas Distribution" in Item 1 of this Form
10-K, which information is incorporated herein by reference.

PIPELINES AND GATHERING

For information regarding the properties of our Pipelines and Gathering
business segment, please read "Pipelines and Gathering" in Item 1 of this Form
10-K, which information is incorporated herein by reference.

WHOLESALE ENERGY

For information regarding the properties of our Wholesale Energy business
segment, please read "Wholesale Energy" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.

EUROPEAN ENERGY

For information regarding the properties of our European Energy business
segment, please read "European Energy" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.

RETAIL ENERGY

For information regarding the properties of our Retail Energy business
segment, please read "Retail Energy" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.

LATIN AMERICA

For information regarding the properties of our Latin America business
segment, please read "Latin America" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.

OTHER OPERATIONS

For information regarding the properties of our Other Operations business
segment, please read "Other Operations" in Item 1 of this Form 10-K, which
information is incorporated herein by reference.

ITEM 3. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting us,
see Notes 4, 14(f), 14(g) and 21 to our consolidated financial statements, which
notes are incorporated herein by reference.

RESTATEMENT OF SECOND AND THIRD QUARTER 2001 RESULTS OF OPERATIONS

On February 5, 2002, Reliant Energy announced that it was restating its
earnings for the second and third quarters of 2001. As more fully described in
Reliant Energy's March 15, 2002 Current Report on Form 8-K, the restatement
related to a correction in accounting treatment for a series of four structured
transactions that were inappropriately accounted for by Reliant Resources as
cash flow hedges for the period of May 2001 through September 2001, rather than
as derivatives with changes in fair value recognized through the income
statement. Each structured transaction involved a series of forward contracts to
buy and sell an energy commodity in 2001 and to buy and sell an energy commodity
in 2002 or 2003.

At the time of the public announcement of Reliant Energy's intention to
restate its reporting of the structured transactions, the Audit Committees of
each of the boards of directors of Reliant Energy and Reliant Resources
instructed Reliant Resources to conduct an internal audit review to determine
whether there were any other transactions included in the asset books as cash
flow hedges that failed to meet the cash flow hedge requirements under Statement
of Financial Accounting Standards (SFAS) No. 133 "Accounting

53

for Derivative Instruments and Hedging Activities" (SFAS No. 133). This targeted
internal audit review found no other similar transactions.

The Audit Committees also directed an internal investigation by outside
legal counsel of the facts and circumstances leading to the restatement, which
investigation has been completed. In connection with the restatement and related
investigations, the Audit Committees have met eight times to hear and assess
reports from the investigative counsel regarding its investigation and contacts
with the staff of the SEC. To address the issues identified in the investigation
process, the Audit Committees and management have begun analyzing and
implementing remedial actions, including, among other things, changes in
organizational structure and enhancement of internal controls and procedures.

On April 5, 2002, Reliant Resources was advised that the Staff of the
Division of Enforcement of the SEC is conducting an informal inquiry into the
facts and circumstances surrounding the restatement. Reliant Resources is
cooperating with this inquiry. Before releasing its 2001 earnings, Reliant
Energy received concurrence from the SEC's accounting staff on the accounting
treatment of the restatement, which increased its earnings for the two quarters
by a total of $107 million. At this time, we cannot predict the outcome of the
SEC's inquiry. In addition, we cannot predict what effect the inquiry may have
on our pending application to the SEC under the 1935 Act, which is required for
our Restructuring. For more information about our Restructuring, please read
"Our Business -- Status of Business Separation" and "-- Business Separation" in
Item 1 of this Form 10-K.

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

A special meeting of our shareholders was held on December 17, 2001. At the
meeting, our shareholders were asked to approve an Agreement and Plan of Merger,
dated as of October 19, 2001, pursuant to which CenterPoint Energy would become
the parent company of Reliant Energy and each outstanding share of Reliant
Energy common stock would be automatically converted into one share of
CenterPoint Energy common stock. The proposal to approve the Agreement and Plan
of Merger was approved with 167,344,153 votes for, 56,529,357 votes against and
3,019,520 abstentions.

54

PART II

ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS

As of April 8, 2002, our common stock was held of record by approximately
71,212 shareholders. Our common stock is listed on the New York and Chicago
Stock Exchanges and is traded under the symbol "REI."

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, and the cash dividends declared in these
periods. Cash dividends paid aggregated $1.50 per share in 2000 and 2001.

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

(1) The quarterly dividend of $0.375 per share normally declared in the fourth
quarter for payment in the following first quarter was declared on February
8, 2002 and paid in March 2002.

The closing market price of our common stock on December 31, 2001 was
$26.52 per share.

55

The amount of future cash dividends will be subject to determination based
upon our results of operations and financial condition, our future business
prospects, any applicable contractual restrictions and other factors that our
board of directors considers relevant and will be declared at the discretion of
the board of directors. No dividends are currently being paid to Reliant Energy
by Reliant Resources, which may affect the ability of Reliant Energy to maintain
its existing dividend levels pending completion of the Distribution.

After the consummation of the Restructuring, the declaration and payment of
dividends by CenterPoint Energy will be at the discretion of its board of
directors. CenterPoint Energy will not directly conduct any business operations
from which it will derive revenues. Therefore, the payment and rate of future
dividends on CenterPoint Energy common stock will depend primarily upon the
earnings, financial condition and capital requirements of its subsidiaries.
Following the Distribution, CenterPoint Energy will not be as large a company as
Reliant Energy is today, and the earnings of the subsidiaries and assets that
were transferred to Reliant Resources will not be available for the payment of
dividends on the CenterPoint Energy common stock. As a result, the cash dividend
per share of CenterPoint Energy common stock is expected to be reduced to a
level that is consistent with both its earnings profile and the level of cash
dividends of other predominately regulated utility businesses.

Subject to the availability of earnings, the needs of its businesses, and
other applicable restrictions, upon becoming subsidiaries of CenterPoint Energy
following the Restructuring, the T&D Utility and Texas Genco intend to make
regular cash payments to CenterPoint Energy in the form of dividends or
distributions on their stock or membership interests in amounts which would be
sufficient to pay cash dividends on CenterPoint Energy common stock as described
above and to pay operating expenses of CenterPoint Energy and for other purposes
as the board of directors of CenterPoint Energy may determine. CenterPoint
Energy expects that cash dividends will be declared and paid on approximately
the same schedule as that now followed by us with respect to our common stock
dividends.

ITEM 6. SELECTED FINANCIAL DATA

The following table presents selected financial data with respect to our
consolidated financial condition and consolidated results of operations and
should be read in conjunction with our consolidated financial statements and the
related notes in Item 8 of this Form 10-K.

Effective December 1, 2000 (Measurement Date), our board of directors
approved a plan to dispose of our Latin America business segment through sales
of its assets. Accordingly, in our 2000 consolidated financial statements, we
reported the results of our Latin America business segment as discontinued
operations in accordance with APB No. 30 for each of the three years in the
period ended December 31, 2000. On December 20, 2001, negotiations for the sale
of the remaining Latin America assets were terminated as a result of recent
adverse economic developments in Argentina. We will continue to evaluate other
options related to the future disposition of these assets. Accordingly, the
Latin America business segment is no longer reported as discontinued operations.
The related operating results and loss on disposal have been reclassified within
the Statements of Consolidated Income for all periods into operating income with
respect to consolidated subsidiaries and other income with respect to equity
investments in unconsolidated subsidiaries as required for assets held for sale.

The selected financial data includes the financial statement effect of REMA
since its acquisition in May 2000, REPGB since its acquisition in October 1999
and RERC since its acquisition in August 1997. These acquisitions were accounted
for under the purchase method. Please read Note 3 to our consolidated financial
statements for additional information regarding the REMA and REPGB acquisitions
and Note 19 to our consolidated financial statements for additional information
regarding our Latin America operations.

56

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(1) 1997 net income includes a non-cash, unrealized accounting loss on our
indexed debt securities of $79 million (after-tax), or $0.31 loss per basic
and diluted share. For additional information on the indexed debt
securities, please read Note 8 to our consolidated financial statements.

(2) 1998 net income includes a non-cash, unrealized accounting loss on our
indexed debt securities of $764 million (after-tax), or $2.69 loss per basic
and diluted share. For additional information on the

57

indexed debt securities, please read Note 8 to our consolidated financial
statements. Fixed charges exceeded earnings by $179 million in 1998.

(3) 1999 net income includes an aggregate non-cash, unrealized accounting gain
on our indexed debt securities and our Time Warner (now AOL Time Warner)
investment, of $1.2 billion (after-tax), or $4.09 earnings per basic share
and $4.08 earnings per diluted share. For additional information on the
indexed debt securities and AOL Time Warner investment, please read Note 8
to our consolidated financial statements. The extraordinary item in 1999 is
a loss related to an accounting impairment of certain generation related
regulatory assets of our Electric Operations business segment. For
additional information regarding the impairment, please read Note 4 to our
consolidated financial statements.

(4) 2000 net income includes an aggregate non-cash accounting loss on our
indexed debt securities and our AOL Time Warner investment of $67 million
(after-tax), or $0.24 loss per basic share and $0.23 loss per diluted share.
2000 net income also includes a $331 million (after-tax) charge, or $1.16
loss per basic share and $1.15 loss per diluted share, to reflect the
reclassification of our Latin America business segment from discontinued
operations to continuing operations as described above. The extraordinary
item in 2000 is a gain of $7 million, or $0.03 earnings per basic and
diluted share, related to the early extinguishment of $272 million of
long-term debt. For additional information on the indexed debt securities
and AOL Time Warner investment, please read Note 8 to our consolidated
financial statements. For additional information on our Latin America
operations, please read Note 19 to our consolidated financial statements.

(5) 2001 net income includes the following: (i) the cumulative effect of an
accounting change resulting from the adoption of SFAS No. 133 ($61 million
after-tax gain, or $0.21 earnings per basic and diluted share), (ii) a gain
related to the revaluation of our European Energy business segment's share
of NEA B.V. (formerly known as N.V. SEP), which was the coordinating body
for the Dutch electric generation sector prior to the start of wholesale
competition, ($51 million after-tax, or $0.17 earnings per basic and diluted
share), (iii) a gain related to the settlement of the stranded cost
indemnity obligations of former REPGB shareholders ($37 million after-tax,
or $0.13 earnings per basic and diluted share), (iv) a non-cash charge
related to the redesign of our employee benefit plans in anticipation of the
separation of our regulated and unregulated businesses ($65 million
after-tax, or $0.23 loss per basic share and $0.22 loss per diluted share),
(v) a charge related to the disposition of our Communications business ($42
million after-tax, or $0.14 loss per basic and diluted share) and (vi) an
impairment of our Latin America operations ($51 million after-tax, or $0.17
loss per basic and diluted share). These amounts do not reflect the effect
of the third-party minority ownership interest in Reliant Resources. For
additional information related to the above items, please read Notes 3(b),
5, 12, 19, and 20 to our consolidated financial statements.

(6) Net income attributable to common stockholders for 1999 and 2000 includes
minority interest income of $0.6 million and $1 million, respectively. Net
income attributable to common stockholders for 2001 includes minority
interest expense of $81 million.

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

The following discussion and analysis should be read in combination with
our consolidated financial statements included in Item 8 of this Form 10-K.

We are a diversified international energy services and energy delivery
company that provides energy and energy services primarily in North America and
Western Europe. We operate one of the United States' largest electric utilities
in terms of kilowatt-hour (KWh) sales, and our three natural gas distribution
divisions together form one of the United States' largest natural gas
distribution operations in terms of customers served. We invest in the
acquisition, development and operation of domestic non-rate regulated power
generation facilities. We own two interstate natural gas pipelines that provide
gas transportation, supply, gathering and storage services, and we also engage
in wholesale energy marketing and trading.

In this section we discuss our results of operations on a consolidated
basis and individually for each of our business segments. We also discuss our
liquidity, capital resources and critical accounting policies. Our

58

financial reporting business segments include Electric Operations, Natural Gas
Distribution, Pipelines and Gathering, Wholesale Energy, European Energy, Retail
Energy, Latin America and Other Operations. Historically, Retail Energy has been
reported in the Other Operations business segment. For business segment
reporting information, please read Notes 1 and 18 to our consolidated financial
statements. For additional information regarding these business segments, please
read "Business" in Item 1 of this Form 10-K.

We are in the process of separating our regulated and unregulated
businesses into two publicly traded companies. In December 2000, we transferred
a significant portion of our unregulated businesses to Reliant Resources, which,
at the time, was a wholly owned subsidiary. Reliant Resources conducted an
initial public offering (Offering) of approximately 20% of its common stock in
May 2001. In December 2001, our shareholders approved an agreement and plan of
merger by which, subject to regulatory approvals, the following will occur
(which we refer to herein as the Restructuring):

- CenterPoint Energy will become the holding company for the Reliant Energy
group of companies;

- Reliant Energy and its subsidiaries will become subsidiaries of
CenterPoint Energy; and

- each share of Reliant Energy common stock will be converted into one
share of CenterPoint Energy common stock.

After the Restructuring, we plan, subject to further corporate approvals,
market and other conditions, to complete the separation of our regulated and
unregulated businesses by distributing the shares of common stock of Reliant
Resources that we own to our shareholders (which we refer to herein as the
Distribution). Our goal is to complete the Restructuring and subsequent
Distribution as quickly as possible after all the necessary conditions are
fulfilled, including receipt of an order from the Securities and Exchange
Commission (SEC) granting the required approvals under the Public Utility
Holding Company Act of 1935 (1935 Act) and an extension from the IRS for a
private letter ruling we have obtained regarding the tax-free treatment of the
Distribution. Although receipt or timing of regulatory approvals cannot be
assured, we believe we meet the standards for such approvals. We currently
expect to complete the Restructuring and Distribution in the summer of 2002.

Effective December 1, 2000, our board of directors approved a plan to
dispose of our Latin America business segment through sales of its assets.
Accordingly, in our 2000 consolidated financial statements, we reported the
results of our Latin America business segment as discontinued operations in
accordance with Accounting Principles Board (APB) Opinion No. 30 "Reporting the
Results of Operations -- Reporting the Effects of Disposal of a Segment of a
Business, and Extraordinary, Unusual and Infrequently Occurring Events and
Transactions," (APB Opinion No. 30) for each of the three years in the period
ended December 31, 2000. On December 20, 2001, negotiations for the sale of the
remaining Latin America investments were terminated as a result of the recent
adverse economic developments in Argentina. We will continue to evaluate options
related to the future disposition of these assets.

Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Consolidated Statements of Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by Emerging Issues Task Force Issue No. 90-6. (EITF
90-6). For additional information regarding the disposal of the Latin America
business segment, see Note 19 to our consolidated financial statements.

During 2001, we incurred a pre-tax non-cash charge of $101 million relating
to the redesign of some of our benefit plans in anticipation of separation of
our regulated and our unregulated businesses. This included a curtailment gain
of $23 million related to our pension plans, an $84 million loss related to
pension benefit enhancements and a $40 million curtailment loss associated with
postretirement benefits.

All dollar amounts in the tables that follow are in millions, except for
per share and operational data.

59

CONSOLIDATED RESULTS OF OPERATIONS

2001 COMPARED TO 2000

Net Income. We reported consolidated net income of $980 million ($3.35 per
diluted share) for 2001 compared to $447 million ($1.56 per diluted share) for
2000. The 2001 results included a cumulative effect of accounting change of $61
million, net of tax, related to the adoption of Statement of Financial
Accounting Standards (SFAS) No. 133 "Accounting for Derivative Instruments and
Hedging Activities," as amended (SFAS No. 133). For additional discussion of the
adoption of SFAS No. 133, please read Note 5 to our consolidated financial
statements. The 2000 results included an extraordinary gain of $7 million, net
of tax, related to the early extinguishment of $272 million of long-term debt.
For additional discussion of the extraordinary gain, please read Note 10(b) to
our consolidated financial statements.

Our consolidated net income, before cumulative effect of accounting change,
was $919 million for 2001 compared to consolidated net income, before
extraordinary gain, of $440 million in 2000. The increase of $479 million was
primarily due to the following:

- a $674 million increase in gross margins (revenues less fuel and cost of
gas sold and purchased power) from our Wholesale Energy business segment,
excluding the impact of a $68 million provision related to energy sales
to Enron Corp. and its affiliates (Enron) which filed a voluntary
petition for bankruptcy during the fourth quarter of 2001;

- a $280 million after-tax decrease in net losses from our Latin America
business segment. An additional after-tax impairment of $51 million was
recorded in 2001. This business segment had been presented as
discontinued operations in 2000;

60

- a $57 million decrease in operating losses from our Retail Energy
business segment;

- a $37 million net gain resulting from the settlement of an indemnity
agreement related to certain energy obligations entered into in
connection with our acquisition of Reliant Energy Power Generation
Benelux N.V. (REPGB), formerly N.V. UNA;

- a $51 million gain recorded in equity income in 2001 related to a
preacquisition contingency for the value of NEA B.V. (NEA), the
coordinating body for the Dutch electricity generating sector, which is
an equity investment in which REPGB holds a 22.5% economic interest;

- a $112 million decrease in net interest expense; and

- a $27 million pre-tax impairment loss on marketable equity securities
classified as "available-for-sale" in 2000.

The above items were partially offset by:

- a decrease in operating income of $139 million from our Electric
Operations business segment primarily due to the impact of milder
weather, reduced rates charged to certain governmental agencies as
mandated by the Texas Electric Choice Plan (Texas Electric Restructuring
Law), fees paid for the early termination of an accounts receivable
factoring agreement and higher benefit expenses;

- a $66 million decrease in our European Energy business segment's gross
margins primarily attributable to the Dutch wholesale electric market
opening to competition on January 1, 2001, excluding the impact of a $17
million provision related to energy sales to Enron recorded in the fourth
quarter of 2001;

- a $101 million pre-tax, non-cash charge relating to the redesign of
certain of our benefit plans in anticipation of our separation from
Reliant Resources;

- an $85 million pre-tax provision related to energy sales to Enron which
was recorded in the fourth quarter of 2001;

- $54 million in pre-tax disposal charges and impairments of goodwill and
fixed assets related to the exiting of our Communications business;

- a $37 million decrease in our Wholesale Energy business segment's equity
earnings of unconsolidated subsidiaries in 2001 as compared to 2000; and

- an $18 million pre-tax gain in 2000 on the sale of our interest in one of
our development-stage electric generation projects.

Net income in 2000 and 2001, excluding the $101 million pre-tax non-cash
charge mentioned above, included pension income of $37 million and $5 million,
respectively. Pension income declined primarily to a decline in the market value
of pension plan assets during 2000. The market value of our pension plan assets
continued to decrease during 2001 due primarily to the declines in the U.S.
equity markets. As a result of this decline, along with a reduction in the
expected return on plan assets and discount rate assumptions, we expect to
record pension expense of approximately $40 million in 2002.

During 2001, we contributed to our pension plans approximately 4.5 million
shares of Reliant Energy common stock with a fair value of $107 million. As of
December 31, 2001, the fair value of Reliant Energy common stock held by these
plans was $120 million or 8.7% of the pension plan assets. We do not anticipate
a required pension contribution during 2002. Future effects of our pension
plans, including effects such as those mentioned above, on our operating results
depend on economic conditions, employee demographics, mortality rates and
investment performance. For additional information regarding the pension plan
assets and the components of pension income, please read Note 12 to our
consolidated financial statements.

Operating Income. For an explanation of changes in our operating income
for 2001 as compared to 2000, please read the discussion below of operating
income (loss) by business segment.

61

Other Income/Expense. We incurred other expense of $575 million for 2001
compared to other expense of $1.1 billion for 2000. The decrease of $504 million
in 2001 as compared to 2000 resulted primarily from the following:

- a $23 million increase in interest income in 2001 earned on
under-recovery of fuel costs of our Electric Operations business segment;

- a $51 million gain recorded in equity income with respect to our equity
investment in NEA;

- a $112 million decrease in net interest expense, primarily as a result of
lower levels of borrowings and lower interest rates in 2001 compared to
2000;

- a $343 million pre-tax decrease in other expense related to reduced
losses of our Latin America operations;

- a $103 million pre-tax ($67 million after-tax) non-cash accounting loss
on our indexed debt securities and our related AOL Time Warner investment
in 2000; and

- a $27 million pre-tax impairment loss on marketable equity securities
classified as "available-for-sale" in 2000.

The decrease in other expense noted above was partially offset by:

- minority interest expense of $81 million in 2001 primarily related to
minority interest in Reliant Resources as a result of the initial public
offering of Reliant Resources' common stock in May 2001 discussed above;

- an $18 million pre-tax gain in 2000 on the sale of our interest in one of
our development stage electric generation projects; and

- a $37 million decrease in our Wholesale Energy business segment's equity
earnings in unconsolidated subsidiaries in 2001 as compared to 2000. The
equity income in both years primarily resulted from an investment in an
electric generation plant in Boulder City, Nevada. The plant became
operational in May 2000. The equity income related to our investment in
the plant declined in 2001 from 2000 primarily due to higher plant
outages in 2001 and reduced power prices realized by the project company.

During 2000, we incurred a pre-tax impairment loss of $27 million on
marketable equity securities classified as "available-for-sale". Management's
determination to recognize this impairment resulted from a combination of events
occurring in 2000 related to this investment. Such events affecting the
investment included changes occurring in the investment's senior management,
announcement of significant restructuring charges and related downsizing for the
entity, reduced earnings estimates for this entity by brokerage analysts and the
bankruptcy of a competitor of the investment in the first quarter of 2000. These
events, coupled with the stock market value of our investment in these
securities continuing to be below our cost basis, caused management to believe
the decline in fair value to be other than temporary. During 2001, we recognized
a pre-tax gain of $14 million from the sale of a portion of this investment. For
additional discussion of this investment, please read Note 2(l) to our
consolidated financial statements.

Upon adoption of SFAS No. 133 effective January 1, 2001, we recorded a
transition adjustment pre-tax gain of $90 million ($58 million net of tax)
related to our investment in AOL Time Warner, Inc. (AOL TW) common stock (AOL TW
Common) and our related indexed debt obligation. The transition adjustment gain
was reported in the first quarter of 2001 as the effect of a change in
accounting principle. During 2001, we recorded a $70 million loss on our
investment in AOL TW Common. During 2001, we recorded a $58 million gain
associated with the fair value of the derivative component of the indexed debt
obligation. A detailed discussion follows in the narrative and table presented
below.

In 1997, in order to monetize a portion of the cash value of our investment
in Time Warner Inc. (TW) convertible preferred stock (TW Preferred), we issued
unsecured 7% Automatic Common Exchange Securities (ACES) having an original
principal amount of $1.052 billion and maturing July 1, 2000. The

62

market value of ACES was indexed to the market value of TW common stock (TW
Common). On July 6, 1999, we converted our investment in TW Preferred into 45.8
million shares of TW Common. Prior to the conversion, our investment in the TW
Preferred was accounted for under the cost method at a value of $990 million.
Effective on the conversion date, the shares of TW Common were classified as
trading securities under SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), and an unrealized gain was recorded
in the amount of $2.4 billion ($1.5 billion after-tax) to reflect the cumulative
appreciation in the fair value of our investment in Time Warner securities. On
the July 1, 2000 maturity date, we tendered 37.9 million shares of TW Common to
fully settle our obligations in connection with our ACES obligation. On
September 21, 1999, we issued approximately 17.2 million of 2.0% Zero-Premium
Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal
amount of $1.0 billion. At maturity the holders of the ZENS will receive in cash
the higher of the original principal amount of the ZENS (subject to adjustment)
or an amount based on the then-current market value of AOL TW Common, or other
securities distributed with respect to AOL TW Common. We used $537 million of
the net proceeds from the offering of the ZENS to purchase 9.2 million
additional shares of TW Common, which are classified as trading securities under
SFAS No. 115. Prior to the purchase of additional shares of TW Common on
September 21, 1999, we owned approximately 8 million shares of TW Common that
were in excess of the 37.9 million shares needed to economically hedge our ACES
obligation. Prior to January 1, 2001, an increase above $58.25 (subject to some
adjustments) in the market value per share of TW Common resulted in an increase
in our liability for the ZENS. However, as the market value per share of TW
Common declined below $58.25 (subject to some adjustments), the liability for
the ZENS did not decline below the original principal amount. The market value
per share of TW Common was $52.24 as of December 31, 2000 and the market value
per share of AOL TW Common was $32.10 as of December 31, 2001.

Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS
obligation was bifurcated into a debt component and a derivative component (the
holder's option to receive the appreciated value of AOL TW Common at maturity).
The derivative component was valued at fair value and determined the initial
carrying value assigned to the debt component ($121 million) as the difference
between the original principal amount of the ZENS ($1.0 billion) and the fair
value of the derivative component at issuance ($879 million). Effective January
1, 2001 the debt component was recorded at its accreted amount of $122 million
and the derivative component was recorded at its current fair value of $788
million, as a current liability, resulting in a transition adjustment pre-tax
gain of $90 million ($58 million net of tax). The transition adjustment gain was
reported in the first quarter of 2001 as the effect of a change in accounting
principle. Subsequently, the debt component will accrete through interest
charges at 17.5% up to the minimum amount payable upon maturity of the ZENS in
2029, approximately $1.1 billion, and changes in the fair value of the
derivative component will be recorded in the Statements of Consolidated Income.
During 2001, we recorded a $70 million loss on our investment in AOL TW Common.
During 2001, we recorded a $58 million gain associated with the fair value of
the derivative component of the ZENS obligation. Changes in the fair value of
the AOL TW Common we hold are expected to substantially offset changes in the
fair value of the derivative component of the ZENS.

63

The following table sets forth summarized financial information regarding
our investment in AOL TW securities and the ACES and ZENS obligations (in
millions).

For additional information regarding our investment in AOL TW, our indexed
debt securities and the effect of adoption of SFAS No. 133 on January 1, 2001 on
our ZENS obligation, please read Note 8 to our consolidated financial
statements.

Income Tax Expense. The effective tax rate for 2000 and 2001 was 42.0% and
35.2%, respectively. The decrease in the effective tax rate in 2001 compared to
2000 was primarily due to non-recurring increased tax expense arising from the
sales of our Latin American investments in 2000, increased earnings of REPGB and
decreased state income taxes in 2001, partially offset by the write-off of
goodwill in 2001 associated with our Communications business. In 2001 and prior
years, the earnings of REPGB were subject to a zero percent Dutch corporate
income tax rate as a result of the Dutch tax holiday in effect for the Dutch
electricity industry. After December 31, 2001, all of our European Energy
business segment's earnings in the Netherlands will be subject to the standard
Dutch corporate income tax rate, which is currently 34.5%.

As discussed in Note 14(h) to our consolidated financial statements, the
Dutch parliament has adopted legislation allocating to the Dutch generation
sector, including REPGB, financial responsibility for certain stranded costs and
other liabilities incurred by NEA prior to the deregulation of the Dutch
wholesale market. These obligations include NEA's obligations under an
out-of-market gas supply contract and three out-of-market electricity contracts.
REPGB's allocated share of these liabilities is 22.5%. As a result, we recorded
a net stranded cost liability of $369 million and a related deferred tax asset
of $127 million at December 31, 2001 for our statutorily allocated share of
these gas supply and electricity contracts. We believe that the costs incurred
by REPGB subsequent to the tax holiday ending in 2001 related to these contracts
will be deductible for Dutch tax purposes. However, due to uncertainties related
to the deductibility of these costs, we have recorded an offsetting liability in
other liabilities in our consolidated financial statements of $127 million as of
December 31, 2001.

64

2000 COMPARED TO 1999

Net Income. We reported consolidated net income, before the extraordinary
gain of $7 million, of $440 million for 2000 compared to $1.7 billion, before an
extraordinary loss of $183 million, in 1999. The extraordinary gain in 2000
related to the retirement of certain debt obligations of our REPGB subsidiary.
The extraordinary loss in 1999 related to an accounting impairment of certain
generation related regulatory assets of our Electric Operations business
segment. The 2000 results included the following unusual items:

- an aggregate after-tax, non-cash accounting loss of $67 million on our
indexed debt securities and our related AOL TW investment;

- an after-tax loss of $172 million from operations of our Latin America
business segment; and

- an after-tax loss of $159 million on the anticipated disposal of our
Latin America business segment.

The 1999 results included the following unusual items:

- an aggregate after-tax, non-cash accounting gain of $1.2 billion on our
indexed debt securities and our AOL TW investment as discussed above; and

- an after-tax loss of $9 million from operations of our Latin America
business segment.

In 1999, the Texas legislature adopted the Texas Electric Restructuring
Law. In connection with the implementation of the Texas Electric Restructuring
Law, we evaluated the recovery of our generation related regulatory assets and
liabilities. We determined that a pre-tax accounting loss of $282 million
existed because we believed only the economic value of our generation related
regulatory assets (as defined by the Texas Electric Restructuring Law) would be
recovered. Therefore, we recorded a $183 million after-tax extraordinary loss in
the fourth quarter of 1999. For information regarding the $183 million
extraordinary loss, please read "-- Certain Factors Affecting Our Future
Earnings -- Factors Affecting the Results of Our Electric
Operations -- Generation" and Note 4(a) to our consolidated financial
statements.

In the fourth quarter of 2000, the Latin America business segment sold its
investments in El Salvador, Colombia and Brazil for an aggregate $790 million in
after-tax proceeds. We recorded a $242 million after-tax loss in connection with
the sale of these investments.

In the fourth quarter of 2000, we recorded an additional pre-tax impairment
related to our remaining Latin America investments in Argentina of $172 million,
based on the expected net realizable value of the businesses upon their
disposition.

Operating Income. For an explanation of changes in our operating income
for 2000 as compared to 1999, please read the discussion below of operating
income (loss) by business segment.

Other Income/Expense. We incurred net other expense of $1.1 billion for
2000 compared to net other income of $1.3 billion for 1999. The decrease in
other income/expense of $2.4 billion in 2000 as compared to 1999 resulted
primarily from the following:

- a net aggregate pre-tax, non-cash accounting gain in 1999 of $1.8 billion
on our indexed debt securities and our AOL TW investment;

- a $322 million pre-tax increase in other expense in 2000 related to
losses of our Latin America operations;

- a $214 million increase in net interest expense in 2000 compared to 1999
primarily due to increased levels of short-term borrowings. These
increases were associated in part with borrowings to fund the purchase
obligation for the acquisition of REPGB in the fourth quarter of 1999 and
the first quarter of 2000, the acquisition of the REMA entities in the
second quarter of 2000, other acquisitions, capital expenditures and
increased margin deposits on energy trading activities; and

- an impairment loss of $27 million on marketable equity securities
classified as "available-for-sale" in 2000, distributions of $9 million
from venture capital investments in marketable securities classified as
"trading" in 1999 and a decline of $19 million in dividend income from
our AOL TW investment.
65

These increases in net other expense were partially offset by the
following:

- an increase in interest income of $57 million primarily related to income
tax refunds received in 2000 and margin deposits on energy trading
activities;

- a pre-tax gain of $18 million in 2000 on the sale of our interest in one
of our development stage electric generation projects; and

- a $44 million increase in our Wholesale Energy business segment's equity
earnings in unconsolidated subsidiaries in 2000 as compared to 1999.

Income Tax Expense. The effective tax rate for 1999 and 2000 was 35.1% and
42.0%, respectively. The increase in the effective tax rate in 2000 compared to
1999 was primarily due to book/tax basis differences realized on the sale of our
Latin American investments, including the write-off of deferred tax assets
related to the Latin America business segment, partially offset by the increased
earnings of REPGB. Under Dutch corporate income tax laws, the earnings of REPGB
were subject to a zero percent Dutch corporate income tax rate as a result of
the Dutch tax holiday in effect for the Dutch electricity industry.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (loss) for each of our
business segments for 1999, 2000 and 2001 (in millions). Some amounts from the
previous years have been reclassified to conform to the 2001 presentation of the
financial statements. These reclassifications do not affect consolidated
earnings.

OPERATING INCOME (LOSS) BY BUSINESS SEGMENT

ELECTRIC OPERATIONS

For a discussion of the factors that may affect the future results of
operations of our Electric Operations business segment, please read "-- Certain
Factors Affecting Our Future Earnings -- Factors Affecting the Results of Our
Electric Operations."

66

The following table provides summary data regarding the results of
operations of our Electric Operations business segment for 1999, 2000 and 2001
(in millions, except electric sales data):

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

(1) Includes miscellaneous revenues, non-reconcilable fuel revenues and
purchased power-related revenues.

(2) Includes revenues collected through a fixed fuel factor and surcharges net
of adjustments for over/under recovery of fuel.

2001 Compared to 2000. Our Electric Operations business segment's
operating income for 2001 decreased $139 million compared to 2000. The decrease
was primarily due to milder weather, decreased customer demand, increased
contract services and benefit expenses and a charge recorded in the fourth
quarter of 2001 resulting from the early termination of an accounts receivable
factoring agreement. The decrease was also due to the implementation of the
pilot program for Texas deregulation in August 2001, reduced rates for certain
governmental agencies and increased administrative expenses related to the
separation of our regulated and unregulated businesses. These decreases were
partially offset by decreased amortization expense and customer growth.

Base revenues decreased $119 million in 2001 due to decreased customer
demand as a result of the effect of milder weather compared to 2000 and
decreased customer usage on a weather normalized basis. The weather impact
represented approximately $84 million of the decrease in base revenues in 2001
as compared to 2000.

The 6% increase in reconcilable fuel revenue in 2001 resulted primarily
from increased fuel costs as discussed below. The Texas Utility Commission
provides for recovery of certain fuel and purchased power costs through a fixed
fuel factor included in electric rates. Revenues collected through this factor
are adjusted monthly to equal expenses; therefore, these revenues and expenses
have no effect on earnings unless fuel costs are subsequently determined not to
be recoverable. The adjusted over/under recovery of fuel costs is recorded in
our Consolidated Balance Sheets as regulatory liabilities or regulatory assets,
respectively. For information regarding the effect of the Texas Electric
Restructuring Law on fuel recovery beginning in 2002, please read

67

"Business -- Regulation -- State and Local Regulations -- Texas -- Electric
Operations -- The Texas Electric Restructuring Law" in Item 1 of this Form 10-K
and Note 4(c) to our consolidated financial statements for information regarding
Reliant Energy HL&P fuel filings.

Fuel and purchased power expenses in 2001 increased by $126 million, or 5%,
over 2000 expenses. This increase is due to increased purchased power volume
related to the load balancing requirements associated with the Electric
Reliability Council of Texas, Inc. (ERCOT) adapting to a single control area,
with a slightly higher cost for purchased power ($44.26 and $44.42 per MWh in
2000 and 2001, respectively). The purchased power increase was partially offset
by the decline in the volume of natural gas used at a slightly higher rate
($3.98 and $4.23 per MMBtu in 2000 and 2001, respectively).

Operation, maintenance and other operating expenses increased $78 million
in 2001 compared to 2000 primarily due to the following items:

- a $32 million increase in benefits expense primarily driven by medical
and pension costs;

- a $16 million increase in contract services due to additional major and
solid fuel outages at our generating plants in 2001 compared to shorter,
routine outages in 2000;

- an $11 million increase in administrative expenses related to the
separation of our regulated and unregulated businesses; and

- a $20 million charge recorded in the fourth quarter of 2001 resulting
from the early termination of an accounts receivable factoring agreement.

Depreciation and amortization expense decreased $54 million primarily due
to a decrease in amortization of the book impairment regulatory asset recorded
in June 1999 and decreased amortization expense due to regulatory assets related
to cancelled projects being fully amortized in June 2000, partially offset by
accelerated amortization of certain regulatory assets related to energy
conservation management as required by the Texas Utility Commission. In June
1998, the Texas Utility Commission issued an order approving a transition to
competition plan (Transition Plan) filed by Reliant Energy HL&P in December
1997. In order to reduce Reliant Energy HL&P's exposure to potential stranded
costs related to generation assets, the Transition Plan permitted the
redirection of depreciation expense to generation assets that Reliant Energy
HL&P otherwise would apply to transmission, distribution and general plant
assets. In addition, the Transition Plan provided that all earnings above a
stated overall annual rate of return on invested capital be used to recover
Reliant Energy HL&P's investment in generation assets. Reliant Energy HL&P
implemented the Transition Plan effective January 1, 1998. For information
regarding items that affect depreciation and amortization expense of our
Electric Operations business segment pursuant to the Texas Electric
Restructuring Law and the Transition Plan, see Notes 2(g) and 4(a) to our
consolidated financial statements, which are incorporated herein by reference.

2000 Compared to 1999. Our Electric Operations business segment's
operating income for 2000 increased $249 million compared to 1999. The increase
was primarily due to decreased depreciation and amortization expense, strong
customer growth and warmer weather, partially offset by increased operation and
maintenance expenses and other taxes.

Base revenues increased $173 million in 2000 due to continued customer
growth and increased demand from the effects of weather as compared to 1999.
Growth in usage per customer and number of customers contributed $132 million of
the increase in base revenues in 2000.

Fuel and purchased power expenses in 2000 increased by $853 million, or
55%, over 1999 expenses. The increase is primarily the result of higher
reconcilable costs for natural gas ($2.47 and $3.98 per MMBtu in 1999 and 2000,
respectively), higher costs for purchased power ($26.46 and $44.26 per MWh in
1999 and 2000, respectively) and higher sales due to customer growth and
increased demand, which led to increased production.

68

Operation, maintenance and other operating expenses increased $69 million
in 2000 compared to 1999 primarily due to the following items:

- a $25 million increase due to transmission expenses resulting from the
wholesale rates established by the Texas Utility Commission;

- a $22 million increase in state franchise taxes and municipal franchise
fees due to increased earnings and cash receipts;

- a $24 million assessment for the 1999 and 2000 System Benefit Fund, which
was established by the Texas Electric Restructuring Law to insure that
public schools were not impacted by the loss of taxes related to the
lower property values of generation assets, substantially offset by a
decrease in property taxes of $21 million; and

- a $22 million increase in other operation and maintenance expense.

Depreciation and amortization expense decreased $160 million primarily due
to our discontinuance of recording additional depreciation and redirected
depreciation pursuant to the Transition Plan, the extension of electric
generation assets' depreciable lives, fully amortizing some investments in
lignite reserves associated with a cancelled generation station and ceasing
amortization of regulatory assets pursuant to the Texas Electric Restructuring
Law.

NATURAL GAS DISTRIBUTION

Our Natural Gas Distribution business segment's operations consist of
intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers in Arkansas, Louisiana,
Minnesota, Mississippi, Oklahoma and Texas and some non-rate regulated retail
marketing of natural gas.

For a discussion of the factors that may affect future results of
operations of our Natural Gas Distribution business segment, please read
"-- Certain Factors Affecting Our Future Earnings -- Factors Affecting the
Results of RERC's Operations -- Natural Gas Distribution."

The following table provides summary data regarding the results of
operations of our Natural Gas Distribution business segment for 1999, 2000 and
2001 (in millions, except throughput data):

69

2001 Compared to 2000. Our Natural Gas Distribution business segment's
operating income increased $12 million in 2001 from 2000. Operating margins
(revenues less fuel costs) in 2001 were $14 million higher than in 2000
primarily due to increased volumes in the first quarter of 2001 due to the
effect of colder weather.

Operation and maintenance expenses decreased in 2001 as compared to 2000
primarily due to expenses incurred in 2000 in connection with exiting certain
non-rate regulated natural gas business activities outside our established
market areas offset by the following items:

- increased bad debt expense due to higher natural gas prices in the first
quarter of 2001;

- higher employee benefit cost; and

- changes in estimates of unbilled revenues and recoverability of deferred
gas accounts and other items.

Generally, our utility operations of the Natural Gas Distribution business
segment are allowed to flow through the cost of natural gas to our customers
through purchased gas adjustment provisions in rates pursuant to regulations of
the states in which they operate. Differences between actual gas costs and the
amount collected from customers are deferred on the balance sheet so that there
is no impact on operating income.

2000 Compared to 1999. Our Natural Gas Distribution business segment's
operating income decreased $40 million in 2000 from 1999. Increases in revenues
and natural gas expenses in 2000 compared to 1999 were due primarily to the
increase in the price of natural gas. In addition, operating revenues increased
$6 million related to gains from the effect of a financial hedge of our Natural
Gas Distribution business segment's earnings against unseasonably warm weather
during peak heating months. Slightly increased operating margins (revenues less
fuel costs) in 2000 were offset by higher operating expenses and higher
depreciation expense in 2000.

Operation and maintenance expenses increased in 2000 primarily due to the
following items:

- costs incurred in connection with some non-rate regulated retail natural
gas business activities outside our established market areas, which we
exited in the fourth quarter of 2000;

- additional provisions against receivable balances resulting from the
implementation of a new billing system for Arkla; and

- increased employee benefit costs.

PIPELINES AND GATHERING

Our Pipelines and Gathering business segment operates two interstate
natural gas pipelines, as well as provides gathering and pipeline services.

For a discussion of the factors that may affect future results of
operations of our Pipelines and Gathering business segment, please read
"-- Certain Factors Affecting Our Future Earnings -- Factors Affecting the
Results of RERC's Operations -- Pipelines and Gathering."

70

The following table provides summary data regarding the results of
operations of our Pipelines and Gathering business segment for 1999, 2000 and
2001 (in millions, except throughput data):

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

(1) Elimination of volumes both transported and sold.

2001 Compared to 2000. Our Pipelines and Gathering business segment's
operating income for 2001 was consistent with 2000 results. Increased gas
gathering and processing revenues were offset by increased operating expenses
associated with a pipeline rate case which began in 2001, higher employee
benefit costs and increased other operating expenses.

2000 Compared to 1999. Our Pipelines and Gathering business segment's
operating income for 2000 increased $6 million, primarily due to increased gas
gathering and processing revenues. Natural gas expense increased $35 million in
2000, primarily due to the increased cost of natural gas per unit. Operation and
maintenance expense increased $9 million in 2000, primarily due to the
implementation of various projects throughout the year.

WHOLESALE ENERGY

Our Wholesale Energy business segment, which is conducted through Reliant
Resources, includes our non-rate regulated power generation operations in the
United States and our wholesale energy trading, marketing, origination and risk
management operations in North America.

As of December 31, 2001, we owned or leased electric power generation
facilities with an aggregate net generating capacity of 11,109 megawatts (MW) in
the United States. We acquired our first power generation facility in April
1998, and have increased our aggregate net generating capacity since that time
principally through acquisitions, as well as contractual agreements and the
development of new generating projects. As of December 31, 2001, we had 3,587 MW
of additional net generating capacity under construction, including facilities
having 2,120 MW that are being constructed under a construction agency agreement
by off-balance sheet special purpose entities. 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. On May 12, 2000,
one of our subsidiaries purchased entities owning electric power generating
assets and development sites located in Pennsylvania, New Jersey and Maryland
having an aggregate net generating capacity of approximately 4,262 MW. For
additional information regarding this acquisition of our Mid-Atlantic generating
assets completed in May 2000

71

by Wholesale Energy, including the accounting treatment of this acquisition,
please read Note 3(a) to our consolidated financial statements.

On February 19, 2002, we acquired all of the outstanding shares of common
stock of Orion Power Holdings, Inc. (Orion Power) for $26.80 per share in cash
for an aggregate purchase price of $2.9 billion. As of February 19, 2002, Orion
Power's debt obligations were $2.4 billion ($2.1 billion net of cash acquired,
some of which is restricted pursuant to debt covenants). Orion Power is an
independent electric power generating company that was formed in March 1998 to
acquire, develop, own and operate power-generating facilities in certain
deregulated wholesale markets in North America. As of February 28, 2002, Orion
Power had 81 power plants in operation with a total generating capacity of 5,644
MW and an additional 804 MW under construction or in various stages of
development.

For a discussion of the factors that may affect the future results of
operations of Wholesale Energy, please read "-- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Wholesale Energy
Operations."

The following table provides summary data regarding the results of
operations of our Wholesale Energy business segment for 1999, 2000 and 2001 (in
millions, except operations data).

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

(1) Million megawatt hours.

(2) Billion cubic feet.

2001 Compared to 2000. Wholesale Energy's operating income increased by
$420 million in 2001 compared to 2000. The results for 2001 include a $68
million provision against net receivables, trading and marketing assets and
non-trading derivative balances related to Enron, and a $29 million provision
and a $12 million net write-off against receivable balances related to energy
sales in California. A $39 million provision against receivable balances related
to energy sales in California was recorded in 2000.

The increase in operating income was primarily due to increased gross
margins. Gross margins for Wholesale Energy increased by $606 million primarily
due to increased volumes on power sales from our generation facilities,
increased volumes from our trading and marketing activities and the addition of
our Mid-Atlantic assets and strong commercial and operational performance in
other regions. Margins on power sales from our generation facilities, excluding
a $63 million provision related to Enron, increased by $429 million in the West
region (Arizona, California and portions of New Mexico and Nevada), $85 million
in the Mid-Atlantic region, and $32 million in other regions in 2001 compared to
2000. Favorable market conditions in the first six months of 2001 in the West
region resulting from a combination of factors, including reduction in

72

available hydroelectric generation resources, increased demand and decreased
electric imports, positively impacted Wholesale Energy's operating margins.
These favorable market conditions did not exist in the second half of 2001, and
we do not expect them to return in 2002. Trading and marketing gross margins,
excluding a $5 million provision related to Enron, increased $113 million from
$197 million in 2000 to $310 million in 2001 primarily as a result of increased
natural gas trading volumes. These results were partially offset by the $68
million provision related to Enron as discussed above, higher operation and
maintenance expenses from facilities in the Mid-Atlantic region acquired in
2000, higher general and administrative expenses and increased depreciation
expense.

The following table provides further summary data regarding gross margin by
commodity of Wholesale Energy for 2000 and 2001.

Wholesale Energy's revenues increased by $16.0 billion (84%) in 2001
compared to 2000. The increased revenues were primarily due to increased volumes
for natural gas (approximately $5.4 billion) and power sales (approximately $8.6
billion) and to a lesser extent increased prices for power sales compared to
2000, which increased approximately $2.5 billion. Wholesale Energy's fuel and
cost of gas sold and purchased power increased by $15.4 billion in 2001 compared
to 2000, largely due to increased volumes for natural gas and power sales and to
a lesser extent increases in power generation plant output, which increased
approximately 33% compared to 2000, and increased prices for power purchases.

Operation and maintenance expenses for Wholesale Energy increased $162
million in 2001 compared to the same period in 2000, primarily due to costs
associated with the operation and maintenance of generating plants acquired in
the Mid-Atlantic region of $53 million and higher lease expense of $38 million
associated with the Mid-Atlantic generation facilities' sale-leaseback
transactions that were entered into in August 2000. The higher lease expense
associated with the Mid-Atlantic generating facilities was offset by lower
interest expense in the consolidated results of operations in 2001 compared to
2000. Other operating expenses increased $14 million in 2001 compared to 2000,
primarily due to higher administrative costs to support growing wholesale
commercial activities of $69 million and higher legal and regulatory expenses
related to the West region of $25 million, partially offset by decreased
development expenses of $12 million. Depreciation and amortization expense
increased by $10 million in 2001 compared to 2000 primarily as a result of
higher expense related to the depreciation of our Mid-Atlantic plants, which
were acquired in May 2000, and other generating plants placed into service
during 2001, partially offset by a decrease in amortization of our air emissions
regulatory allowances of $8 million.

2000 Compared to 1999. Wholesale Energy's operating income increased $452
million for 2000 compared to 1999. The increase was primarily due to increased
energy sales volumes, higher prices for energy and ancillary services, and
improved operating results from trading and marketing activities, as well as

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expansion of our generation operations into regions other than the Western
United States, including the Mid-Atlantic United States, Florida and Texas.

Wholesale Energy's operating revenues increased $11.3 billion (143%) for
2000 compared to 1999. The increase was primarily due to an increase in prices
and volumes for both gas and power sales in 2000 compared to 1999. Wholesale
Energy's fuel and cost of gas sold and purchased power costs increased $6.4
billion and $4.1 billion, respectively, in 2000 compared to 1999. The increase
in fuel and cost of gas sold was primarily due to an increase in gas volumes
purchased, and to increases in plant output and in the price of gas. The
increase in purchased power cost was primarily due to a higher average cost of
power and higher power volumes purchased. Operation and maintenance expenses and
other operating expenses increased $248 million and $7 million, respectively, in
2000 compared to 1999. These increases were primarily due to costs associated
with the maintenance of facilities acquired or placed into commercial operation
during the period, lease expense associated with the Mid-Atlantic generating
facilities sale-leaseback transactions, higher run rates at existing facilities,
increased costs associated with developing new power generation projects and
higher staffing levels to support increased sales and expanded trading and
marketing efforts. Depreciation and amortization expense for 2000 increased $87
million as compared to 1999, primarily as a result of our acquisition of the
Mid-Atlantic generating facilities and other generating facilities in 2000.

EUROPEAN ENERGY

Our European Energy business segment, which is conducted through Reliant
Resources, includes the operations of REPGB and its subsidiaries and our
European trading and power origination operations. We created European Energy in
the fourth quarter of 1999 with the acquisition of REPGB and the formation of
our European trading and power origination operations. European Energy generates
and sells power from its generation facilities in the Netherlands and
participates in the emerging wholesale energy trading markets in Northwest
Europe.

Effective October 7, 1999, we acquired REPGB, a Dutch generation company,
for a net purchase price of $1.9 billion. From October 1, 1999, our operating
results include the results of operations of REPGB. The impact of REPGB's
results of operations from October 1 through October 7, 1999 was immaterial to
our consolidated results of operations. For additional information regarding the
acquisition of REPGB, please read Note 3(b) to our consolidated financial
statements.

In connection with our evaluation of the acquisition of REPGB, we also
began to assess and formulate an employee severance plan to be undertaken as
soon as reasonably possible post-acquisition. The intent of this plan was to
make REPGB competitive in the Dutch electricity market when it became
deregulated on January 1, 2001. This plan was finalized, approved and completed
in September 2000. At that time, we recorded the severance liability as a
purchase price adjustment in the amount of $19 million. During 2001, we utilized
$8 million of the reserve. As of December 31, 2001, the remaining severance
liability is $11 million.

REPGB and the other major Dutch generators historically operated under a
protocol agreement, pursuant to which the generators provided capacity and
energy to distributors in exchange for regulated production payments, plus
compensation for actual fuel expended in the production of electricity over the
period from 1997 through 2000. Effective January 1, 2001, these agreements
expired in all material respects. Beginning January 1, 2001, the Dutch wholesale
electric market was opened to competition. Consistent with our expectations at
the time that we made the acquisition, REPGB experienced a significant decline
in electric margins in 2001 attributable to the deregulation of the wholesale
electric market.

In 2001, we evaluated strategic alternatives for our European Energy
business segment, including a possible sale. We completed our evaluation, and
determined that given current market conditions and prices, it is not advisable
to sell our European Energy operations. Consequently, we decided to continue to
own and operate our European Energy business segment and to expand our trading
and origination activities in Northwest Europe. During December 2001, we
evaluated our European Energy business segment's long-lived assets and goodwill
for impairment. 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. As of December 31, 2001, pursuant
to SFAS No. 121, "Accounting for the Impairment of Long-Lived Assets
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and for Long-Lived Assets to Be Disposed Of," (SFAS No. 121), no impairment has
been indicated. For assessing of impairment in 2002, under SFAS No. 142,
"Goodwill and Other Intangible Assets," (SFAS No. 142), please read "-- New
Accounting Pronouncements,".

For additional information regarding these and other factors that may
affect the future results of operations of European Energy, please read
"-- Certain Factors Affecting Our Future Earnings -- Factors Affecting the
Results of Our European Energy Operations."

For information regarding foreign currency matters, please read Note 5(b)
to our consolidated financial statements and "-- Quantitative and Qualitative
Disclosures about Market Risk" in Item 7A of this Form 10-K.

The following table provides summary data for the results of operations of
our European Energy business segment for 1999, 2000 and 2001 (in millions,
except operations data).

2001 Compared to 2000. European Energy's operating income decreased by $33
million for 2001 compared to 2000. This decrease was primarily due to the
anticipated decline in electric power generation gross margins (revenues less
fuel and purchased power), as the Dutch electric market was completely opened to
wholesale competition on January 1, 2001. Further contributing to the decline in
operating margins were a number of unscheduled outages at our electric
generating facilities. We estimate that these unplanned outages resulted in
losses of $11 million. Increased margins from ancillary services of $33 million
and district heating sales of $9 million in 2001 compared to 2000 and efficiency
and energy payments from NEA totaling $30 million in 2001 partially offset this
decline. Trading gross margins decreased $12 million from a $3 million gross
margin in 2000 to a $9 million gross margin loss in 2001 primarily as a result
of a $17 million provision against receivable and trading and marketing asset
balances related to Enron. Excluding this provision, trading gross margins
increased primarily due to a significant increase in power trading volumes,
trading origination transactions and increased volatility in the Dutch and
German markets. In addition, the decrease in operating income was partially
offset by a $37 million net gain related to the settlement of an indemnity
agreement with the former shareholders of REPGB in the fourth quarter of 2001,
as discussed below.

European Energy's operating revenues increased by $612 million for 2001
compared to 2000. The increase was primarily due to increased trading revenues
in the Dutch, German and Austrian power markets of $544 million and, to a lesser
extent, increased volumes of electric generation sales, which increased 41%,
partially offset by a 29% decrease in prices for power sales. Fuel and purchased
power costs increased $695 million for 2001 compared to 2000 primarily due to
increased purchased power for trading activities, and to a lesser extent
increased cost of natural gas due to higher gas prices, increased output from
our generating facilities and increased transmission and grid charges as a
result of a change in the tariff structure.

Operation and maintenance expenses decreased by $50 million for 2001
compared to 2000. These expenses declined primarily due to (a) the net gain of
$37 million recorded in operation expenses related to

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the settlement of the former shareholders' indemnity obligation, as discussed
below, (b) provisions in 2000 against environmental tax subsidies receivable
from Dutch distribution companies, REPGB's former shareholders and the Dutch
government, coupled with the reversal of such accrual in 2001 due to the
indemnity obligation settlement with REPGB's former shareholders and (c)
decreases in provisions for environmental liabilities, employee benefits and
other accruals totaling $6 million. This decrease was partially offset by an
increase in personnel and operating expenses related to our trading operations,
facilities costs and systems upgrades.

In December 2001, REPGB and its former shareholders entered into a
settlement agreement resolving the former shareholders' stranded cost indemnity
obligations under the purchase agreement of REPGB. During the fourth quarter of
2001, we recognized a net settlement gain of $37 million in operation expenses
for the difference between the sum of (a) the cash settlement consideration of
$202 million, and REPGB's rights to claim future distributions of our NEA
investment of an estimated $248 million and (b) the amount recorded as "stranded
cost indemnity receivable" related to the stranded cost gas and electric
commitments of $369 million and claims receivable related to stranded costs
incurred in 2001 of $44 million both previously recorded in our consolidated
balance sheet. Future changes in the valuation of the stranded cost import
contracts that remain an obligation of REPGB will be recorded as adjustments to
our consolidated statement of income, thus introducing potential earnings
volatility. For additional information regarding the settlement, please read
Note 14(h) to our consolidated financial statements.

2000 Compared to 1999. For the year ended December 31, 2000, European
Energy reported operating income of $89 million. European Energy reported
operating income of $32 million for the three months ended December 31, 1999.

RETAIL ENERGY

Our Retail Energy business segment, which is conducted through Reliant
Resources, provides energy products and services to end-use customers, ranging
from residential and small commercial customers to large commercial,
institutional and industrial customers. In addition, Retail Energy provided
billing, customer service and credit and collection services to the Electric
Operations business segment and remittance services to the Electric Operations
business segment and two of the divisions of the Natural Gas Distribution
business segments. The service agreement governing these services terminated on
December 31, 2001. Retail Energy charged the regulated electric and natural gas
utilities for these services at cost. Reliant Resources acquired approximately
1.7 million electric retail customers in the Houston metropolitan area when the
Texas market opened to competition in January 2002. During the first half of
2002, the Texas electric retail market will be largely focused on the extensive
efforts necessary to transition customers from the utilities to the affiliated
retail electric providers. Reliant Resources expects to expand its marketing
efforts for small residential and commercial customers (i.e.,customers with an
aggregate peak demand at or below one MW) to other areas in Texas outside of the
Houston territory during the second quarter of 2002. Reliant Resources signed
246 contracts with large commercial, industrial and institutional (e.g.,
hospitals, universities, school systems and government agencies) customers
(i.e., customers with an aggregate peak demand of more than one MW) during 2001,
with an aggregate peak electric energy demand of approximately 3,700 MW and
serving approximately 12,000 meter locations. These customers are both in the
Houston metropolitan area as well as outside of the Houston territory. Reliant
Resources' marketing efforts for large commercial, industrial and institutional
customers are continuing throughout the competitive region of the ERCOT.

For a discussion of the factors that may affect the future results of
operations of Retail Energy, please read "-- Certain Factors Affecting Our
Future Earnings -- Factors Affecting the Results of Our Retail Energy
Operations."

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The following table provides summary data regarding the results of
operations of our Retail Energy business segment for 1999, 2000 and 2001 (in
millions).

2001 Compared to 2000. Our Retail Energy business segment's operating loss
decreased by $57 million for 2001 compared to 2000. The operating loss reduction
was primarily due to increased sales of energy and energy services to
commercial, industrial and institutional customers, partially offset by (a)
increased personnel costs and employee related costs and (b) increased costs
associated with developing an infrastructure necessary to prepare for
competition in the retail electric market in Texas. Contracted energy sales to
large commercial, industrial and institutional customers are accounted for under
the mark-to-market method of accounting. These energy contracts are recorded at
fair value in revenue upon contract execution. The net changes in their market
values are recognized in the income statement in revenue in the period of the
change. During 2001, our Retail Energy business segment recognized $74 million
of mark-to-market revenues related to commercial, industrial and institutional
energy contracts of which $73 million relates to energy that will be supplied in
future periods ranging from one to three years.

Operating revenues increased by $147 million for 2001 compared to 2000
largely due to increased revenues from sales of energy and energy services to
large commercial, industrial and institutional customers, as well as increased
revenues for the services provided to the Electric Operations and Natural Gas
Distribution business segments. Operations and maintenance costs increased by
$83 million in 2001 as compared to 2000, primarily due to increased personnel
and employee-related costs and costs related to building an infrastructure
necessary to prepare for competition in the retail electric market in Texas
totaling $35 million, increased costs incurred in performing services for the
Electric Operations and Natural Gas Distribution business segments of $31
million and increased purchased power expenses of $27 million in 2001 primarily
due to a $22 million increase in wholesale electricity purchases and a $5
million increase in the cost of transmission service both related to the Texas
retail pilot program during the last half of 2001. Our Wholesale Energy business
segment purchases and manages Retail Energy's wholesale purchased power
requirements needed to fulfill its retail energy commitments. The Wholesale
Energy business segment charges Retail Energy for the purchased power at its
actual cost and charges an administrative fee for such service.

2000 Compared to 1999. Retail Energy's operating loss increased $56
million for 2000 compared to 1999. Operating revenues increased $41 million
(178%) for 2000 as compared to 1999. This increase was primarily the result of
the inclusion of revenues generated by the operations acquired during November
1999, additional revenue generated by an increase in the number of new energy
service contracts. For 2000 as compared to 1999, operations and maintenance
costs increased $93 million primarily due to costs associated with servicing
contracts acquired during 1999 as well as new contracts entered into in 2000 and
costs related to building an infrastructure necessary to prepare for competition
in the retail electric market in Texas. In addition, during the fourth quarter
of 2000, Reliant Resources incurred an obligation to pay $12 million in order to
secure the naming rights to a Houston sports complex and for the initial
advertising of which $10 million was expensed in 2000. Starting in 2002, when
the new stadium in the sports complex is operational, Reliant Resources will pay
$10 million each year through 2032 for annual advertising associated with the
sports complex.

77

LATIN AMERICA

Effective December 1, 2000 (Measurement Date), Reliant Energy's board of
directors approved a plan to dispose of our Latin America business segment
through sales of its assets. Accordingly, in our 2000 consolidated financial
statements, we reported the results of our Latin America business segment as
discontinued operations in accordance with APB Opinion No. 30 for each of the
three years in the period ended December 31, 2000.

In the fourth quarter of 2000, the Latin America business segment sold its
investments in El Salvador, Colombia and Brazil for an aggregate $790 million in
after-tax proceeds. We recorded a $242 million after-tax loss in connection with
the sale of these investments. Through our subsidiaries, we continue to operate
investments in Argentina which include a 100% interest in a 160 MW cogeneration
project, Argener, and a 90% interest in a utility, EDESE (collectively, the
Argentine Investments).

In the fourth quarter of 2000 and in the first quarter of 2001, we recorded
after-tax impairments related to the Argentine Investments of $89 million and $7
million, respectively, based on the expected net realizable value of the
businesses upon their disposition.

On December 20, 2001, negotiations for the sale of the Argentine
Investments were terminated as a result of recent adverse economic developments
in Argentina. We will continue to evaluate options related to the future
disposition of these assets.

Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Statements of Consolidated Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by EITF 90-6.

During December 2001, we concluded that there was an impairment related to
the remaining assets in this business segment. This evaluation resulted in an
after-tax impairment charge of $43 million, representing the excess of book
value over estimated net realizable value. As of December 31, 2001, we had $8
million of Latin America net assets held for sale recorded in our Consolidated
Balance Sheets. The charge was included as a component of operating income with
respect to consolidated subsidiaries and other income with respect to equity
investments in unconsolidated subsidiaries. The impairment was primarily related
to recent adverse economic developments in Argentina. We do not intend to invest
additional resources in these operations.

OTHER OPERATIONS

Our Other Operations business segment includes the operations of our
Communications and venture capital businesses, non-operating investments,
certain real estate holdings and unallocated corporate costs. For additional
information about our exiting of the Communications business, please read Note
20 to our consolidated financial statements. After Restructuring and
Distribution, our Other Operations business segment will consist primarily of
Reliant Energy Thermal Systems, Inc., Reliant Energy Power Systems, Inc., office
buildings and other real estate used in our business operations and unallocated
corporate costs.

2001 Compared to 2000. Other Operations' operating loss increased by $130
million to $232 million in 2001 compared to $102 million in 2000. During 2001,
we incurred a pre-tax non-cash charge of $101 million relating to the redesign
of certain of our benefit plans in anticipation of separation of our regulated
and unregulated businesses. In connection with our decision to exit the
Communications business, we determined that the goodwill associated with the
Communications business was impaired. We recorded $54 million of pre-tax
disposal charges in 2001, including the impairment of goodwill of $19 million
and fixed assets of $22 million, and severance accruals, lease cancellation
costs and other incremental costs associated with exiting the Communications
business, totaling $13 million. The goodwill and fixed assets impairments are
included in depreciation and amortization expense. These items were partially
offset by decreased corporate operating expenses of $12 million and decreased
charitable contributions to a charitable foundation of $15 million of equity
securities classified as "trading." For additional information about the benefit
charge noted above, please read Note 12 to our consolidated financial
statements.

78

2000 Compared to 1999. Other Operations had an operating loss of $102
million for 2000 compared to a $52 million operating loss for 1999. This
increased loss was primarily due to increased Communications business expenses
and a $15 million non-cash charitable contribution of equity securities, as
discussed above.

TRADING AND MARKETING OPERATIONS

Through Reliant Resources, we trade and market power, natural gas and other
energy-related commodities and provide related risk management services to our
customers. We apply mark-to-market accounting for all of our non-asset based
energy trading, marketing, power origination and risk management services
activities. For information regarding mark-to-market accounting, please read
Notes 2(d) and 5 to our consolidated financial statements. These trading and
marketing activities consist of:

- the domestic energy trading, marketing, power origination and risk
management services operations of our Wholesale Energy business segment;

- the European energy trading and power origination operations of our
European Energy business segment; and

- the large contracted commercial, industrial and institutional retail
electricity business of our Retail Energy business segment.

Our domestic and European energy trading and marketing operations enter
into derivative transactions as a means of optimization of our current power
generation asset position and to take a market position. For additional
information regarding the types of contracts and activities of our trading and
marketing operations, please read "Quantitative and Qualitative Disclosures
About Market Risk" in Item 7A of this Form 10-K and Note 5 to our consolidated
financial statements.

Below is a detail of our net trading and marketing assets (liabilities) by
business segment:

Our trading and marketing and risk management services margins realized and
unrealized are as follows:

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Below is an analysis of our net trading and marketing assets and
liabilities for 2001 (in millions):

Fair value of contracts outstanding at December 31, 2000.... $ 32
Fair value of new contracts when entered into during the
year...................................................... 119
Contracts realized or settled during the year............... (184)
Changes in fair values attributable to changes in valuation
techniques and assumptions................................ (23)
Changes in fair values attributable to market price and
other market changes...................................... 274
-----
Fair value of contracts outstanding at December 31,
2001................................................... $ 218
=====

During 2001, our Retail Energy business segment entered into contracts with
large commercial, industrial and institutional customers, with a peak demand of
approximately 3,700 MW, ranging from one to three years. These contracts had an
aggregated fair value of $97 million at the contract inception dates. Subsequent
to the inception dates, the fair values of these contracts were adjusted to $74
million due to changes in assumptions used in the valuation models, as described
below. The fair value of these Retail Energy electric supply contracts was
determined by comparing the contractual pricing to the estimated market price
for the retail energy delivery and applying the estimated volumes under the
provisions of these contracts. This calculation involves estimating the
customer's anticipated load volume, and using the forward ERCOT over-the-counter
(OTC) commodity prices, adjusted for the customer's anticipated load pattern.
Load characteristics in the valuation model include: the customer's expected
hourly electricity usage profile, the potential variability in the electricity
usage profile (due to weather or operational uncertainties), and the electricity
usage limits included in the customer's contract. In addition, some estimates
include anticipated delivery costs, such as regulatory and transmission charges,
electric line losses, ERCOT system operator administrative fees and other market
interaction charges, estimated credit risk and administrative costs to serve.
The weighted-average duration of these transactions is approximately one year.

The remaining fair value of new contracts recorded at inception of $22
million primarily relates to Wholesale Energy fixed and variable-priced power
purchases and sales. The fair values of these 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. A
significant portion of the value of these contracts required utilization of
internal models. For the contracts extending beyond December 31, 2001, the
weighted-average duration of these transactions is less than two years.

Below are the maturities of our contracts related to our trading and
marketing assets and liabilities as of December 31, 2001 (in millions):

The "prices actively quoted" category represents our New York Mercantile
Exchange (NYMEX) futures positions in natural gas and crude oil. As of December
31, 2001, the NYMEX had quoted prices for natural gas and crude oil for the next
36 and 30 months, respectively.

The "prices provided by other external sources" category represents our
forward positions in natural gas and power at points for which OTC broker quotes
are available. On average, OTC quotes for natural gas and power extend 60 and 36
months into the future, respectively. We value these positions against
internally developed forward market price curves that are continuously compared
to 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.

80

The "prices based on models and other valuation methods" category contains
(a) the value of our valuation adjustments for liquidity, credit and
administrative costs, (b) the value of options not quoted by an exchange or OTC
broker, (c) the value of 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, and (d) the value of structured
transactions. In certain instances structured transactions can be composed and
modeled by us as simple forwards and options based on prices actively quoted.
Options are typically valued using Black-Scholes option valuation models.
Although the valuation of the simple structures might not be different than the
valuation of contracts in other categories, the effective model price for any
given period is a combination of prices from two or more different instruments
and therefore have been included in this category due to the complex nature of
these transactions.

The fair values in the above table are subject to significant changes based
on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, marketing, power origination and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant parameters impacting the value of our portfolio of contracts include
natural gas and power forward market prices, volatility and credit risk. For the
Retail Energy sales discussed above, significant variables affecting contract
values also include the variability in electricity consumption patterns due to
weather and operational uncertainties (within contract parameters). 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. Please read
"Quantitative and Qualitative Disclosures About Market Risk" in Item 7A of this
Form 10-K for further discussion and measurement of the market exposure in the
trading and marketing businesses and discussion of credit risk management.

For additional information about price volatility and our hedging strategy,
please read "-- Certain Factors Affecting Our Future Earnings -- Factors
Affecting the Results of Our Wholesale Energy Operations -- Price Volatility,"
and "-- Risks Associated with Our Hedging and Risk Management Activities."

For information regarding our counterparty credit risk, including credit
ratings, exposure and collateral held by us, please read, "Quantitative and
Qualitative Disclosures About Market Risk -- Credit Risk" in Item 7A of this
Form 10-K.

For a description of accounting policies for our trading and marketing
activities, please read Notes 2(d) and 5 to our consolidated financial
statements.

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

CERTAIN FACTORS AFFECTING OUR FUTURE EARNINGS

Our past earnings are not necessarily indicative of our future earnings and
results of operations. The magnitude of our future earnings and results of our
operations will depend on numerous factors including:

- state, federal and international legislative and regulatory developments,
including deregulation, re-regulation and restructuring of the electric
utility industry, changes in or application of environmental and other
laws and regulations to which we are subject and changes in or
application of laws or regulations applicable to other aspects of our
business, such as commodities trading and hedging activities;

- the timing of the implementation of our Business Separation Plan;

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

- liquidity concerns in our markets;

81

- industrial, commercial and residential growth in our service territories;

- the degree to which Reliant Resources successfully integrates the
operations and assets of Orion Power into the Wholesale Energy business
segment;

- the determination of the amount of our Texas generation business'
stranded costs and the recovery of these costs;

- the availability of adequate supplies of fuel, water, and associated
transportation necessary to operate our generation facilities;

- our pursuit of potential business strategies, including acquisitions or
dispositions of assets or the development of additional power generation
facilities;

- state, federal and other rate regulations in the United States and in
foreign countries in which we operate or into which we might expand our
operations;

- the timing and extent of changes in interest rates and commodity prices,
particularly natural gas prices;

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

- our ability to cost-effectively finance and refinance;

- the degree to which we successfully integrate the operations and assets
of Orion Power into our Wholesale Energy segment;

- the successful and timely completion of our construction programs, as
well as the successful start-up of completed projects;

- financial market conditions, our access to and cost of capital and the
results of our financing and refinancing efforts, including availability
of funds in the debt/capital markets for merchant generation companies;

- the credit worthiness or bankruptcy or other financial distress of our
trading, marketing and risk management services counterparties;

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

- acts of terrorism or war;

- the availability and price of insurance;

- the reliability of the systems, procedures and other infrastructure
necessary to operate our retail electric business, including the systems
owned and operated by ERCOT;

- political, legal, regulatory and economic conditions and developments in
the United States and in foreign countries in which we operate or into
which we might expand our operations, including the effects of
fluctuations in foreign currency exchange rates;

- the resolution of the refusal by California market participants to pay
our receivables balances due to the recent energy crisis in the West
region; and

- the successful operation of deregulating power markets.

In order to adapt to the increasingly competitive environment in our
industry, we continue to evaluate a wide array of potential business strategies,
including business combinations or acquisitions involving other utility or
non-utility businesses or properties, dispositions of currently owned
businesses, as well as developing new generation projects, products, services
and customer strategies.

82

FACTORS ASSOCIATED WITH THE BUSINESS SEPARATION, RESTRUCTURING AND DISTRIBUTION

As previously discussed, in anticipation of electric deregulation in Texas,
and pursuant to the Texas Electric Restructuring Law, we submitted a business
separation plan in January 2000 to the Texas Utility Commission. Pursuant to the
Business Separation Plan, we are in the process of separating our regulated and
our unregulated businesses into two separate publicly traded companies.

After the Restructuring, we plan, subject to further corporate approvals,
market and other conditions, to complete the separation of our regulated and
unregulated businesses through the Distribution. Our goal is to complete the
Restructuring and subsequent Distribution as quickly as possible after all the
necessary conditions are fulfilled, including receipt of an order from the SEC
granting the required approvals under the Public Utility Holding Company Act of
1935 (1935 Act) and an extension from the IRS for a private letter ruling we
have obtained regarding the tax-free treatment of the Distribution. We currently
expect to complete the Restructuring and Distribution in the summer of 2002. See
"Our Business -- Business Separation" in Item 1 of this Form 10-K.

Regulatory Uncertainty. The Restructuring as currently planned cannot be
completed unless and until the SEC issues an order approving the acquisition by
CenterPoint Energy of Reliant Energy and its subsidiary companies and either
granting CenterPoint Energy an exemption from regulation as a registered public
utility holding company under the 1935 Act or the necessary authority to operate
as a registered holding company. While we believe such an order will be
received, and that both the Restructuring and Distribution will be completed
during the summer of 2002, there can be no assurances that such will be the
case. The Restructuring has been designed to enable us to meet all of the
requirements of the Texas Electric Restructuring Law. We have not formulated an
alternative restructuring plan that could be implemented if the SEC fails or
refuses to grant an exemption for CenterPoint Energy or the authority for
CenterPoint Energy to become a registered holding company on terms consistent
with our business plan. For information about an informal inquiry by the staff
of the Division of Enforcement of the SEC in connection with an earnings
restatement by Reliant Energy that might impact the approval process, please
read "Restatement of Second and Third Quarter 2001 Results of Operations" in
Item 3 of this Form 10-K.

The tax ruling that we received from the IRS expires at the end of April
2002. We are currently seeking an extension of this ruling from the IRS. There
can be no assurance that we will receive the extension quickly or at all. In
this event, the Restructuring and Distribution are not likely to be completed
within our expected time frame, or, perhaps, at all. In addition, our tax ruling
contemplates that the Restructuring will occur prior to the Distribution. If,
due to delay or uncertainty regarding receipt of an order under the 1935 Act, we
decide to make the Distribution before completing the Restructuring, we would
have to seek a new ruling from the IRS that the Distribution would be tax free
to us and to our shareholders. This process could take six months or longer.

A significant delay in completing the Restructuring and the Distribution
may impact planned financings by each of Reliant Energy and Reliant Resources
and make it more difficult and more expensive for us to obtain bank financing.
We cannot predict how any such delay might impact our credit ratings or those of
Reliant Resources.

Adverse Tax Consequences. If we take actions which cause the Distribution
to fail to qualify as a tax-free transaction, we will incur taxable gain equal
to the positive difference between the value of the Reliant Resources shares
distributed and our tax basis in those shares. Current tax law provides that,
depending on the facts and circumstances, the Distribution may be taxable if
either CenterPoint Energy or Reliant Resources undergo a 50% or greater change
in stock ownership within two years after the Distribution. These costs may be
so great that they delay or prevent a strategic acquisition or change in control
of our company. If Reliant Resources takes actions which cause the Distribution
to fail to qualify as a tax-free transaction, for example, through a change in
control of Reliant Resources, we will be responsible for the tax due on the gain
but may seek indemnity from Reliant Resources for such payments.

Credit. To the extent that we continue to need access to current amounts
of committed credit prior to the Distribution, we expect to extend or replace
the credit facilities on a timely basis. The terms of any new

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credit facilities are expected to be adversely affected by our leverage, the
amount of bank capacity utilized, any delay in the date of Restructuring and
Distribution and conditions in the bank market. These same factors are expected
to make the syndication of new credit facilities more difficult in the future.
Proceeds from any issuance of debt in the capital markets are expected to be
used to retire a portion of our short-term debt and reduce our need for
committed revolving credit facilities.

FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC OPERATIONS

Deregulation. In June 1999, the Texas legislature adopted the Texas
Electric Restructuring Law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail competition.
Retail pilot projects for up to 5% of each utility's load in all customer
classes began in August 2001 and retail electric competition for all other
customers began on January 1, 2002. We have made significant changes in the
electric utility operations previously conducted through Reliant Energy HL&P.
For additional information regarding these changes, please read "Our
Business -- Deregulation," "-- Electric Operations," "-- Regulation -- State and
Local Regulations -- Texas -- Electric Operations -- The Texas Electric
Restructuring Law" and "-- Our Business Going Forward" in Item 1 of this Form
10-K and Note 4 to our consolidated financial statements.

Transmission and Distribution. Under the Texas Electric Restructuring Law,
our T&D Utility will remain subject to traditional rate regulation by the Texas
Utility Commission, and we will collect from retail electric providers the rates
approved in the T&D Utility's rate case (Wires Case) to cover the cost of
providing transmission and distribution service and any other expenses. Our
ability to earn the rate of return built into the T&D Utility's rates may be
affected, positively or negatively, to the extent that the T&D Utility's actual
expenses or revenues differ from the estimates used to set the T&D Utility's
rates.

Generation. As described under "Electric Operations -- Generation," since
January 1, 2002, we have been obligated to sell substantially all of the
generating capacity and related ancillary services of our Texas generation
business through auctions. As a result, we are not guaranteed any rate of return
on our investment in these generation facilities through mandated rates, and our
revenues and results of operations are likely to depend, in large part, upon
prevailing market prices for electricity in the Texas market and the related
results of our capacity auctions. These market prices may fluctuate
substantially over relatively short periods of time. In addition, ERCOT, the
independent system operator for the Texas markets, may impose price limitations,
bidding rules and other mechanisms that may impact wholesale power prices in the
Texas market and the outcome of our capacity auctions. Our historical financial
results represent the results of our Texas generation business as part of an
integrated utility in a regulated market and may not be representative of its
results as a stand-alone wholesale electric power generation company in an
unregulated market. Therefore, the historical financial information included in
this report does not necessarily reflect what our financial position, results of
operations and cash flows would have been had our generation facilities been
operated in an unregulated market.

Under the terms of the auctions pursuant to which we are obligated to sell
our capacity, we are obligated to provide specified amounts of capacity to
successful bidders. The products we sell in the auctions are only entitlements
to capacity dispatched from our units and do not convey the right to have power
dispatched from a particular unit. This flexibility exposes us to the risk that,
depending on the availability of our units, we could be required to supply
energy from a higher cost unit to meet an obligation for lower cost generation
or to obtain the energy on the open market. Obtaining such replacement
generation could involve significant additional costs. We manage this risk by
maintaining appropriate reserves within our generation asset base but these
reserves may not cover an entire exposure in the event of a significant outage
at one of our facilities. For information about operating risks associated with
our Texas generation business, please read "Factors Affecting the Results of Our
Wholesale Energy Operations -- Operating Risks" below.

Also, market volatility in the price of fuel for our generation operations,
as well as in the price of purchased power, could have an effect on our cost to
generate or acquire power. For additional information regarding commodity prices
and supplies, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Price Volatility."

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Pursuant to the Texas Electric Restructuring Law, we will be entitled to
recover our stranded costs (i.e., the excess of regulatory net book value of
generation assets, as defined by the Texas Electric Restructuring Law, over the
market value of those assets) and our regulatory assets related to generation.
The Texas Electric Restructuring Law prescribes specific methods for determining
the amount of stranded costs and the details for their recovery, and our
recovery of stranded costs is dependent upon the outcome of regulatory
proceedings in which we will be required to establish the extent of our stranded
costs and related underlying matters. During the base rate freeze period from
July 1999 through 2001, earnings above the utility's authorized rate of return
formula were applied in a manner to accelerate depreciation of generation
related plant assets for regulatory purposes. In addition, depreciation expense
for transmission and distribution related assets was redirected to generation
assets for regulatory purposes from 1998. The Texas Electric Restructuring Law
also provided for us, or a special purpose entity formed by us, to issue
securitization bonds for the recovery of generation related regulatory assets
and a portion of stranded costs. Reliant Energy Transition Bond Company LLC, our
wholly owned subsidiary, issued $749 million of securitization bonds on October
24, 2001. Any stranded costs not recovered through the sale of securitization
bonds may be recovered through a charge to transmission and distribution
customers. For additional information regarding these securitization bonds,
please read Note 4(a) to our consolidated financial statements. For information
regarding recovery of under-collected fuel expenses, please read "Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Fuel Filing in Item 7 of
this Form 10-K".

The Texas Utility Commission issued a final order on October 3, 2001
(October 3, 2001 Order) that established the transmission and distribution rates
that became effective January 2002. In this Order, the Texas Utility Commission
found that we had overmitigated our stranded costs by redirecting transmission
and distribution depreciation and by accelerating depreciation of generation
assets as provided under the Transition Plan and Texas Electric Restructuring
Law. In December 2001, we recorded a regulatory liability of $1.1 billion to
reflect the prospective refund of accelerated depreciation, removed our
previously recorded embedded regulatory asset of $841 million related to
redirected depreciation and recorded a regulatory asset of $2.0 billion based
upon current projections of market value of the Reliant Energy HL&P generation
assets to be covered by the 2004 true-up proceeding provided for in the Texas
Electric Restructuring Law. Recovery of this asset is subject to regulatory
risk. We began refunding the excess mitigation credits in January 2002 and will
continue over a seven year period. If events occur that make the recovery of all
or a portion of the regulatory assets no longer probable, we will write off the
corresponding balance of these assets as a charge against earnings. One of the
results of discontinuing the application of regulatory accounting for the
generation operations is the elimination of the regulatory accounting effects of
excess deferred income taxes and investment tax credits related to these
operations. We believe it is probable that some parties will seek to return
these amounts to ratepayers and, accordingly, we have recorded an offsetting
liability.

The Texas Electric Restructuring Law requires us to auction 15% of the
output of the installed generating capacity of our Texas generation business
until January 1, 2007 unless certain criteria are met (state mandated auctions).
In addition, the master separation agreement between Reliant Energy and Reliant
Resources requires us to auction to third parties, including Reliant Resources,
the capacity available in excess of amounts included in the state mandated
auctions (contractually mandated auctions). Beginning January 2002, our Texas
generation business began delivering power sold through the state mandated
auctions and contractually mandated auctions at market rates. However, the Texas
Electric Restructuring Law provides for recovery of any difference between
market power prices received in these capacity auctions and the Texas Utility
Commission's earlier estimates of those market prices. This capacity auction
true-up should provide for revenues earned by our Texas generation business
during the two-year period ending December 2003 to approximate a regulated
return on the invested capital of our Texas generation business. The Texas
Utility Commission's estimate serves as a preliminary identification of stranded
costs for recovery through securitization. This component of the true-up is
intended to ensure that neither the customers nor we are disadvantaged
economically as a result of the two-year transition period by providing this
pricing structure. The underlying data for the true-up calculation has not been
finalized. Because the capacity true-up process provided for in the Texas
Electric Restructuring Law will take into account only the prices we receive in
the state mandated auctions, lower prices that we may receive in the
contractually mandated auctions will not be considered and

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we may therefore not recover all of our stranded costs. We cannot predict the
amount, if any, of these costs that would not be recovered.

Retail. For a discussion of factors affecting our retail operations,
please read "-- Factors Affecting the Results of Our Retail Operations."

Other. For additional information regarding litigation over franchise
fees, please read Note 14(f) to our consolidated financial statements.

FACTORS AFFECTING THE RESULTS OF RERC'S OPERATIONS

Natural Gas Distribution. Our Natural Gas Distribution business segment
competes primarily with alternate energy sources such as electricity and other
fuel sources. In some areas, intrastate pipelines, other gas distributors and
marketers also compete directly with our Natural Gas Distribution business
segment for gas sales to end-users. In addition, as a result of federal
regulatory changes affecting interstate pipelines, natural gas marketers
operating on these pipelines may be able to bypass our Natural Gas Distribution
business segment's facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers.

Generally, the regulations of the states in which our Natural Gas
Distribution business segment operates allow us to pass through changes in the
costs of natural gas to our customers through purchased gas adjustment
provisions in rates. There is, however, an inherent timing difference between
our purchases of natural gas and the ultimate recovery of these costs.
Consequently, we may incur additional "carrying" costs as a result of this
timing difference and the resulting, temporary under-recovery of our purchased
gas costs. To a large extent, these additional carrying costs are not recovered
from our customers.

On November 21, 2001, Arkla filed a rate case (Docket 01-243-U) with the
Arkansas Public Service Commission seeking an increase in rates for its Arkansas
customers of approximately $47 million on an annual basis. Arkla's last rate
increase was authorized in 1995. In the rate filing, Arkla maintains that its
rate base has grown by $183 million, and its operating expenses have increased
from $93 million to $106 million on an annual basis and, therefore, Arkla's
current rates for service to Arkansas customers do not provide a reasonable
opportunity for Arkla to cover its operating costs and earn a fair return on its
investment. A decision in the case is expected by the fourth quarter of 2002.

Pipelines and Gathering. Our Pipelines and Gathering business segment
competes with other interstate and intrastate pipelines in the transportation
and storage of natural gas. The principal elements of competition among
pipelines are rates, terms of service, and flexibility and reliability of
service. Our Pipelines and Gathering business segment competes indirectly with
other forms of energy available to its customers, including electricity, coal
and fuel oils. The primary competitive factor is price. Changes in the
availability of energy and pipeline capacity, the level of business activity,
conservation and governmental regulations, the capability to convert to
alternative fuels, and other factors, including weather, affect the demand for
natural gas in areas we serve and the level of competition for transportation
and storage services. Since FERC Order No. 636, REGT's and MRT's commodity sales
activity has been minimal. Commodity transactions are usually related to system
management activity which we have been able to manage with little exposure. We
have not been nor do we anticipate being negatively impacted by higher price
levels and the tightening of supply experienced in the fourth quarter of 2000
and the first quarter of 2001. In addition, competition for our gathering
operations is impacted by commodity pricing levels in its markets because these
prices influence the level of drilling activity in those markets.

Natural Gas Pipeline Company of America has proposed, and is soliciting
customers for a 30" pipeline paralleling MRT's East Line in Illinois to a point
17 miles east of St. Louis Metro, with a proposed in-service date of June 2002.
This service would represent an alternative to that provided by MRT. MRT has
renewed or is engaged in negotiations to renew service agreements under
multi-year terms, including service and potential expansion needs along MRT's
existing East Line in Illinois. Our Pipelines and Gathering business segment
derives approximately 14% of its revenues from Laclede Gas Company, which has an
annual evergreen term provision. In February 2002, MRT negotiated an agreement
to extend its existing service relationship with Laclede for a five year period
subject to acceptance by the FERC. However, the Pipelines and Gathering
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business segment's financial results could be materially adversely affected
after this five year period if Laclede decides to engage another pipeline for
the transportation services currently provided by the Pipelines and Gathering
business segment.

FACTORS AFFECTING THE RESULTS OF OUR WHOLESALE ENERGY OPERATIONS

Price Volatility. Our Wholesale Energy business segment, which is
conducted through Reliant Resources, sells electricity from its facilities into
spot markets under short- and long-term contractual arrangements. We are not
guaranteed any rate of return on our capital investments through cost of service
rates, and our revenues and results of operations are likely to depend, in large
part, upon prevailing market prices for electricity and fuel in our regional
markets. In addition to our power generation operations, we trade and market
power. Market prices may fluctuate substantially over relatively short periods
of time. Demand for electricity can fluctuate dramatically, creating periods of
substantial under- or over-supply. During periods of over-supply, prices are
depressed. During periods of under-supply, there is frequently regulatory or
political pressure to regulate prices to compensate for product scarcity.

In addition, the FERC, which has jurisdiction over wholesale power rates,
as well as independent system operators that oversee some of these markets, have
imposed price limitations, bidding rules and other mechanisms to attempt to
address some of the volatility in these markets and mitigate market prices. For
a discussion of the implementation of price limitations and other rules in the
California market, please read Note 14(g) to our consolidated financial
statements.

Most of our Wholesale Energy business segment's domestic power generation
facilities purchase fuel under short-term contracts or on the spot market. Fuel
prices may also be volatile, and the price we can obtain for power sales may not
change at the same rate as changes in fuel costs. In addition, we trade and
market natural gas and other energy-related commodities. These factors could
have an adverse impact on our revenues, margins and results of operations.

Volatility in market prices for fuel and electricity may result from:

- weather conditions;

- seasonality;

- forced or unscheduled plant outages;

- addition of generating capacity;

- changes in market liquidity;

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

- availability of competitively priced alternative energy sources;

- demand for energy commodities and general economic conditions;

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

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

- natural disasters, wars, embargoes and other catastrophic events; and

- federal, state and foreign governmental regulation and legislation.

Risks Associated with Our Hedging and Risk Management Activities. To lower
our financial exposure related to commodity price fluctuations, our trading,
marketing and risk management services operations routinely enter into contracts
to hedge a portion of our purchase and sale commitments, exposure to weather
fluctuations, fuel requirements and inventories of natural gas, coal, crude oil
and refined products, and other commodities. As part of this strategy, we
routinely utilize fixed-price forward physical purchase and sales contracts,
futures, financial swaps and option contracts traded in the over-the-counter
markets and on exchanges. However, we do not expect to cover the entire exposure
of our assets or our positions to market price volatility, and the coverage will
vary over time. This hedging activity fluctuates according to strategic
objectives, taking into account the desire for cash flow or earnings certainty
and our view on market prices. To the extent we have unhedged positions,
fluctuating commodity prices could negatively impact our financial
87

results and financial position. For additional information regarding the
accounting treatment for our hedging, trading and marketing and risk management
activities, please read Notes 2(d) and 5 to our consolidated financial
statements. For additional information regarding the types of contracts and
activities of our trading and marketing operations, please read "-- Trading and
Marketing Operations" and "Qualitative and Quantitative Disclosures about Market
Risk" in Item 7A of this Form 10-K.

We manage our power generation hedge objectives in the context of market
conditions while targeting certain hedge percentages of future earnings through
hedge actions in the current year. As of December 31, 2001, we had hedged 39%
and 29% of our planned Wholesale Energy margins for 2002 and 2003, respectively,
excluding margins related to Orion Power. Margins for 2002 and 2003 are expected
to be positively impacted by the acquisition of Orion Power and negatively
affected by lower forward electric power prices as they relate to unhedged
positions and an estimated decline in our trading and marketing operations due
to projected decreases in volatility in energy commodity markets.

At times, we have open trading positions in the market, within established
corporate risk management guidelines, resulting from the management of our
trading portfolio. To the extent open trading positions exist, changes in
commodity prices could negatively impact our financial results and financial
position.

The risk management procedures we have in place may not always be followed
or may not always work as planned. As a result of these and other factors, we
cannot predict with precision the impact that our risk management decisions may
have on our businesses, operating results or financial position. For information
regarding our risk management policies, please read "Quantitative and
Qualitative Disclosures about Market Risk -- Risk Management Structure" in Item
7A to this Form 10-K.

The trading, marketing and risk management services operations conducted by
our Wholesale Energy business segment are also exposed to the risk that
counterparties who owe us money or physical commodities, such as power, natural
gas or coal, will not perform their obligations. Should the counterparties to
these arrangements fail to perform, we might be forced to acquire alternative
hedging arrangements or replace the underlying commitment at then-current market
prices. In this event, we might incur additional losses to the extent of
amounts, if any, already paid to the counterparties. For information regarding
our credit risk, including exposure to Enron and utilities in California, please
read "Quantitative and Qualitative Disclosure About Market Risk -- Credit Risk"
in Item 7A of this Form 10-K and Notes 5(c), 14(g) and 21 to our consolidated
financial statements.

In the ordinary course of business, and as part of our hedging strategy, we
enter into long-term sales arrangements for power, as well as long-term purchase
arrangements. For information regarding our long-term fuel supply contracts,
purchase power and electric capacity contracts and commitments, electric energy
and electric sale contracts and tolling arrangements, please read Notes 5, 14(a)
and 14(b) to our consolidated financial statements.

Uncertainty in the California Market. During portions of 2000 and 2001,
prices for wholesale electricity in California increased dramatically as a
result of a combination of factors, including higher natural gas prices and
emission allowance costs, reduction in available hydroelectric generation
resources, increased demand, decreased net electric imports and limitations on
supply as a result of maintenance and other outages. Because of the high prices
that prevailed during this period, we, and several of Reliant Resources'
subsidiaries, including Reliant Energy Services and REPG, as well as some of the
officers of some of these companies, have been named as defendants in class
action lawsuits and other lawsuits filed against a number of companies that own
generation plants in California and other sellers of electricity in California
markets.

In response to the filing of a number of complaints challenging the level
of these wholesale prices, the FERC initiated a staff investigation and issued a
number of orders implementing a series of wholesale market reforms and
modifications to those reforms. On February 13, 2002, the FERC issued an order
initiating a staff investigation into potential manipulation of electric and
natural gas prices in the West region for the period

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January 1, 2000 forward. Some of our long-term bilateral contracts already have
been challenged by one of our many counterparties based on the alleged market
dysfunction in Western power markets in 2000 and 2001. If these challenges are
successful, the precedent set by the challenge could have larger ramifications
to our business and operations beyond the challenged contracts at issue.
Furthermore, in addition to FERC investigations, several state and other federal
regulatory investigations have commenced in connection with the wholesale
electricity prices in California and other neighboring Western states to
determine the causes of the high prices and potentially to recommend remedial
action.

Finally, there have been proposals in the California state legislature to
regulate the operations of our California generating subsidiaries, beyond the
existing state regulation regarding siting, environmental and other health and
safety matters. For additional information regarding the litigation and market
uncertainty in California, please read Notes 14(f) and 14(g) to our consolidated
financial statements.

Industry Restructuring, the Risk of Re-regulation and the Impact of Current
Regulations. The regulatory environment applicable to the United States
electric power industry is undergoing significant changes as a result of varying
restructuring initiatives at both the state and federal levels and the
reassessment of existing regulatory mechanisms stemming from the California
power market situation and the bankruptcy of Enron. These initiatives have had a
significant impact on the nature of the industry and the manner in which its
participants conduct their business. These changes are ongoing and we cannot
predict the future development of restructuring in these markets or the ultimate
effect that this changing regulatory environment will have on our business.

Moreover, existing regulations may be revised or reinterpreted, new laws
and regulations may be adopted or become applicable to us, our facilities or our
commercial activities, and future changes in laws and regulations may have a
detrimental effect on our business. Some restructured markets, particularly
California, have experienced supply problems and price volatility. These supply
problems and volatility have been the subject of a significant amount of press
coverage, much of which has been critical of the restructuring initiatives. In
some markets, including California, proposals have been made by governmental
agencies and/or other interested parties to delay or discontinue proposed
restructuring or to re-regulate areas of these markets, especially with respect
to residential retail customers, that have previously been deregulated. In this
connection, state officials, the California Independent System Operator (Cal
ISO) and the investor-owned utilities in California have argued to the FERC that
our California generating subsidiaries should not continue to have market-based
rate authority. While the FERC to date has consistently refused petitions to
force entities with market-based rates to return to cost-based rates, some of
these proceedings are ongoing and we cannot predict what action the FERC may
take on such petitions in the future. If we were forced to adopt cost-based
rates, future earnings would be affected. Furthermore, the Cal ISO is
undertaking a market redesign process to fundamentally change the structure of
wholesale electricity markets and transmission service in California. These
changes, if approved by the FERC, could include a revised market monitoring and
mitigation structure, a revised congestion management mechanism and an
obligation for load-serving entities in California to maintain capacity
reserves. The Cal ISO's stated goal is to complete the first phase of this
redesign by September 30, 2002, when the existing FERC market mitigation scheme
for California will expire.

On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including Reliant Energy. For information
regarding this FERC proceeding and other FERC actions relating to the California
market, please read Note 14(g) to our consolidated financial statements. If the
FERC does not modify or reject its proposed approach for dealing with
anti-competitive behavior, our future earnings may be affected by the open-ended
refund obligation.

Additionally, federal legislative initiatives have been introduced and
discussed to address the problems being experienced in some of these markets,
including legislation seeking to impose price caps on sales. We cannot predict
whether other proposals to re-regulate will be made or whether legislative or
other attention to the restructuring of the electric power industry will cause
the restructuring to be delayed or reversed. If the trend towards competitive
restructuring of the wholesale power markets is reversed, discontinued or
delayed,

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the business growth prospects and financial results of our Wholesale Energy and
Retail Energy segments could be adversely affected.

If RTOs are established as envisioned by Order No. 2000, "rate pancaking,"
or multiple transmission charges that apply to a single point-to-point delivery
of energy will be eliminated within a region, and wholesale transactions within
the region, and between regions will be facilitated. The end result could be a
more competitive, transparent market for the sale of energy and a more economic
and efficient use and allocation of resources; however, considerable opposition
exists to the development of RTOs.

The FERC also has initiated a rulemaking proceeding to establish
standardized transmission service throughout the United States, a standard
wholesale electric market design, including forward and spot markets for energy
and an ancillary services market, and specifications regarding the entities that
administer these markets and for market monitoring and mitigation, that could be
used in all RTOs. We cannot predict at this time what effect FERC's standard
market design will have on our business growth prospects and financial results.

Partly in response to the bankruptcy of Enron, there have been proposals in
the United States Congress to make online platforms that trade energy and metals
derivatives subject to oversight by the Commodities Futures Trading Commission
(CFTC), to prohibit market price manipulation and fraud. Under some of these
proposals, dealers in energy derivatives would be required to file reports with
the CFTC and maintain amounts of capital, as determined by the CFTC, to support
the risks of their transactions. Other proposals would require the CFTC to
review these markets for potential regulatory recommendations. We do not know
what impact, if any, these proposals would have on our business if enacted.
Additionally, there may be other broader proposals introduced to submit energy
trading to comprehensive regulation by the FERC or by the CFTC.

The acquisition, 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.
At present, we have operations in Arizona, California, Florida, Illinois,
Maryland, Nevada, New Jersey, New York, Ohio, Pennsylvania, Texas and West
Virginia. Most of our existing domestic 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 and by state public utility commissions regarding siting, environmental
and other health and safety matters. The FERC has authorized us to sell our
generation 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 if it determines that market pricing is not in the
public interest.

Uncertainty Related to the New York Regulatory Environment. The New York
market is subject to significant regulatory oversight and control. Our operating
results are as dependent on the continuance of the regulatory structure as they
are on fluctuations in the market price for electricity. The rules governing the
current regulatory structure are subject to change. We cannot assure you that we
will be able to adapt our business in a timely manner in response to any changes
in the regulatory structure, which could have a material adverse effect on our
revenues and costs. The primary regulatory risk in this market is associated
with the oversight activity of the New York Public Service Commission, the New
York Independent System Operator (NYISO) and the FERC.

Our assets located in New York are subject to "lightened regulation" by the
New York Public Service Commission, including provisions of the New York Public
Service Law that relate to enforcement, investigation, safety, reliability,
system improvements, construction, excavation, and the issuance of securities.
Because "lightened regulation" was accomplished administratively, it could be
revoked.

The NYISO has the ability to revise wholesale prices, which could lead to
delayed or disputed collection of amounts due to us for sales of energy and
ancillary services. The NYISO also has the ability, in some cases subject to
FERC approval, to impose cost-based pricing and/or price caps. The NYISO has
implemented a measure known as the "Automated Mitigation Procedure" (AMP) under
which day-ahead energy bids will be automatically reviewed and, if necessary,
mitigated if economic or physical withholding is determined. Proposed
modifications to the AMP provide a level of uncertainty over the impacts of that
procedure in the

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summer of 2002. FERC has also directed the NYISO to adopt mitigation measures
for all limits in New York City consistent with its overall market-monitoring
plan. NYISO has filed in-city mitigation measures with the FERC, which it is
proposing to be implemented beginning in late spring of 2002. The full impact of
these revisions may not be known until the summer of 2002.

Integration and Other Risks Associated with Our Orion Power Assets. We
have made a substantial investment in our recent acquisition of Orion Power. If
we are unable to profitably integrate, operate, maintain and manage our newly
acquired power generation facilities our results of operations will be adversely
affected.

Duquesne Light Company is obligated to supply electricity at predetermined
tariff rates to all retail customers in its existing service territory who do
not select another electricity supplier. Orion Power has committed to provide
100% of the energy that Duquesne Light Company needs to meet this obligation
under a contract that was recently extended through December 2004. If our
obligation under this contract exceeds the available output from the combination
of Orion Power's generation facilities and our additional generation facilities
in the region, we would be forced to buy additional energy at prevailing market
prices and, in certain cases where we failed to deliver the required amount, we
could incur penalties during periods of peak demand of up to $1,000 per megawatt
hour. If this situation were to occur during periods of peak energy prices, we
could suffer substantial losses that could materially adversely affect our
results of operations. In addition, our revenues generated under this contract
may be adversely impacted if a substantial number of Duquesne Light Company's
retail customers select other retail electric providers.

Operating Risks. Our Electric Generation, Wholesale Energy operations and
our European Energy operations are exposed to risks relating to the breakdown or
failure of equipment or processes, fuel supply interruptions, shortages of
equipment, material and labor, and operating performance below expected levels
of output or efficiency. A significant portion 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 or upgrade equipment to keep it operating at peak
efficiency, to comply with changing environmental requirements, or to provide
reliable operations. Such changes could affect operating costs. Any unexpected
failure to produce power, including failure caused by breakdown or forced
outage, could result in reduced earnings.

We depend on transmission and distribution facilities owned and operated by
utilities and other power companies to deliver the electricity we sell from our
power generation facilities to our customers, who in turn deliver these products
to the ultimate consumers of the power. If transmission is disrupted, or
transmission capacity is inadequate, our ability to sell and deliver our
products may be hindered.

Factors Affecting Our Acquisition and Project Development Activities. Our
plans for our Wholesale Energy business segment indicate a shift in emphasis
from identifying and pursuing acquisition and development candidates to
construction and integration of generation facilities. We believe this is a
temporary shift based on the requirements of integrating the Orion Power assets
and the maturation of both our and Orion Power's development projects and by the
current state of the wholesale electricity and capital markets.

There are numerous risks relating to the acquisition and development of
power generation plants and construction and integration of these facilities. We
may not be able to identify attractive acquisitions or development
opportunities, complete acquisitions or development projects we undertake, or we
may not be able to integrate these plants, especially larger acquisitions, into
the portfolios of our Wholesale Energy business segment and achieve the
synergies, including cost savings, we originally envisioned.

Currently, our Wholesale Energy business segment has a select number of
power generation facilities under development and many under construction
(either owned or leased). Our completion of these facilities is subject to the
following:

- market prices;

- shortages and inconsistent quality of equipment, material and labor;

- financial market conditions and the results of our financing efforts;

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

- work stoppages, due to plant bankruptcies and contract labor disputes;

- permitting and other regulatory matters;

- unforeseen weather conditions;

- unforeseen equipment problems;

- environmental and geological conditions; and

- unanticipated capital cost increases.

Any of these factors could give rise to delays, cost overruns or the
termination of the plant expansion, construction or development. Many of these
risks cannot be adequately covered by insurance. While we maintain insurance,
obtain warranties from vendors and obligate contractors to meet specified
performance standards, the proceeds of such insurance, warranties or performance
guarantees may not be adequate to cover lost revenues, increased expenses or
liquidated damages payments we may owe.

If we were unable to complete the development of a facility, we would
generally not be able to recover our investment in the project. The process for
obtaining initial environmental, siting and other governmental permits and
approvals is complicated, expensive, lengthy and subject to significant
uncertainties. Transmission interconnection, fuel supply and cooling water
represent some cost uncertainties during project development that may also
result in termination of the project. In addition, construction delays and
contractor performance shortfalls can result in the loss of revenues and may, in
turn, adversely affect our results of operations. The failure to complete
construction according to specifications can result in liabilities, reduced
plant efficiency, higher operating costs and reduced earnings. We may not be
successful in the development or construction of power generation facilities in
the future.

As a result of several recent events, including the United States economic
recession, the price decline of our industry sector in the equity capital
markets and the downgrading of the credit ratings of several of our significant
competitors, the availability and cost of capital for our business and the
businesses of our competitors has been adversely affected. In response to these
events and the intensified scrutiny of companies in our industry sector by the
rating agencies, our Wholesale Energy business segment has reduced its planned
capital expenditures by $2.7 billion over the 2002-2006 time frame.

Successful integration of plants, especially acquisitions, is subject to a
number of risks, including the following:

- unforeseen liabilities or other exposures;

- inaccurate due diligence of acquired facilities, such as underestimates
of outage rates and operating costs;

- inability to achieve adequate cost savings in both overhead and
operations;

- inability to achieve various commercial synergies with existing
operations; and

- market prices for power and fuels.

Any of these factors could significantly affect the economic impact of an
acquisition on our results of operations.

As part of this integration process and our temporary shift in emphasis,
the Orion Power plants will be part of an operations improvement process that
strives to achieve both reduced operating and maintenance costs and increase
gross margins through improved availability and reliability of plants. This
process is currently underway at our other plants and will be introduced at the
Orion Power facilities beginning in the third quarter of 2002.

Increasing Competition in Our Industry. Our Wholesale Energy business
segment competes with other energy merchants. In order to successfully compete,
we must have the ability to aggregate supplies at
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competitive prices from different sources and locations and must be able to
efficiently utilize transportation services from third-party pipelines and
transmission services from electric utilities. We also compete against other
energy merchants on the basis of our relative skills, financial position and
access to credit sources. Energy customers, wholesale energy suppliers and
transporters often seek financial guarantees and other assurances that their
energy contracts will be satisfied. As pricing information becomes increasingly
available in the energy trading and marketing business, we anticipate that our
operations will experience greater competition and downward pressure on per-unit
profit margins. Furthermore, demands for liquidity to support trading and
merchant asset businesses are increasing at the same time that the credit rating
agencies are reviewing the liquidity and other credit criteria for trading,
marketing and merchant generation firms. Other companies we compete with may not
have similar credit ratings pressure or may have higher credit ratings. The
growth of electronic trading platforms has increased the number of transactions,
potential counterparties and level of price transparency in the energy commodity
market. As a result, we are likely to transact with a wide range of customers
potentially increasing our risk due to their changing credit circumstances,
while at the same time potentially diversifying our reliance on a smaller number
of customers.

Developments with respect to our competitors frequently have a collateral
and tangible impact on us. Credit and liquidity concerns impact our ability to
do business with counterparties. Adverse regulatory and political ramifications
can result from activities and investigations directed at our competitors.

Hydroelectric Facilities Licensing. The Federal Power Act gives the FERC
exclusive authority to license non-federal hydroelectric projects on navigable
waterways and federal lands. The FERC hydroelectric licenses are issued for
terms of 30 to 50 years. Some of the hydroelectric facilities in our Wholesale
Energy business segment, representing approximately 90 MW of capacity, have
licenses that expire within the next ten years. Facilities that we own
representing approximately 160 MW of capacity have new or initial license
applications pending before the FERC. Upon expiration of a FERC license, the
federal government can take over the project and compensate the licensee, or the
FERC can issue a new license to either the existing licensee or a new licensee.
In addition, upon license expiration, the FERC can decommission an operating
project and even order that it be removed from the river at the owner's expense.
In deciding whether to issue a license, the FERC gives equal consideration to a
full range of licensing purposes related to the potential value of a stream or
river. It is not uncommon for the relicensing process to take between four and
ten years to complete. Generally, the relicensing process begins at least five
years before the license expiration date and the FERC issues annual licenses to
permit a hydroelectric facility to continue operations pending conclusion of the
relicensing process. We expect that the FERC will issue to us new or initial
hydroelectric licenses for all the facilities with pending applications.
Presently, there are no applications for competing licenses and there is no
indication that the FERC will decommission or order any of the projects to be
removed.

FACTORS AFFECTING THE RESULTS OF OUR EUROPEAN ENERGY OPERATIONS

General. Our European Energy segment, which is operated by subsidiaries of
Reliant Resources, intends to focus its activities in existing trading markets
in the Netherlands, the United Kingdom, Germany, the Scandinavian countries,
Austria and Switzerland. Historical results of operations may not be indicative
of future results of operations. In particular, results of operations for our
European Energy segment prior to 2001 reflect the impact of a regulated
generation price system that has been discontinued. In addition, in 2001 and
prior years, under Dutch corporate income tax laws, the earnings of REPGB were
subject to a zero percent Dutch corporate income tax rate as a result of the
Dutch tax holiday applicable to its electric industry. After December 31, 2001,
all of European Energy's earnings in the Netherlands will be subject to the
standard Dutch corporate income tax rate, which currently is 34.5%. Furthermore,
European Energy's results of operations for 2001 include the effect of a number
of non-recurring items, including the $37 million net gain resulting from the
settlement of a stranded cost indemnity agreement.

Future results of operations of our European Energy segment could be
affected by, among other things, the following:

- increasing competition in the Dutch wholesale energy market, resulting in
declining electric power margins;

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- the timing and pace of the deregulation of other sectors of the European
energy markets;

- the continuing negative impact of the bankruptcy of Enron on market
liquidity and credit requirements in European trading markets;

- the mark-to-market price risk exposure associated with certain stranded
cost electricity and natural gas supply contracts;

- the impact of any renegotiation of European Energy's stranded cost
contracts;

- the impact and changes of natural gas tariffs pursuant to changes in the
regulatory structure;

- the ability to negotiate new contracts or renew contracts with customers
on favorable terms; and

- the impact of slowing economic growth on power generation demand in the
markets in which our European Energy segment operates.

Competition in the European Market. Competition for energy customers in
the markets in which our European Energy segment operates is high. The primary
factors affecting our European Energy segment's competitive position are price,
regulation, the economic resources of its competitors, and its market reputation
and perceived creditworthiness.

Our European Energy segment competes in the Dutch Wholesale market against
a variety of other companies, including other Dutch generation companies,
cogenerators, various producers of alternate sources of power and non-Dutch
generators of electric power, primarily from France and Germany. As of December
31, 2001, the Dutch electricity system had three operational interconnection
points with Germany and two interconnection points with Belgium. There are also
a number of projects that are at various stages of development and that may
increase the number of interconnections in the future (post 2005), including
interconnections with Norway and the United Kingdom. The Belgian
interconnections are primarily used to import electricity from France, but a
larger portion of Dutch electricity imports comes from Germany. It is
anticipated that over time, transmission constraints between the Netherlands and
other European markets will be reduced, thereby exposing our European Energy
segment to even greater competitive pressures.

Our European Energy segment's trading and marketing operations are also
subject to increasing levels of competition. Competition among power generators
for customers is intense and is expected to increase as more participants enter
increasingly deregulated markets. Many of our European Energy segment's existing
competitors have geographic market positions far more extensive than that of our
European Energy segment. In addition, many of these competitors possess
significantly greater financial, personnel and other resources than our European
Energy segment.

Deregulation of the Dutch Market. The Dutch wholesale electric market was
completely opened to competition on January 1, 2001. Consistent with our
expectations at the time we acquired our operations in the Netherlands, the
gross margin of our European Energy segment declined in 2001 as a result of the
deregulation of the market and the termination of an agreement with the other
Dutch generators and the Dutch distributors. Commercial markets were generally
opened to retail competition in January 2002. We expect the remainder of the
market, consisting of mainly residential customers, will be open to competition
by January 1, 2003. The timing of opening of the residential segment of the
market is subject to change, however, at the discretion of the Dutch Minister of
Economic Affairs. Since our European Energy segment's operations focus on the
wholesale market, we do not expect that the opening of the Dutch commercial or
residential electric market will have a significant impact on the segment's
results of operations.

Plant Outages. During 2001, our margins were negatively impacted by
unplanned outages at some of our Dutch generation facilities. The unplanned
outages were primarily due to malfunctions of the generation turbines and
related equipment and complications encountered in the maintenance of one of our
facilities. We estimate that these unplanned outages resulted in losses of
approximately $11 million, a significant portion of which is covered by property
damage and business interruption insurance. For additional information regarding
operational risks applicable to our European Energy segment, including unplanned
plant outages, please read "-- Factors Affecting the Results of Our Wholesale
Energy Operations -- Operating Risks."

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Other Factors. In December 2001, REPGB and its former shareholders entered
into a settlement agreement resolving the former shareholders' stranded cost
indemnity obligations under the purchase agreement of REPGB. For additional
information regarding the stranded cost indemnity settlement and the potential
impact on earnings from changes in the valuation in the future of the related
stranded cost contracts, please read Notes 5(b) and 14(h) to our consolidated
financial statements. We have begun discussions with the other parties to these
contracts to modify the terms of certain of the out-of-market contracts. The
structure of these settlements, if consummated, likely would entail an upfront
cash payment to the counterparty in exchange for amendments to price and other
terms intended to make the contracts more market conforming. REPGB would seek to
fund these payments, if made, to the extent possible through the proceeds from
the settlement of its stranded cost indemnity agreement and, possibly,
anticipated distributions from NEA. We cannot currently predict the outcome of
these negotiations. However, to the extent that these discussions result in
amendments to the contracts, we could realize a gain.

We are in the process of reviewing our European Energy segment's goodwill
and certain intangibles for impairment pursuant to SFAS No. 142. For information
regarding assessing the impairment in 2002 under SFAS No. 142, please read
"-- New Accounting Pronouncements."

Our European operations are subject to various risks incidental to
investing or operating in foreign countries. These risks include economic risks,
such as fluctuations in currency exchange rates, restrictions on the
repatriation of foreign earnings and/or restrictions on the conversion of local
currency earnings into U.S. dollars. For example, we estimate that the impact of
the devaluation of the Euro relative to the U.S. dollar during 2001 negatively
affected U.S. dollar net income by approximately $2 million.

FACTORS AFFECTING THE RESULTS OF OUR RETAIL ENERGY OPERATIONS

General. The Texas retail electricity market fully opened to competition
in January 2002. Therefore, we do not expect the earnings from our Retail Energy
segment, which is operated by subsidiaries of Reliant Resources, for past years
to be indicative of our future earnings and results. The level of future
earnings generated by our Retail Energy segment will depend on numerous factors
including:

- legislative and regulatory developments related to the newly opened
retail electricity market in Texas and changes in the application of such
laws and regulations;

- the effects of competition, including the extent and timing of the entry
or exit of competitors in our markets and the impact of competition on
retail prices and margins;

- customer attrition rates and cost associated with acquiring and retaining
new customers;

- our ability to negotiate new contracts or renew contracts with customers
on favorable terms;

- the timing and extent of changes in wholesale commodity prices and
transmission and distribution rates;

- our ability to procure adequate electricity supply upon economic terms;

- our ability to effectively hedge commodity prices;

- our ability to pass increased supply costs on to customers in a timely
manner;

- our ability to timely perform our obligations under our customer
contracts;

- market liquidity for wholesale power;

- the financial condition and payment patterns of our customers;

- weather variations and other natural phenomena;

- the timely and accurate implementation of the new internal and external
information technology systems and processes necessary to provide
customer information and to implement customer switching in the retail
electricity market in Texas which was established in late 2001;

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- the costs associated with operating our internal customer service and
other operating functions; and

- the timing and accuracy of ERCOT settlements, and the exchange of
information between ERCOT, the T&D Utility and our Retail Energy
segment's retail electric provider, which facilitates our Retail Energy
business segment's billing, collection and supply management processes.

Competition in the Texas Market. Under the Texas Electric Restructuring
Law, beginning in 2002, all classes of Texas customers of most investor-owned
utilities, and those of any municipal utility and electric cooperative that
opted to participate in the competitive marketplace, are able to choose their
retail electric provider. In January 2002, Reliant Resources began to provide
retail electric services to all customers of Reliant Energy HL&P who did not
select another retail electric provider. Under the market framework established
by the Texas Electric Restructuring Law, Reliant Resources is recognized as the
affiliated retail electric provider of Reliant Energy's electric utility. The
Distribution will not change this treatment, even though Reliant Resources will
cease to be a subsidiary of Reliant Energy after the Distribution. As an
affiliated retail electric provider, Reliant Resources is initially required to
sell electricity to these Houston area residential and small commercial
customers at a specified price, which is referred to in the law as the "price to
beat," whereas other retail electric providers are allowed to sell electricity
to these customers at any price. Reliant Resources' price to beat was set at a
level resulting in an estimated average 17% reduction from December 31, 2001
rates for its residential customers and an estimated average 22% reduction from
December 31, 2001 rates for its pre-existing small commercial customers. The
wholesale energy supply cost component, or "fuel factor," included in its price
to beat was initially set by the Texas Utility Commission at the then average
forward 12 month gas price strip of approximately $3.11/MMBtu.

Reliant Resources is not permitted to offer electricity to these customers
at a price other than the price to beat until January 1, 2005, unless before
that date the Texas Utility Commission determines that 40% or more of the amount
of electric power that was consumed in 2000 by the relevant class of customers
in the Houston metropolitan area is committed to be served by retail electric
providers other than Reliant Resources. In addition, as the affiliated retail
electric provider, Reliant Resources is obligated to offer the price to beat to
requesting residential and small commercial customers in Reliant Energy's
electric utility service territory through January 1, 2007. Because Reliant
Resources will not be able to compete for residential and small commercial
customers on the basis of price in the Houston area, it may lose a significant
number of these customers to other retail electric providers. Customers were
given the opportunity to switch beginning in August 2001 through the retail
pilot project. Due to system related problems which restricted the timely
switching of customers during the pilot project and in early 2002, we cannot be
sure of the number of customers that have attempted to switch to other retail
electric providers. For additional information regarding retail market systems
problems, please read "-- Operational Risks." Between the beginning of the pilot
project in August 2001 and February 28, 2002, Reliant Resources estimates that
approximately 67,000 customers (or approximately 4% of their residential and
small commercial customers) have switched to other retail electric providers.
Due to the switching systems problems, the actual numbers of customers that
switched or attempted to switch by this date may actually be higher.

Reliant Resources is providing commodity service to the large commercial,
industrial and institutional customers previously served by Reliant Energy's
electric utility who did not take action to select another retail electric
provider. In addition, Reliant Resources has signed contracts to provide
electricity and services to large commercial, industrial and institutional
customers, both in the Houston area as well as outside of the Houston market.
Reliant Resources or any other retail electric provider can provide services to
these customers at any negotiated price. The market for these customers is very
competitive, and any of these customers that select Reliant Resources as their
provider may subsequently decide to switch to another provider at the conclusion
of the term of their contract with Reliant Resources.

In most retail electric markets outside the Houston area, Reliant
Resources' principal competitor may be the local incumbent utility company's
retail affiliate. These retail affiliates have the advantage of long-standing
relationships with their customers. In addition to competition from the
incumbent utilities' affiliates, Reliant Resources may face competition from a
number of other retail providers, including affiliates of other non-incumbent
utilities, independent retail electric providers and, with respect to sales to
large commercial and

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industrial customers, independent power producers acting as retail electric
providers. Some of these competitors or potential competitors may be larger and
better capitalized than Reliant Resources.

Generally, retail electric providers will purchase electricity from the
wholesale generators at unregulated rates, sell electricity to their retail
customers and pay the transmission and distribution utility a regulated tariffed
rate for delivering the electricity to their customers. Retail electric
providers will then bill and collect payments from the customers. Because
Reliant Resources is required to sell electricity to residential and small
commercial customers in the Houston area at the price to beat, it may lose a
significant number of these customers to non-affiliated retail electric
providers if their cost to provide electricity to these customers is lower than
the price to beat. In addition, the results of our Retail Energy operations for
sales to residential and small commercial customers over the next several years
in Texas will be largely dependent upon the amount of gross margin, or
"headroom," available in our price to beat. Until 2004, when Reliant Resources
will have the option to acquire our ownership interest in Texas Genco, Reliant
Resources' results will be largely based on the ability of the Wholesale Energy
segment to buy power at prices that yield acceptable gross margins at revenue
levels determined by the price to beat set by the Texas Utility Commission. The
available headroom in the price to beat is equal to the difference between the
price to beat and the sum of the charges, fees and transmission and distribution
utility rates approved by the Texas Utility Commission and the price Reliant
Resources pays for power to serve its price to beat customers. The larger the
amount of headroom, the more incentive new market entrants should have to
provide retail electric services in that particular market. The Texas Utility
Commission's regulations allow affiliated retail electric providers to adjust
their price to beat fuel factor based on the percentage change in the price of
natural gas. In addition, they may also request an adjustment as a result of
changes in their price of purchased energy. In such a request, they may adjust
the fuel factor to the extent necessary to restore the amount of headroom that
existed at the time the initial price to beat fuel factor was set by the Texas
Utility Commission. Affiliated retail electric providers may not request that
their price to beat be adjusted more than twice a year. Reliant Resources cannot
estimate with any certainty the magnitude and frequency of the adjustments they
may seek, if any, and the eventual impact of such adjustments on the amount of
headroom. Based on forward gas prices at the end of March 2002, Reliant
Resources would be able to increase its price to beat rates by approximately
4-5%. Available headroom in the Houston market, as well as in other Texas
markets where Reliant Resources intends to compete, will be affected by any
changes in transmission and distribution rates that may be requested by the
transmission and distribution provider in the respective service territory and
in taxes, fees and other charges assessed or levied by third parties. Any
changes in transmission and distribution rates must be approved by the Texas
Utility Commission. The Texas Utility Commission has initiated a proceeding to
determine what taxes a municipality or other local taxing authority can charge
retail electric providers relating to the provision of electricity.

In Texas, our Wholesale Energy business segment and our Retail Energy
business segment work together in order to determine the price, demand and
supply of energy required to meet the needs of our Retail Energy business
segments' customers. Reliant Resources may purchase capacity from non-affiliated
parties in the state mandated auctions and from our Texas generation business in
the contractually mandated auctions. Reliant Resources also enters into
bilateral contracts with third parties for capacity, energy and ancillary
services. Supply positions are continuously monitored and updated based on
retail sales forecasts and market conditions. However, Reliant Resources does
not expect to cover the entire exposure of these positions to market price
volatility, and the coverage will vary over time. For a discussion of risks
similar to those associated with our Retail Energy segment's hedging activities,
please read "-- Factors Affecting the Results of Our Wholesale Energy
Operations -- Price Volatility," and "-- Risks Associated with Our Hedging and
Risk Management Activities." In addition to the factors noted in these sections,
Reliant Resources' ability to adequately hedge its retail electricity
requirements is also dependent on the accurate forecast of the number of our
customers in each customer class and uncertainties associated with the recently
established ERCOT settlement procedures.

Obligations as a Provider of Last Resort. The Texas Electric Restructuring
Law requires the Texas Utility Commission to designate certain retail electric
providers as providers of last resort in areas of the state in which retail
competition is in effect. A provider of last resort is required to offer a
standard retail electric service package for each class of customers designated
by the Texas Utility Commission at a fixed,

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nondiscountable rate approved by the Texas Utility Commission, and is required
to provide the service package to any requesting retail customer in the
territory for which it is the provider of last resort. In the event that another
retail electric provider fails to serve any or all of its customers, the
provider of last resort is required to offer that customer the standard retail
service package for that customer class with no interruption of service to the
customer. The Texas Utility Commission designated Reliant Resources' subsidiary,
StarEn Power to serve as the provider of last resort for residential and small
commercial customers in the western portion of the Dallas/Fort Worth
metropolitan area formally served by Texas Utilities, Inc., a subsidiary of TXU,
Inc. In addition, StarEn Power has been appointed as the provider of last resort
for large commercial, industrial and institutional customers in Reliant Energy's
electric utility service territory. StarEn Power will serve two consecutive six
month terms as the provider of last resort. The first term began on January 1,
2002. The second six-month term, beginning July 1, 2002, will include a
potential adjustment to the energy component of our provider of last resort rate
based on a NYMEX Henry Hub natural gas index. The terms and rates for provider
of last resort service are governed by a settlement between Reliant Resources
and various interested parties, which settlement was approved by the Texas
Utility Commission. In this role, StarEn Power retains the rights to require
customer deposits and disconnect service in accordance with Texas Utility
Commission rules, and to petition the Texas Utility Commission for a price
change in the event it is determined that StarEn power will experience a net
financial loss over the term of its provider of last resort obligations. In the
first quarter of 2002, the Texas Utility Commission initiated a proceeding to
review and possibly amend both the governing rules and structure of provider of
last resort service and obligations. This proceeding is in its initial stages
and we cannot be sure whether the structure of provider of last resort service
and obligations will change, how they will change or what effect, if any, any
changes would have on the financial condition, results of operations or cash
flows of StarEn Power or our Retail Energy business segment.

"Clawback" Payment to Reliant Energy. To the extent the price to beat
exceeds the market price of electricity, Reliant Resources will be required to
make a payment to Reliant Energy in 2004 unless the Texas Utility Commission
determines that, on or prior to January 1, 2004, 40% or more of the amount of
electric power that was consumed in 2000 by residential or small commercial
customers (at or below one MW), as applicable, within Reliant Energy HL&P's
service territory is committed to be served by retail electric providers other
than Reliant Resources. If the 40% test is not met and the reconciliation and a
retail payment is required, the amount of this retail payment will be equal to
(a) the amount that the price to beat, less non-bypassable delivery charges, is
in excess of the prevailing market price of electricity during such period per
customer, but not to exceed $150 per customer, multiplied by (b) the number of
residential or small commercial customers, as the case may be, that we serve on
January 1, 2004 in Reliant Energy HL&P's service territory, less the number of
new retail electric customers Reliant Resources serves in other areas of Texas.
Amounts received from Reliant Resources with respect to the clawback payment, if
any, will be included in the 2004 stranded cost true-up as a reduction of
stranded costs.

Operational Risks. The price of purchased power could have an adverse
effect on the costs incurred by our Retail Energy segment in acquiring power to
serve the demand of its retail customers. For additional information regarding
commodity price volatility, please read "-- Factors Affecting the Results of Our
Wholesale Energy Operations -- Price Volatility."

Reliant Resources is dependent on local transmission and distribution
utilities for maintenance of the infrastructure through which electricity is
delivered to its retail customers. Any infrastructure failure that interrupts or
impairs delivery of electricity to its customers could negatively impact the
satisfaction of its customers with its service. Additionally, Reliant Resources
is dependent on the local transmission and distribution utilities for the
reading of its customers' energy meters. Reliant Resources is required to rely
on the local utility or, in some cases, the independent transmission system
operator, to provide it with its customers' information regarding energy usage,
and Reliant Resources may be limited in its ability to confirm the accuracy of
the information. The provision of inaccurate information or delayed provision of
such information by the local utilities or system operators could have a
material negative impact on our business and results of operations and cash
flows.

The ERCOT ISO is the independent system operator responsible for
maintaining reliable operations of the bulk electric power supply system in the
ERCOT market. Its responsibilities include ensuring that
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information relating to a customer's choice of retail electric provider is
conveyed in a timely manner to anyone needing the information. Problems in the
flow of information between the ERCOT ISO, the transmission and distribution
utility and the retail electric providers have resulted in delays in switching
customers. While the flow of information is improving, operational problems in
the new system and processes are still being worked out.

The ERCOT ISO is also responsible for handling scheduling and settlement
for all electricity supply volumes in the Texas deregulated electricity market.
In addition, 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. Reliant Resources and other retail electric
providers schedule volumes based on forecasts. As part of settlement, the ERCOT
ISO communicates the actual volumes delivered compared to the forecast volumes
scheduled. The ERCOT ISO calculates an additional charge or credit based on the
difference between the actual and forecast volumes, utilizing a market clearing
price for the difference. Settlement charges also include allocated costs such
as unaccounted-for energy. Currently, there is a three to four month delay in
receiving the final settlement information. As a result, Reliant Resources must
estimate its supply costs. Timing delays in receiving final settlement
information creates supply cost estimation risk.

FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS

For information regarding our exposure to risk as a result of fluctuations
in commodity prices and derivative instruments, please read "Quantitative and
Qualitative Disclosures About Market Risk" in Item 7A of this Form 10-K.

ENVIRONMENTAL EXPENDITURES

We are subject to numerous environmental laws and regulations, which
require us to incur substantial costs to operate existing facilities, construct
and operate new facilities, and mitigate or remove the effect of past operations
on the environment. For additional information regarding environmental
contingencies, please read Note 14(f) to our consolidated financial statements.

Clean Air Act Expenditures. We expect the majority of capital expenditures
associated with environmental matters to be incurred by our Electric Generation
and Wholesale Energy business segments in connection with emission limitations
for NOx under the Clean Air Act, or to enhance operational flexibility under
Clean Air Act requirements. In 2000, emission reduction requirements for NOx
were finalized for our electric generating facilities in the United States. We
currently estimate that up to $476 million will be required to comply with the
requirements through the end of 2004, with an estimated $287 million to be
incurred in 2002. The Texas regulations require additional reductions that must
be completed by March 2007. Plans for the Texas units for the period 2004
through 2007 have not been finalized, but have been estimated at $88 million. We
are currently litigating the economic and technical viability of the Texas
post-2004 reduction requirements, but cannot predict the outcome of this
litigation. In addition, the Texas Electric Restructuring Law created a program
mandating air emissions reductions for some generating facilities of our
Electric Generation business segment. The Texas Electric Restructuring Law
provides for stranded cost recovery of costs associated with this obligation
incurred before May 1, 2003. For additional information regarding the Texas
Electric Restructuring Law, please read "-- Regulation -- State and Local
Regulations -- Texas -- Electric Operations -- The Texas Electric Restructuring
Law" in Item 1 of this Form 10-K and Note 4(a) to our consolidated financial
statements. For additional information regarding environmental regulation of air
emissions, please read "Business -- Environmental Matters -- Air Emissions" in
Item 1 of this Form 10-K.

Site Remediation Expenditures. From time to time we have received notices
from regulatory authorities or others regarding our status as a potentially
responsible party in connection with sites found to require remediation due to
the presence of environmental contaminants. Based on currently available
information, we believe that remediation costs will not materially affect our
financial position, results of operations or cash flows. There can be no
assurance, however, that future developments, including additional information
about existing sites or the identification of new sites, will not require
material revisions to our estimates. For

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information about specific sites that are the subject of remediation claims,
please read Note 14(f) to our consolidated financial statements.

Water, Mercury and Other Expenditures. As discussed under
"Business -- Environmental Matters -- Water Issues" in Item 1 of this Form 10-K,
regulatory authorities are in the process of implementing regulations and
quality standards in connection with the discharge of pollutants into waterways.
Once these regulations and quality standards are enacted, we will be able to
determine if our operations are in compliance, or if we will have to incur costs
in order to comply with the quality standards and regulations. Until that time,
however, we are not able to predict the amount of these expenditures, if any. To
date, however, our expenditures associated with respect to permits,
registrations and authorizations for operation of facilities under the statutes
regulating the discharge of pollutants into surface water have not been
material. With regard to mercury remediation and other environmental matters,
such as the disposal of solid wastes, our expenditures have not been, and are
not expected to be material, based on our experiences and that of others in our
industries. Please read "Business -- Environmental Matters -- Mercury
Contamination" and "-- Other" in Item 1 of this Form 10-K.

OTHER FACTORS

Terrorist Attacks and Acts of War. We are currently unable to measure the
ultimate impact of the terrorist attacks of September 11, 2001 on our industry
and the United States economy as a whole. The uncertainty associated with the
retaliatory military response of the United States and other nations and the
risk of future terrorist activity may impact 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 on which we rely could be directly or indirectly harmed by future
terrorist activity. The occurrence or risk of occurrence of future terrorist
attacks or related acts of war could also adversely affect the United States
economy. A lower level of economic activity could result in a decline in energy
consumption which could adversely affect our revenues, margins and limit our
future growth prospects. The occurrence or risk of occurrence could also
increase pressure to regulate or otherwise limit the prices charged for
electricity or gas. Also, these risks could cause instability in the financial
markets and adversely affect our ability to access capital.

Environmental Regulation. Our Electric Generation and Wholesale Energy
business segments 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 additional costs to comply
with these requirements. If we fail to comply with these requirements, we could
be subject to civil or criminal liability and fines. Existing environmental
regulations could be revised or reinterpreted, new laws and regulations could be
adopted or become applicable to us or our facilities, and future changes in
environmental laws and regulations could occur, including potential regulatory
and enforcement developments related to air emissions. If any of these events
occur, our business, operations and financial condition could be adversely
affected.

We may not be able to obtain or maintain from time to time all required
environmental regulatory approvals. If there is a delay in obtaining any
required environmental regulatory approvals or if we fail to obtain and comply
with them, the operation of our facilities could be prevented or become subject
to additional costs.

We are generally responsible for all on-site liabilities associated with
the environmental condition of our power generation facilities which we have
acquired and developed, regardless of when the liabilities arose and whether
they are known or unknown. These liabilities may be substantial.

Holding Company Organizational Structure. We are a holding company, and we
conduct a significant portion of our operations through our subsidiaries. After
the Restructuring and Distribution, CenterPoint Energy will be a holding company
that conducts substantially all of its operations through its respective
subsidiaries. CenterPoint Energy's only significant assets will be the capital
stock of its subsidiaries, and its subsidiaries will generate substantially all
of CenterPoint Energy's operating income and cash flow. As a result, dividends
or advances from CenterPoint Energy's subsidiaries will be the principal source
of funds
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necessary to meet its debt service obligations. In some circumstances,
contractual provisions (including terms of indebtedness) or laws, as well as the
financial condition or operating requirements of our respective subsidiaries,
may limit our or CenterPoint Energy's ability to obtain cash from our respective
subsidiaries. As of December 31, 2001, all conditions on payments to us by our
subsidiaries that are contained in existing agreements were satisfied. After the
Distribution, Reliant Resources will also be a holding company that conducts all
of its operations through its subsidiaries and will be subject to similar
structural limitations as described above with respect to CenterPoint Energy.
For information regarding payment of dividends please read Item 5 of this Form
10-K.

In addition, the ability of REMA, a Reliant Resources subsidiary that owns
some of the power generation facilities in our Northeast regional portfolio, to
pay dividends or make restricted payments to Reliant Resources is restricted
under the terms of three lease agreements under which we lease all or an
undivided interest in these generating facilities. These agreements allow our
Mid-Atlantic subsidiary to pay dividends or make restricted payments only if
specified conditions are satisfied, including maintaining specified fixed charge
coverage ratios.

Liquidity Concerns. For a discussion of factors affecting our sources of
cash and liquidity, please read "-- Liquidity and Capital Resources -- Future
Sources and Uses of Cash."

LIQUIDITY AND CAPITAL RESOURCES

HISTORICAL CASH FLOWS

The net cash provided by/used in operating, investing and financing
activities for 1999, 2000 and 2001 is as follows (in millions):

CASH PROVIDED BY OPERATING ACTIVITIES

Net cash provided by operations in 2001 increased $369 million compared to
2000. This increase primarily resulted from:

- an increase in recovered fuel costs by our Electric Operations business
segment;

- a decrease in net margin deposits on energy trading activities as a
result of reduced commodity volatility and relative price levels of
natural gas and power compared to the fourth quarter of 2000; and

- an increase in operating margins from Wholesale Energy's power generation
operations.

This increase is partially offset by:

- a prepayment of a lease obligation related to REMA sale/leaseback
transactions (please read Note 14(b) to our consolidated financial
statements);

- an increase in restricted cash related to our REMA operations;

- an increase in deposits in a collateral account related to an equipment
financing structure (please read Note 14(l) to our consolidated financial
statements);

- an increase in costs related to our Retail Energy business segments'
increased staffing levels and preparation for competition in the retail
electric market in Texas;

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- reduced cash flows from our European Energy business segment primarily
resulting from a decline in electric power generation gross margins as
the Dutch electric market was completely opened to wholesale competition
on January 1, 2001; and

- other changes in working capital.

Net cash provided by operations in 2000 increased $240 million compared to
1999. This increase primarily resulted from:

- proceeds from the sale of an investment in marketable debt securities by
REPGB;

- improved operating results of our Wholesale Energy business segment's
California generating facilities;

- incremental cash flows provided by REPGB, acquired in the fourth quarter
of 1999;

- cash flows from REMA, acquired in the second quarter of 2000; and

- increased sales from our Electric Operations business segment due to
growth in usage and number of customers.

These increases were partially offset by increases in under-recovered fuel
costs of our Electric Operations business segment and Wholesale Energy's net
margin deposits on energy trading activities.

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities decreased $1.2 billion during 2001
compared to 2000. This decrease was primarily due to no acquisitions being made
in 2001 as compared to the $2.1 billion acquisition of REMA in 2000, and the
funding of the remaining $982 million purchase obligation for REPGB in 2000.

These decreases were partially offset by additional capital expenditures in
2001 of $211 million primarily related to our Electric Operations business
segment, proceeds of $1.0 billion received in 2000 from the REMA sale-leaseback
and $642 million received in 2000 from the sale of our Latin America assets, net
of investments and advances.

Net cash used in investing activities increased $416 million during 2000
compared to 1999. This increase was primarily due to:

- the funding of the remaining purchase obligation for REPGB of $982
million on March 1, 2000;

- the acquisition of REMA for $2.1 billion on May 12, 2000; and

- increased capital expenditures related to the construction of domestic
power generation projects.

Proceeds of $1.0 billion from the REMA sale-leaseback in 2000, the sale of
a substantial portion of our Latin America investments in 2000 and the purchase
of $537 million of AOL Time Warner securities in 1999 partially offset these
increases.

CASH PROVIDED BY FINANCING ACTIVITIES

Cash flows provided by financing activities decreased $1.7 billion in 2001
compared to 2000, primarily due to a decline in short term borrowings partially
offset by $1.7 billion in net proceeds from the initial public offering of
Reliant Resources.

Cash flows provided by financing activities increased $209 million in 2000
compared to 1999, primarily due to an increase in short-term borrowings
partially offset by a decline in proceeds from long-term debt and the sale of
trust preferred securities.

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FUTURE SOURCES AND USES OF CASH

The following table sets forth our consolidated capital requirements for
2001, and estimates of our consolidated capital requirements for 2002 through
2006 (in millions).

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

(1) Beginning in 2002, the Electric Operations business segment will be replaced
by the Electric Transmission and Distribution business segment and the
Electric Generation business segment. In December 2001, we formed Texas
Genco, LP, a Texas limited partnership, as an indirect, wholly owned
subsidiary (Texas Genco). It is anticipated that the majority interest in
Texas Genco held by CenterPoint Energy will be purchased by Reliant
Resources in early 2004 pursuant to the terms of an option that Reliant
Resources holds, or will otherwise be sold to one or more other parties. The
Texas generation operations referred to as our "Texas generation business"
throughout this Form 10-K will be reported as the "Electric Generation"
business segment beginning in 2002. Capital requirements for current
generation operations of Reliant Energy HL&P are included in the Electric
Generation business segment. Capital requirements for the remainder of
Reliant Energy HL&P's operations are included in the Electric Transmission
and Distribution business segment.

(2) Capital requirements for 2002 include $2.9 billion for the acquisition of
Orion Power by Reliant Resources.

(3) We currently estimate the capital expenditures by off-balance sheet special
purpose entities to be $704 million, $343 million, $163 million and $48
million in 2002, 2003, 2004 and 2005, respectively. Capital expenditures for
these projects have been excluded from the table above. Please read "Future
Sources and Uses -- Reliant Resources (unregulated businesses),"
"-- Off-Balance Sheet Transactions -- Construction Agency Agreements" and
"-- Equipment Financing Structure" below for additional information.

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The following table sets forth estimates of our consolidated contractual
obligations as of December 31, 2001 to make future payments for 2002 through
2006 and thereafter (in millions):

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(1) For a discussion of short-term and long-term debt, please read Note 10 to
our consolidated financial statements.

(2) For a discussion of trust preferred securities, please read Note 11 to our
consolidated financial statements.

(3) For a discussion of REMA and other operating leases, please read Note 14(b)
to our consolidated financial statements.

(4) For a discussion of trading and marketing liabilities and non-trading
derivative liabilities, please read Note 5 to our consolidated financial
statements.

(5) For a discussion of other commodity commitments, please read Note 14(a) to
our consolidated financial statements. Excluded from the table above are
amounts to be acquired by Reliant Resources from Texas Genco under purchase
power and electric capacity commitments of $213 million and $57 million in
2002 and 2003, respectively.

The following discussion regarding future sources and uses of cash over the
next twelve months is presented separately for our regulated businesses and
unregulated businesses consistent with the separate liquidity plans that our
management has developed for CenterPoint Energy and Reliant Resources. We
believe that our borrowing capability combined with cash flows from operations
will be sufficient to meet the operational needs of our businesses for the next
twelve months.

RELIANT ENERGY (TO BECOME CENTERPOINT ENERGY SUBSEQUENT TO THE RESTRUCTURING)

Our liquidity and capital requirements will be affected by:

- capital expenditures;

- debt service requirements;

- the repayment of notes payable to Reliant Resources;

- the reduction in, and elimination of, programs under which we have sold
customer accounts receivable;

- proceeds from the expected initial public offering of Texas Genco;

- various regulatory actions; and

- working capital requirements.

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We expect capital requirements to be met with cash flows from operations,
as well as proceeds from debt offerings and other borrowings. The following
table sets forth our capital requirements for 2001, and estimates of our capital
requirements for 2002 through 2006 (in millions):

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(1) Beginning in 2002, the Electric Operations business segment will be replaced
by the Electric Transmission and Distribution business segment and the
Electric Generation business segment. It is anticipated that the majority
interest in Texas Genco held by CenterPoint Energy will be purchased by
Reliant Resources in early 2004 pursuant to the terms of an option that
Reliant Resources holds, or will otherwise be sold to one or more other
parties. The Texas generation operations referred to as our "Texas
generation business" throughout this Form 10-K will be reported as the
"Electric Generation" business segment beginning in 2002. Capital
requirements for current generation operations of Reliant Energy HL&P are
included in the Electric Generation business segment. Capital requirements
for the remainder of Reliant Energy HL&P's operations are included in the
Electric Transmission and Distribution business segment.

The following table sets forth estimates of our contractual obligations to
make future payments for 2002 through 2006 and thereafter (in millions):

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

(1) For a discussion of other operating leases, please read Note 14(b) to our
consolidated financial statements.

(2) For a discussion of other commodity commitments, please read Note 14(a) to
our consolidated financial statements.

Credit Facilities. As of December 31, 2001, we had credit facilities,
including facilities of Houston Industries FinanceCo LP (FinanceCo) and RERC
Corp., that provided for an aggregate of $5.4 billion in committed credit. As of
December 31, 2001, $3.1 billion was outstanding under these facilities including
$2.5 billion of commercial paper supported by the facilities, borrowings of $636
million and letters of credit of $2.5 million.

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The following table summarizes amounts available under these credit
facilities at December 31, 2001 and commitments expiring in 2002 (in millions):

The RERC Corp. receivables facility was reduced from $350 million to $150
million in January 2002. Proceeds for the repayment of $196 million of advances
under the facility were obtained from the liquidation of a temporary investment
and the sale of commercial paper.

The revolving credit facilities contain various business and financial
covenants requiring us to, among other things, maintain leverage (as defined in
the credit facilities) below specified ratios. We are in compliance with the
covenants under all of these credit agreements. We do not expect these covenants
to materially limit our ability to borrow under these facilities. For additional
discussion, please read Note 10(a) to our consolidated financial statements.

The revolving credit facilities support commercial paper programs. The
maximum amount of outstanding commercial paper of an issuer is limited to the
amount of the issuer's aggregate revolving credit facilities less any direct
loans or letters of credit obtained under its revolvers. Due to an inability to
consistently satisfy all short-term borrowing needs by issuing commercial paper,
short-term borrowing needs have been met with a combination of commercial paper
and bank loans. The extent to which commercial paper will be issued in lieu of
bank loans will depend on market conditions and our credit ratings.

Pursuant to the terms of the existing agreements (but subject to certain
conditions precedent which we anticipate will be met) the revolving credit
agreements aggregating $4.3 billion of FinanceCo will terminate and CenterPoint
Energy revolving credit facilities of the same amount and with the same
termination dates will become effective on the date of Restructuring.

To the extent that we continue to need access to current amounts of
committed credit prior to the Distribution, we expect to extend or replace the
credit facilities on a timely basis. The terms of any new credit facilities are
expected to be adversely affected by the leverage of Reliant Energy, the amount
of bank capacity utilized by Reliant Energy, any delay in the date of
Restructuring and Distribution and conditions in the bank market. These same
factors are expected to make the syndication of new credit facilities more
difficult in the future. Proceeds from any issuance of debt in the capital
markets are expected to be used to retire a portion of our short-term debt and
reduce our need for committed revolving credit facilities.

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Shelf Registrations. The following table lists shelf registration
statements existing at December 31, 2001 for securities expected to be sold in
public offerings.

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(1) The amount reflects the principal amount of debt securities, the aggregate
liquidation value of trust preferred securities and the estimated market
value of common stock based on the number of shares registered as of
December 31, 2001 and the closing market price of Reliant Energy common
stock on that date.

We expect to register $2.5 billion of debt securities some or all of which
may be issued either by Reliant Energy prior to the Restructuring or by
CenterPoint Energy after the Restructuring. Proceeds from the sale of these debt
securities are expected to be used to repay short-term borrowings. The amount
actually issued will depend on interest rates and other market conditions.

Debt Service Requirements. Excluding the repayments expected to be made on
the transition bonds described in Note 4(a) to our consolidated financial
statements, we have maturing long-term debt in 2002 aggregating $500 million.
Maturing debt is expected to be refinanced with new debt. In addition, Reliant
Energy has $175 million of 5.20% pollution control bonds that are expected to be
remarketed in 2002 as multi-year fixed-rate debt.

Debt service requirements will be affected by the overall level of interest
rates in 2002 and credit spreads applicable to the various issuers of debt in
2002. Up to $2.7 billion of long-term debt is expected to be issued or
remarketed in 2002 and we expect to have large amounts of short-term
floating-rate debt in 2002. At December 31, 2001, we had entered into five year
forward starting interest rate swaps having an aggregate notional amount of $500
million to hedge the interest rate on an anticipated 2002 offering of five year
notes. The weighted average rate on the swaps was 5.6%. At December 31, 2001, we
also had entered into interest rate swaps to fix the rate on $1.8 billion of our
floating rate debt. The weighted average rate on these swaps was 4.1% and the
swaps expire in 2002 and 2003. While we have, in some instances, hedged our
exposure to changes in interest rates by entering into interest rate swaps, the
swaps leave us exposed to changes in our credit spread relative to the market
indices reflected in the swaps.

Money Fund. We have a "money fund" through which Reliant Energy and
participating subsidiaries can borrow or invest on a short-term basis. Funding
needs are aggregated and external borrowing or investing is based on the net
cash position. The money fund's net funding requirements are generally met with
commercial paper and/or bank loans. At December 31, 2001, Reliant Resources had
$390 million invested in the money fund. Reliant Resources is expected to
withdraw its investment from the money fund on or before the Distribution. Funds
for repayment of the notes payable to Reliant Resources will be obtained from
bank loans or the issuance of commercial paper.

Environmental Issues. We anticipate investing up to $397 million in
capital and other special project expenditures between 2002 and 2006 for
environmental compliance. Of this amount, we anticipate expenditures to be
approximately $234 million and $132 million in 2002 and 2003, respectively.
These environmental compliance expenditures are included in the capital
requirements table presented above. For additional information related to
environmental issues, please read Note 14(f) to our consolidated financial
statements.

Initial Public Offering of Texas Genco. In 2002, approximately 20% of
Texas Genco is expected to be sold in an initial public offering or distributed
to holders of CenterPoint Energy common stock. The decision

107

whether to distribute the Texas Genco shares or to sell the shares in an initial
public offering will depend on numerous factors, including market conditions.
Proceeds, if any, are expected to be used to retire short-term debt.

Fuel Filing. As of December 31, 2000 and 2001, Reliant Energy HL&P was
under-collected on fuel recovery by $558 million and $200 million, respectively.
In two separate filings with the Texas Utility Commission in 2000, Reliant
Energy HL&P received approval to implement fuel surcharges to collect the
under-recovery of fuel expenses, as well as to adjust the fuel factor to
compensate for significant increases in the price of natural gas. Under the
Texas Electric Restructuring Law, a final settlement of these stranded costs
will occur in 2004.

Reliant Energy HL&P Rate Matters. The October 3, 2001 Order established
the transmission and distribution rates that became effective in January 2002.
The Texas Utility Commission determined that Reliant Energy HL&P had
overmitigated its stranded costs by redirecting transmission and distribution
depreciation and by accelerating depreciation of generation assets as provided
under the Transition Plan and Texas Electric Restructuring Law. In this final
order, Reliant Energy HL&P is required to reverse the amount of redirected
depreciation and accelerated depreciation taken for regulatory purposes as
allowed under the Transition Plan and the Texas Electric Restructuring Law. Per
the October 3, 2001 Order, our Electric Operations business segment recorded a
regulatory liability to reflect the prospective refund of the accelerated
depreciation. Our Electric Operations business segment began refunding excess
mitigation credits with the January 2002 unbundled bills, to be refunded over a
seven year period. The annual cash flow impact of the reversal of both
redirected and accelerated depreciation is a decrease of approximately $225
million. Under the Texas Electric Restructuring Law, a final settlement of these
stranded costs will occur in 2004. For further discussion, please read Note 4(a)
to our consolidated financial statements.

In addition to the above factors, our liquidity and capital requirements
could be affected by:

- a downgrade in credit ratings;

- the need to provide cash collateral in connection with trading
activities;

- various regulatory actions; and

- funding of our pension plan.

Impact on Liquidity of a Downgrade in Credit Ratings. At December 31,
2001, Moody's Investors Service, Inc. (Moody's), Standard & Poor's, a division
of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned the
following credit ratings to senior debt of Reliant Energy and certain
subsidiaries:

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

(1) A "stable" outlook from Moody's indicates that Moody's does not expect to
put the rating on review for an upgrade or downgrade within 18 months from
when the outlook was assigned or last affirmed.

(2) A "stable" outlook from S&P indicates that the rating is not likely to
change over the intermediate to longer term.

(3) A "negative" watch from Fitch signals that the rating may be downgraded or
affirmed in the near term. Fitch has indicated that the Reliant Energy
senior secured debt ratings will change from A- to BBB+

108

upon the distribution of Reliant Resources shares and that the RERC Corp.
senior debt ratings will change from BBB+ to BBB upon the distribution of
Reliant Resources shares.

(4) A "stable" outlook from Fitch signals that the medium term view of the
credit trend of an issuer is stable rather than positive or negative.

We cannot assure you 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 agency. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to access capital on acceptable terms.

A decline in credit ratings would increase commitment fees and borrowing
costs under our existing bank credit facilities. A decline in credit ratings
would also adversely affect our ability to issue commercial paper and the
interest rates applicable to commercial paper. Increased direct borrowings under
our bank credit facilities could also result in the payment of usage fees under
the terms of these arrangements. A decline in credit ratings would also increase
the interest rate on long-term debt to be issued in the capital markets.

Our revolving credit agreements are broadly syndicated committed facilities
which contain "material adverse change" clauses that could impact our ability to
borrow under these facilities. The "material adverse change" clauses generally
relate to our ability to perform our obligations under the agreements.

The $150 million receivables facility of RERC Corp. requires the
maintenance of credit ratings of at least BB from S&P and Ba2 from Moody's.
Advances under the facility would need to be repaid in the event a credit rating
fell below the threshold.

As previously discussed, bank facilities of FinanceCo are expected to be
converted into bank facilities of CenterPoint Energy on the date of
Restructuring. There is a ratings-related condition precedent to the conversion
from the existing FinanceCo bank credit facilities (totaling $4.3 billion) to
facilities under which CenterPoint Energy will become the obligor. The condition
precedent requires that CenterPoint Energy be rated at least BBB by S&P and Baa2
by Moody's at the time of Restructuring. We believe that we could obtain a
waiver of this condition, if necessary. However, if we were unable to obtain
such a waiver, the facilities would remain obligations of FinanceCo until the
earlier of 90 days after the date of Restructuring or the expiration of the
facilities in July 2002, subject to compliance with applicable covenants.

Similar ratings-related provisions govern the transfer to CenterPoint
Energy of rights and obligations under certain interest rate swap agreements
entered into by Reliant Energy and Houston Industries FinanceCo LP to effect
interest rate hedging. Interest rate swaps having an aggregate notional amount
of $1.5 billion as of December 31, 2001 contained such provisions. These
agreements are generally assumable by CenterPoint Energy without the consent of
the counterparties, provided that CenterPoint Energy's rating is at least BBB-
from S&P or Baa3 from Moody's. We believe that we could obtain the consent of
the counterparties if necessary, but if we were unable to do so, the swaps would
remain obligations of the current counterparties until their expiration. All of
the swaps terminate no later than 2004.

As discussed in Note 8 to our consolidated financial statements, each ZENS
note is exchangeable at the holder's option at any time for an amount of cash
equal to 95% of the market value of the reference shares of AOL TW common stock
attributable to each ZENS note. If our credit worthiness were to drop such that
ZENS note holders felt our liquidity was adversely affected or the market for
the ZENS notes was to become illiquid, some ZENS holders might decide to
exchange their ZENS for cash. Funds for the payment of cash upon exchange could
be obtained from the sale of the AOL TW common stock that we own or from other
sources. We own shares of AOL TW common stock equal to 100% of the "reference
shares" used to calculate our obligation to the holders of the ZENS notes.

Certain of the contracts that we have entered into on behalf of Texas Genco
for the sale of capacity from our Texas generation business contain requirements
obligating us to put up additional security in the event that our rating or the
rating of CenterPoint Energy falls below BBB- from S&P or Baa3 from Moody's.
These

109

requirements stem from reciprocal provisions under power purchase and sale
agreements with purchasers of capacity to be delivered in various monthly,
12-month or 24-month periods or "strips" until December 2003. If a downgrade
below either of these levels were to occur, the purchasers would be entitled to
call upon us to provide collateral to secure our obligations in a "commercially
reasonable" amount within three business days of notice. Failure to provide this
collateral entitles the other party to terminate the agreement and unwind all
pending transactions under the agreement. Our Texas generation business is
always the seller under these agreements, and its performance obligation in all
cases is one of delivery, rather than payment. Accordingly, it is difficult to
quantify the amount of collateral we would be required to provide as assurance
for these delivery obligations. We believe that any such quantification should
be predicated on our Texas generation business' ultimate exposure under these
agreements. Our Texas generation business has no exposure until (1) it cannot
deliver power as called for in the agreements and (2) the market cost of
replacement power has increased above the contract price. In the unlikely event
that our Texas generation business could not deliver any of this power as
agreed, we estimate that our Texas generation business' total exposure under
these contracts at December 31, 2001 was approximately $73 million.

As part of its normal business operations, our Texas generation business
has also entered power purchase and sale agreements with counterparties that
contain similar provisions that require a party to provide additional collateral
on three business days notice when that party's rating falls below BBB- from S&P
or Baa3 from Moody's. Our Texas generation business both buys and sells under
these agreements, and we use them whenever possible either to locate less
expensive power than our Texas generation business' marginal cost of generation
or to sell power to another party who is willing to pay more than our marginal
cost of generation. Our Texas generation business' purchases for 2001 under
agreements with ratings triggers were approximately $23 million and its sales
under those agreements were approximately $8 million. This compares to total
purchases of approximately $125 million and total sales of approximately $32
million under all buy/sell agreements in 2001. We believe that this risk is
mitigated because most of the purchases and sales under these arrangements take
place over relatively short time periods; typically, these transactions are for
one-day deliveries and rarely exceed periods of one month.

Entex Gas Resources Corp., a wholly owned subsidiary of RERC Corp.,
provides comprehensive natural gas sales and services to industrial and
commercial customers who are primarily located within or near the territories
served by our pipelines and distribution subsidiaries. In order to hedge its
exposure to natural gas prices, Entex Gas Resources Corp. will have agreements
with provisions standard to the industry that establish credit thresholds and
then require a party to provide additional collateral on two business days'
notice when that party's rating or the rating of a credit support provider for
that party (RERC Corp. in this case), falls below those levels. The senior
unsecured debt of RERC Corp. is currently rated BBB+ by S&P and Baa2 by Moody's.
Based on these ratings, we estimate that unsecured credit limits extended to
Entex Gas Resources Corp. by counterparties could aggregate $250 million;
however, utilized credit capacity would typically be lower.

Regulatory Matters. Our liquidity can be impacted by regulatory actions
affecting our Electric Operations and our Natural Gas Distribution business
segments. For further discussion, please read Note 4 to our consolidated
financial statements.

Treasury Stock Purchases. As of December 31, 2001, we were authorized
under our common stock repurchase program to purchase an additional $271 million
of our common stock. Our purchases under our repurchase program depend on market
conditions, might not be announced in advance and may be made in open market or
privately negotiated transactions. CenterPoint Energy has no current plans to
engage in a significant stock buy-back program, but may seek to repurchase
shares in the open market for use in various benefit and employee compensation
plans, or to maintain a targeted balance of outstanding shares to the extent
that original issue stock is used for such purposes.

Pension and Postretirement Benefits Funding. We make contributions to
achieve adequate funding of Company sponsored pension and postretirement
benefits in accordance with applicable regulations and rate orders. Based on
current estimates, we expect to have funding requirements, excluding Reliant
Resources, of

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approximately $330 million for the period 2002-2006. These anticipated funding
requirements are not reflected in the table of contractual obligations presented
above.

RELIANT RESOURCES -- UNREGULATED BUSINESSES

Liquidity and capital requirements for these businesses are affected
primarily by the results of operations, capital expenditures, debt service
requirements and working capital needs. Reliant Resources expects to grow these
businesses through the construction of new generation facilities and the
acquisition of generation facilities, the expansion of their energy trading and
marketing activities and the expansion of their energy retail business. Reliant
Resources expects any resulting capital requirements to be met with cash flows
from operations, and proceeds from debt and equity offerings, project
financings, securitization of assets, other borrowings and off-balance sheet
financings. Additional capital expenditures, some of which may be substantial,
depend to a large extent upon the nature and extent of future project
commitments which are discretionary. In the discussion below, Reliant Resources
has provided several tables outlining their expected future capital requirements
by category of expenditure followed by more detailed descriptions of the most
significant of their currently known future capital requirements and
descriptions of known uncertainties that could impact these items.

The following table sets forth Reliant Resources' consolidated capital
requirements for 2001, and estimates of their consolidated capital requirements
for 2002 through 2006 (in millions).

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(1) Capital requirements for 2002 includes $2.9 billion for the acquisition of
Orion Power.

(2) In connection with Reliant Resources' separation from Reliant Energy,
Reliant Energy has granted Reliant Resources an option, subject to
completion of the Distribution, to purchase the majority interest in Texas
Genco held by CenterPoint Energy in January 2004. This option may be
exercised between January 10, 2004 and January 24, 2004. The purchase of
Texas Genco has been excluded from the above table. For additional
information regarding this option to purchase Texas Genco, please read Note
4(b) to our consolidated financial statements.

(3) Reliant Resources currently estimates the capital expenditures by
off-balance sheet special purpose entities to be $704 million, $343 million,
$163 million and $48 million in 2002, 2003, 2004 and 2005, respectively.
Capital expenditures for these projects have been excluded from the table
above. Please read "Future Sources and Uses -- Reliant
Resources -- unregulated businesses," "-- Off-Balance Sheet
Transactions -- Construction Agency Agreements" and "-- Equipment Financing
Structure" below for additional information.

Acquisition of Orion Power. On February 19, 2002, Reliant Resources
acquired all of the outstanding shares of common stock of Orion Power for $26.80
per share in cash for an aggregate purchase price of $2.9 billion. As of
February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of cash acquired, some of which is restricted pursuant to debt
covenants). Reliant Resources funded the purchase of Orion Power with a $2.9
billion credit facility (Orion Bridge Facility) and $41 million of cash on hand.
Please read "-- Consolidated Sources of Cash -- Orion Bridge Facility" for
further information.

Generating Projects. As of December 31, 2001, Reliant Resources had three
generating facilities under construction. Total estimated costs of constructing
these facilities are $1.1 billion, including $304 million in commitments for the
purchase of combustion turbines. As of December 31, 2001, Reliant Resources had

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incurred $690 million of the total projected costs of these projects, which were
funded primarily from equity and debt facilities. In addition, Reliant Resources
has options to purchase additional combustion turbines for a total estimated
cost of $42 million, but is actively attempting to market these turbines, having
determined that they are in excess of their current needs. In addition to these
facilities, Reliant Resources is constructing facilities as construction agents
under the construction agency agreements under synthetic leasing arrangements,
which permit them to lease or buy each of these facilities at the conclusion of
their construction. For more information regarding the construction agency
agreements, please read "-- Off Balance Sheet Transactions -- Construction
Agency Agreements."

Environmental Expenditures. Reliant Resources anticipates investing up to
$135 million in capital and other special project expenditures between 2002 and
2006 for environmental compliance, totaling approximately $53 million, $20
million, $9 million, $29 million and $24 million in 2002, 2003, 2004, 2005 and
2006, respectively, which is included in the above table. Additionally,
environmental capital expenditures for the recently acquired Orion Power assets
were estimated by Orion Power to be approximately $241 million over the same
time period. Reliant Resources is currently reviewing Orion Power's estimates.

The following table sets forth estimates of Reliant Resources' consolidated
contractual obligations as of December 31, 2001 to make future payments for 2002
through 2006 and thereafter (in millions):

Long-term debt obligations as of December 31, 2001, include $829 million of
borrowings under credit facilities that have been classified as long-term debt,
based upon the availability of committed credit facilities and management's
intention to maintain these borrowings in excess of one year.

As of December 31, 2001, Reliant Resources has issued $396 million of
letters of credit, of which $345 million were issued under two credit facilities
expiring in 2003 and $51 million were issued under a credit facility expiring in
2004.

Mid-Atlantic Assets Lease Obligation. In August 2000, Reliant Resources'
subsidiaries entered into separate sale-leaseback transactions with each of the
three owner-lessors for their respective 16.45%, 16.67% and 100% interests in
the Conemaugh, Keystone and Shawville generating stations, respectively, which
Reliant Resources acquired as part of the REMA acquisition. These lessees lease
an interest in each facility from each owner-lessor under a facility lease
agreement. The equity interests in all the subsidiaries of REMA are pledged as
collateral for REMA's lease obligations. In addition, the subsidiaries have
guaranteed the lease obligations. The lease documents contain restrictive
covenants that restrict REMA's ability to, among other things, make dividend
distributions unless REMA satisfies various conditions. The covenant restricting
dividends would be suspended if the direct or indirect parent of REMA, meeting
specified criteria, including having a credit rating on its long-term unsecured
senior debt of at least BBB from Standard & Poor's and Baa2 from Moody's,
guarantees the lease obligations. For additional discussion of these lease
transactions, please read Notes 3(a) and 14(b) to our consolidated financial
statements. Reliant Resources expects to make lease

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payments through 2029 under these leases, with total cash payments of $1.6
billion. The lease terms expire in 2034. During 2000 and 2001, cash lease
payments totalled $1 million and $259 million, respectively.

Other Operating Lease Commitments. For a discussion of other operating
leases, please read Note 14(b) to our consolidated financial statements.

Other Commodity Commitments. For a discussion of other commodity
commitments, please read Note 14(a) to our consolidated financial statements.

Naming Rights to Houston Sports Complex. In October 2000, Reliant
Resources acquired the naming rights for the new football stadium for the
Houston Texans, the National Football League's thirty-second franchise. The
agreement extends for 31 years. The aggregate undiscounted cost of the naming
rights under this agreement is expected to be $300 million. Starting in 2002,
when the new stadium is operational, Reliant Resources will pay $10 million each
year through 2032 for annual advertising under this agreement. For additional
information on the naming rights agreement, please read Note 14(d) to our
consolidated financial statements.

Payment to Reliant Energy. To the extent that Reliant Resources' price for
providing retail electric service to residential and small commercial customers
in Reliant Energy HL&P's historical service territory during 2002 and 2003,
which price is mandated by the Texas Electric Restructuring Law, exceeds the
market price of electricity, Reliant Resources will be required to make a
payment to Reliant Energy in early 2004. Due to the nature of this possible
payment, Reliant Resources currently cannot reasonably estimate this payment,
and accordingly, it is excluded from the above tables.

Treasury Stock Purchases. On December 6, 2001, the Reliant Resources'
board of directors authorized the purchase of up to 10 million additional shares
of common stock through June 2003. Purchases will be made on a discretionary
basis in the open market or otherwise at times and in amounts as determined by
management subject to market conditions, legal requirements and other factors.
Since the date of such authorization through March 28, 2002, Reliant Resources
has not purchased any of these shares of their common stock under this program.

In addition to the capital requirements discussed above, the following
items, among others, could impact future capital requirements for Reliant
Resources.

Downgrade in Credit Rating. In accordance with industry practice, Reliant
Resources has entered into commercial contracts or issued guarantees related to
their trading, marketing and risk management operations that require them to
maintain an investment grade credit rating. If one or more of their credit
ratings decline below investment grade, Reliant Resources may be obligated to
provide additional or other credit support to the guaranteed parties in the form
of a pledge of cash collateral, a letter of credit or other similar credit
support.

Counterparty Credit Risk. Reliant Resources is exposed to the risk that
counterparties who owe them money or physical commodities, such as energy or
gas, as a result of market transactions fail to perform their obligations.
Should the counterparties to these arrangements fail to perform, Reliant
Resources might incur losses if they are forced to acquire alternative hedging
arrangements or replace the underlying commitment at then-current market prices.
In addition, Reliant Resources might incur additional losses to the extent of
amounts, if any, already paid to the defaulting counterparties.

CONSOLIDATED SOURCES OF CASH

Reliant Resources believes that their current level of cash and borrowing
capability, along with their future anticipated cash flows from operations and
assuming successful refinancings of credit facilities as they mature, will be
sufficient to meet the existing operational needs of their business for the next
12 months. If cash generated from operations is insufficient to satisfy their
liquidity requirements, Reliant Resources may seek to sell either equity or debt
securities or obtain additional credit facilities or long-term financings from
financial institutions. In the discussion below, Reliant Resources has provided
a description of the significant

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factors that could impact their cash flows from operations, their currently
available liquidity sources, currently contemplated future liquidity sources and
known uncertainties that could impact these sources.

The following items will affect Reliant Resources' future cash flows from
operations:

Reliant Resources Restricted Cash. Covenants under the Mid-Atlantic assets
lease, discussed above, restrict REMA's ability to make dividend distributions.
The restricted cash is available for REMA's working capital needs and for it to
make future lease payments. As of December 31, 2001, REMA had $167 million of
restricted cash. Reliant Resources currently anticipates that REMA will be able
to satisfy the conditions necessary to distribute these restricted funds in
2002. In addition, the terms of two of their subsidiaries' indebtedness restrict
the subsidiaries' ability to pay dividends or make restricted payments to
Reliant Resources in some circumstances. Specifically, their subsidiary which
holds an electric power generation facility in Channelview, Texas (Channelview)
and their subsidiary which holds an equity investment in the entity owning and
operating an electric power generation facility in Nevada (El Dorado) are each
party to credit agreements used to finance construction of these generating
plants. Both the Channelview credit agreement and the El Dorado credit agreement
allow the respective subsidiary 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. In both
cases, the amount of the dividends or restricted payments that may be paid if
the conditions are met is limited to a specified level and may be paid only from
a particular account.

Orion Power Restricted Cash. Substantially all of Orion Power's operations
are conducted by its subsidiaries. The terms of some of its subsidiaries'
indebtedness restrict the subsidiaries' ability to pay dividends to Orion Power
or Reliant Resources. Restricted funds are available for such subsidiaries to
make debt service payments and to meet their working capital needs. In addition,
covenants under some indebtedness of Orion Power restrict its ability to pay
dividends to Reliant Resources unless Orion Power meets certain conditions,
including the ability to incur additional indebtedness without violating the
required fixed charge coverage ratio of 2.0 to 1.0. A credit facility of Orion
Power also restricts its ability to pay dividends to Reliant Resources unless
the restrictions contained in certain of its subsidiaries' credit agreements
have terminated and no restrictions remain under its credit agreements.

California Trade Receivables. As of December 31, 2001, Reliant Resources
was owed $302 million by Cal ISO, the California Power Exchange (Cal PX) and the
California Department of Water Resources (CDWR) and California Energy Resource
Scheduling for energy sales in the California wholesale market, during the
fourth quarter of 2000 through December 31, 2001 and has recorded an allowance
against such receivables of $68 million. From January 1, 2002 through March 26,
2002, Reliant Resources has collected $45 million of these receivable balances.
For additional information regarding uncertainties in the California wholesale
market, please read Notes 14(f) and 14(g) to our consolidated financial
statements.

Other Items. For other items that may affect our future cash flows from
operations, please read "-- Certain Factors Affecting Our Future Earnings"
related to the Reliant Resources business segments.

The following discussion summarizes Reliant Resources' currently available
liquidity sources and material factors that could impact that availability.

Credit Facilities. The following table provides a summary of the amounts
owed and amounts available under Reliant Resources' various credit facilities
(in millions).

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(1) Excludes $383 million of facilities expiring in November 2002 as borrowings
under such facilities are convertible into a long-term loan.

As of February 19, 2002, Reliant Resources has $2.9 billion of credit
facilities which will expire in 2002. To the extent that they continue to need
access to this amount of committed credit, Reliant Resources expects to extend
or replace these facilities. The current credit environment currently impacting
their industry may require their future facilities to include terms that are
more restrictive or burdensome or at higher borrowing rates than those of their
current facilities.

Reliant Resources Credit Facilities Covenants. As of December 31, 2001,
Reliant Resources, including certain of their subsidiaries, had committed credit
facilities of $5.6 billion. Of these facilities, $5.0 billion contain various
business and financial covenants requiring them to, among other things, maintain
a ratio of net balance sheet debt to the sum of net balance sheet debt,
subordinated affiliate balance sheet debt and stockholders' equity not to exceed
0.60 to 1.00. These covenants are not anticipated to materially restrict Reliant
Resources from borrowing funds or obtaining letters of credit under these
facilities. The remaining credit facilities of $0.6 billion, which were held by
certain of their domestic power generation subsidiaries, contain various
business and financial covenants that are typical for limited or non-recourse
project financings. Such covenants include restrictions on dividends and capital
expenditures, as well as requirements regarding insurance, approval of operating
budgets and commercial contracts. These covenants are not anticipated to
materially restrict Reliant Resources from borrowing funds or obtaining letters
of credit under their credit facilities. None of the above committed bank credit
facilities have any defaults or prepayments triggered by changes in credit
ratings, or are in any way linked to the price of Reliant Resources' common
stock or any other traded instrument.

For additional information regarding the terms and related interest rates
of these credit facilities, please read Note 10 of our consolidated financial
statements.

Orion Power Credit Facilities. The credit facilities of Orion Power and
its subsidiaries contain various business and financial covenants that are
typical for limited or non-recourse project financings. Such covenants include
restrictions on dividends and capital expenditures, as well as requirements
regarding insurance, approval of operating budgets and commercial contracts.
These include covenants that require two of Orion Power's significant
subsidiaries which have credit facilities with outstanding borrowings of $1.6
billion as of December 31, 2001, to, among other things, maintain a debt service
coverage ratio of at least 1.5 to 1.0, and for Orion Power, which has a $75
million credit facility, to, among other things, maintain a debt service
coverage ratio of at least 1.4 to 1.0. One of the subsidiaries may not be able
to meet this debt service coverage ratio for the quarter ended June 30, 2002,
and Orion Power did not meet the debt service coverage ratio for the quarter
ended March 31, 2002. In the event that Orion Power is unable to meet this
financial covenant for a second consecutive fiscal quarter, it would constitute
a default under its credit facility. Reliant Resources currently intends to
arrange for the repayment, refinancing or amendment of these facilities prior to
June 30, 2002. If these facilities are not repaid, refinanced or amended prior
to that date, and if a waiver is required under either or both of these credit
facilities, Reliant Resources believes that they will be able to obtain such a
waiver on or prior to June 30, 2002. Reliant Resources currently has no
assurance that they will be able to obtain such a waiver or amendment from the
respective lender groups if required under either or both of these credit
facilities.

Orion Bridge Facility. In November 2001, Reliant Resources entered into a
$2.2 billion term loan facility to be utilized for the acquisition of Orion
Power. In January 2002, the facility was increased to $2.9 billion. On February
19, 2002, in connection with the Orion Power acquisition Reliant Resources
borrowed $2.9 billion under the Orion Bridge Facility, which is required to be
repaid on or before February 19, 2003.

Potential Future Liquidity Sources. Reliant Resources is currently
considering pursuing the following sources of cash to meet their future capital
requirements.

Commercial Paper Program. Reliant Resources plans to commence a commercial
paper program in 2002, which will be supported by their existing credit
facilities. Although they have not yet determined the size

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of such program, Reliant Resources does not expect that it would exceed $300
million initially, due to market conditions and their current credit ratings. To
the extent that they are not successful in placing commercial paper
consistently, Reliant Resources will borrow directly under their existing credit
facilities.

Debt Securities in the Capital Markets. As part of refinancing the Orion
Bridge Facility, Reliant Resources currently expects that they will issue
various fixed and floating rate debt securities in 2002 having maturities up to
ten years or greater depending upon market conditions. Reliant Resources expects
to offer debt securities in the amount of $2.5 to $3.0 billion, depending on
market conditions. Their ability to complete such debt offerings in the capital
markets will depend on their future performance and prevailing market
conditions. This Form 10-K does not constitute an offer to sell or the
solicitation of an offer to buy debt securities of Reliant Resources or their
subsidiaries.

Settlement of Indemnification of REPGB Stranded Costs. In December 2001,
REPGB and its former shareholders entered into a settlement agreement resolving
the former shareholders' stranded cost indemnity obligations under the purchase
agreement of REPGB. Under the settlement agreement, the former shareholders paid
to REPGB NLG 500 million ($202 million based on an exchange rate of 2.48 NLG per
U.S. dollar as of December 31, 2001) in January and February 2002. In addition,
under the settlement agreement, the former shareholders waived all rights under
the original indemnification agreement to claim distributions from NEA, a 22.5%
owned equity investment. Reliant Resources estimates that there will be future
distributions from 2002 through 2005 from NEA to REPGB totaling approximately
$299 million. For additional information regarding the settlement agreement,
Reliant Resources' investment in NEA and indemnification of district heat
contract obligations, please read Note 14(h) to our consolidated financial
statements.

Factors Affecting Our Sources of Cash and Liquidity. As a result of
several recent events, including the United States economic recession, the price
decline of the common stock of participants in Reliant Resources' industry
sector and the downgrading of the credit ratings of several of Reliant
Resources' significant competitors, the availability and cost of capital for
their business and the businesses of their competitors have been adversely
affected. Any future acquisition or development projects will likely require
Reliant Resources to access substantial amounts of capital from outside sources
on acceptable terms. Reliant Resources may also need external financing to fund
capital expenditures, including capital expenditures necessary to comply with
air emission regulations or other regulatory requirements. If Reliant Resources
is are unable to obtain outside financing to meet their future capital
requirements on terms that are acceptable to them, their financial condition and
future results of operations could be materially adversely affected. In order to
meet their future capital requirements, Reliant Resources may increase the
proportion of debt in their overall capital structure. Increases in their debt
levels may adversely affect their credit ratings thereby increasing the cost of
their debt. In addition, the capital constraints currently impacting their
industry may require Reliant Resources' future indebtedness to include terms
and/or pricing that are more restrictive or burdensome than those of their
current indebtedness. This may negatively impact their ability to operate their
business, or severely restrict or prohibit distributions from their
subsidiaries.

Reliant Resources' ability to arrange financing, including refinancing, and
their cost of capital are dependent on the following factors:

- general economic and capital market conditions;

- maintenance of acceptable credit ratings;

- credit availability from banks and other financial institutions;

- investor confidence in Reliant Resources, their competitors and peer
companies and their wholesale power markets;

- market expectations regarding their future earnings and probable cash
flows;

- market perceptions of Reliant Resources' ability to access capital
markets on reasonable terms;

- the success of current power generation projects;

- the perceived quality of new power generation projects; and

- provisions of relevant tax and securities laws.

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Credit Ratings. Credit ratings for Reliant Resources' senior unsecured
debt are as follows:

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

(1) Fitch assigned a negative rating outlook to reflect its analysis of Reliant
Resources' plan for financing and integrating the acquisition of Orion
Power.

Reliant Resources cannot assure you 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. Reliant Resources notes
that these credit ratings are not recommendations to buy, sell or hold Reliant
Resources' securities and may be revised or withdrawn at any time by a rating
agency. Each rating should be evaluated independently of any other rating. Any
future reduction or withdrawal of one or more of their credit ratings could have
a material adverse impact on Reliant Resources' ability to access capital on
acceptable terms. Reliant Resources has commercial contracts and/or guarantees
related to their trading, marketing and risk management and hedging operations
that require them to maintain an investment grade credit rating. If their credit
rating declines below investment grade, Reliant Resources estimates that they
could be obligated to provide significant credit support to the counterparties
in the form of a pledge of cash collateral, a letter of credit or other similar
credit support.

Furthermore, if their credit ratings decline below an investment grade
credit rating, Reliant Resources' trading partners may refuse to trade with them
or trade only on terms less favorable to them. As of December 31, 2001, Reliant
Resources had $214 million of margin deposits on energy trading and hedging
activities posted as collateral with counterparties. As of December 31, 2001,
Reliant Resources had $1.5 billion available under their credit facilities to
satisfy future commodity obligations.

OFF-BALANCE SHEET TRANSACTIONS

Construction Agency Agreements. In 2001, Reliant Resources, through
several of their subsidiaries, entered into operative documents with special
purpose entities to facilitate the development, construction, financing and
leasing of several power generation projects. The special purpose entities are
not consolidated by Reliant Resources. The special purpose entities have an
aggregate financing commitment from equity and debt participants (Investors) of
$2.5 billion of which the last $1.1 billion is currently available only if the
cash is collateralized. The availability of the commitment is subject to
satisfaction of various conditions, including the obligation to provide cash
collateral for the loans and letters of credit outstanding on November 27, 2004.
Reliant Resources, through several of their subsidiaries, acts as construction
agent for the special purpose entities and is responsible for completing
construction of these projects by December 31, 2004, but Reliant Resources has
generally limited their risk during construction to an amount not in excess of
89.9% of costs incurred to date, except in certain events. Upon completion of an
individual project and exercise of the lease option, their subsidiaries will be
required to make lease payments in an amount sufficient to provide a return to
the Investors. If Reliant Resources does not exercise their option to lease any
project upon its completion, they must purchase the project or remarket the
project on behalf of the special purpose entities. Reliant Resources' ability to
exercise the lease option is subject to certain conditions. Reliant Resources
must guarantee that the Investors will receive an amount at least equal to 89.9%
of their investment in the case of a remarketing sale at the end of
construction. At the end of an individual project's initial operating lease term
(approximately five years from construction completion), Reliant Resources'
subsidiary lessees have the option to extend the lease with the approval of
Investors, purchase the project at a fixed amount equal to the original
construction cost, or act as a remarketing agent and sell the project to an
independent third party. If the lessees elect the remarketing option, they may
be required to make a payment of an amount not to exceed 85% of the project
cost, if the proceeds from remarketing are not sufficient to repay the
Investors. Reliant Resources has guaranteed the performance and payment of their
subsidiaries' obligations during the construction periods and, if the lease
option is exercised, each lessee's obligations during the lease period. At
anytime during the

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construction period or during the lease, Reliant Resources may purchase a
facility by paying an amount approximately equal to the outstanding balance plus
costs. As of December 31, 2001, the special purpose entities had property, plant
and equipment of $428 million and net other assets of $52 million, which were
primarily restricted cash and debt obligations of $465 million. As of December
31, 2001, the special purpose entities had equity from unaffiliated third
parties of $15 million. Reliant Resources currently estimates the aggregate cost
of the three generating facilities that are currently under construction by the
special purpose entities to be approximately $1.8 billion.

Equipment Financing Structure. Reliant Resources, through their
subsidiary, REPG, has entered into an agreement with a bank whereby the bank, as
owner, entered or will enter into contracts for the purchase and construction of
power generation equipment and REPG, or its subagent, acts as the bank's agent
in connection with administering the contracts for such equipment. Under the
agreement, the bank has agreed to provide up to a maximum aggregate amount of
$650 million. REPG and its subagents must cash collateralize their obligation to
administer the contracts. This cash collateral is approximately equivalent to
the total payments by the bank for the equipment, interest and other fees. As of
December 31, 2001, the bank had assumed contracts for the purchase of eleven
turbines, two heat recovery steam generators and one air-cooled condenser with
an aggregate cost of $398 million. REPG, or its designee, has the option at any
time to purchase or, at equipment completion, subject to certain conditions,
including the agreement of the bank to extend financing, to lease equipment, or
to assist in the remarketing of the equipment under terms specified in the
agreement. All costs, including the purchase commitment on the turbines, are the
responsibility of the bank. The cash collateral is deposited by REPG or an
affiliate into a collateral account with the bank and earns interest at the
London inter-bank offered rate (LIBOR) less 0.15%. Under certain circumstances,
the collateral deposit or a portion of it will be returned to REPG or its
designee. Otherwise it will be retained by the bank. At December 31, 2001, REPG
and its subsidiary had deposited $230 million into the collateral account. The
bank's payments for equipment under the contracts totaled $227 million as of
December 31, 2001. 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 our collateral
deposits were returned to Reliant Resources. As of December 31, 2001, there were
equipment contracts with a total contractual obligation of $140 million under
which payments during construction totaled $83 million. Currently this equipment
is not designated for current planned power generation construction projects.
Therefore, Reliant Resources anticipates that it will either purchase the
equipment, assist in the remarketing of the equipment or negotiate to cancel the
related contracts.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the portrayal
of our financial condition and results of operations and requires management to
make difficult, subjective or complex judgments. The circumstances that make
these judgments difficult, subjective and/or complex have to do with the need to
make estimates about the effect of matters that are inherently uncertain.
Estimates and assumptions about future events and their effects cannot be
perceived with certainty. We base our estimates on historical experience and on
various other assumptions that are believed to be reasonable under the
circumstances, the results of which form the basis for making judgments. These
estimates may change as new events occur, as more experience is acquired, as
additional information is obtained and as our operating environment changes.

We believe the following are the most significant estimates used in the
preparation of our consolidated financial statements.

ACCOUNTING FOR RATE REGULATION

SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those costs in rates if
the rates established are designed to recover the costs of providing the
regulated service and if the competitive environment makes it probable that such
rates can be charged and collected. Our rate-

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regulated businesses follow the accounting and reporting requirements of SFAS
No. 71. Certain expenses and revenues subject to utility regulation or rate
determination normally reflected in income are deferred on the balance sheet and
are recognized in income as the related amounts are included in service rates
and recovered from or refunded to customers. The total amounts of regulatory
assets and liabilities reflected in the Consolidated Balance Sheets are $1.9
billion and $237 million at December 31, 2000, and $3.3 billion and $1.4 billion
at December 31, 2001, respectively.

Application of SFAS No. 71 to the generation portion of our business was
discontinued as of June 30, 1999. Only the electric transmission and
distribution business, the natural gas distribution companies and one of our
interstate pipelines are subject to SFAS No. 71 after January 1, 2002. We have
recorded regulatory assets and liabilities related to stranded costs associated
with our electric generation operations. Under the Texas Electric Restructuring
Law, a final settlement of these stranded costs will occur in 2004. In the event
that regulation significantly changes the probability for us to recover our
costs in the future, a write-down of all or a portion of our existing regulatory
assets and liabilities could result.

IMPAIRMENT OF LONG-LIVED ASSETS AND ASSETS HELD FOR SALE

Long-lived assets, which include property, plant and equipment, goodwill
and other intangibles and equity investments comprise a significant amount of
our total assets. We make judgments and estimates in conjunction with the
carrying value of these assets, including amounts to be capitalized,
depreciation and amortization methods and useful lives. Additionally, the
carrying values of these assets are periodically reviewed for impairment or
whenever events or changes in circumstances indicate that the carrying amounts
may not be recoverable. An impairment loss is recorded in the period in which it
is determined that the carrying amount is not recoverable. This requires us to
make long-term forecasts of future revenues and costs related to the assets
subject to review. These forecasts require assumptions about demand for our
products and services, future market conditions and regulatory developments.
Significant and unanticipated changes to these assumptions could require a
provision for impairment in a future period.

During December 2001, we evaluated our European Energy business segment's
long-lived assets and goodwill for impairment. 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. As
of December 31, 2001, pursuant to SFAS No. 121 "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed Of," (SFAS No. 121)
no impairment had been indicated.

During the fourth quarter of 2001, the Distribution of Reliant Resources
common stock to our shareholders was deemed to be a probable event. As Reliant
Resources has an option to purchase our majority interest in Texas Genco in
2004, we were required to evaluate these assets for potential impairment in
accordance with SFAS No. 121, due to an expected decrease in the number of years
we expect to hold and operate these assets. As of December 31, 2001, no
impairment had been indicated. We anticipate that future events, such as the
expected public offering of Texas Genco shares (please read Note 4(b)), or
change in the estimated holding period of the Texas generation assets, will
require us to re-evaluate our Texas generation assets for impairment between now
and 2004. If an impairment is indicated, it could be material and will not be
fully recoverable through the 2004 true-up proceeding calculations (please read
Notes 2(e) and 4(a)).

Assets held for sale are evaluated based on estimated net realizable value
in accordance with Emerging Issues Task Force Issue No. 90-6. During December
2001, we concluded that there was an impairment related to our remaining Latin
America assets held for sale. This evaluation resulted in an after-tax
impairment charge in 2001 of $43 million, representing the excess of book value
over estimated net realizable value. As of December 31, 2001, we had $8 million
of Latin America net assets held for sale recorded in the Consolidated Balance
Sheets. The charge was included as a component of operating income with respect
to consolidated subsidiaries and other income with respect to equity investments
in unconsolidated subsidiaries. The impairment was primarily related to the
recent adverse economic developments in Argentina. We do not intend to invest
additional resources in these operations. For additional information about our
Latin America assets, please read Note 19 to our consolidated financial
statements.

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UNBILLED ENERGY REVENUES

Revenues related to the sale of energy are generally recorded when service
is rendered or energy is delivered to customers. However, the determination of
the energy sales to individual customers is based on the reading of their meters
which are read 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. This
unbilled electric revenue is estimated each month based on daily generation
volumes, line losses and applicable customer rates based on analyses reflecting
significant historical trends and experience. Unbilled natural gas sales are
estimated based on estimated purchased gas volumes, estimated lost and
unaccounted for gas and tariffed rates in effect. Accrued unbilled revenues
recorded in the Consolidated Balance Sheet as of December 31, 2000 were $39
million related to our Electric Operations business segment, $3 million related
to our Retail Energy business segment and $551 million related to our Natural
Gas Distribution business segment. Accrued unbilled revenues recorded in the
Consolidated Balance Sheet as of December 31, 2001 were $33 million related to
our Electric Operations business segment, $5 million related to our Retail
Energy business segment and $188 million related to our Natural Gas Distribution
business segment.

ACCOUNTING FOR DERIVATIVES AND HEDGING INSTRUMENTS

SFAS No. 133 established accounting and reporting standards for derivative
instruments, including certain derivative instruments embedded in other
contracts, and for hedging activities. It requires an entity to recognize the
fair value of derivative instruments held as assets or liabilities on the
balance sheet. In accordance with SFAS No. 133, the effective portion of the
change in the fair value of a derivative instrument designated as a cash flow
hedge is reported in other comprehensive income, net of tax. Amounts in
accumulated other comprehensive income are ultimately recognized in earnings
when the related hedged forecasted transaction occurs. The change in the fair
value of the ineffective portion of the derivative instrument designated as a
cash flow hedge is recorded in earnings. Derivative instruments that have not
been designated as hedges are adjusted to fair value through earnings.

We 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
cross-currency swaps, forward contracts and options to hedge our net investments
in and cash flows of our foreign subsidiaries, interest rate swaps to mitigate
the impact of changes in interest rates and other financial instruments to
manage various other market risks.

The determination of fair values of trading and marketing assets and
liabilities for our energy trading, marketing and price risk management
operations and non-trading derivative assets and liabilities, including stranded
cost obligations related to our European Energy operations, are based on
estimates. For further discussion, please read " -- Trading and Marketing
Operations", "Quantitative and Qualitative Disclosure About Market Risk" in Item
7A of this Form 10-K and Note 5 to our consolidated financial statements.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142. SFAS No. 141
requires business combinations initiated after June 30, 2001 to be accounted for
using the purchase method of accounting and broadens the criteria for recording
intangible assets separate from goodwill. Recorded goodwill and intangibles will
be evaluated against these new criteria and may result in certain intangibles
being transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. SFAS
No. 142 provides for a nonamortization approach, whereby goodwill and certain
intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and written
down and charged to results of operations only in the periods in which the
recorded value of goodwill and certain intangibles with indefinite lives is more
than its fair value. We adopted the provisions of each statement which apply to
goodwill and intangible assets acquired prior to June 30, 2001 on January 1,
2002. The adoption of SFAS No. 141 did not have a material impact on our
historical results of operations or financial position.

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On January 1, 2002, we discontinued amortizing goodwill into the results of
operations pursuant to SFAS No. 142. We recognized $81 million of goodwill
amortization expense in our Statements of Consolidated Income during 2001,
excluding a $19 million write-off of a Communications business goodwill balance
which was recorded as goodwill amortization expense (please read Note 20 to our
consolidated financial statements). We are in the process of determining further
effects of adoption of SFAS No. 142 on our consolidated financial statements,
including the review of goodwill and certain intangible assets for impairment.
We have not completed our review pursuant to SFAS No. 142. However, based on our
preliminary review, we believe an impairment of our European Energy business
segment goodwill is reasonably possible. As of December 31, 2001, net goodwill
associated with our European Energy business segment is $632 million. We have
not completed our preliminary review of our other business segments with net
goodwill totaling $2.0 billion. We anticipate finalizing our review of goodwill
and certain intangible assets during 2002.

In August 2001, the FASB issued 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. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. We plan to adopt SFAS No. 143 on
January 1, 2003 and are in the process of determining the effect of adoption on
our consolidated financial statements. For certain operations subject to cost of
service rate regulation, we are permitted to include annual charges for cost of
removal and nuclear decommissioning costs in the revenues we charge customers.

In August 2001, the FASB issued SFAS No. 144, "Accounting for the
Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144
provides new guidance on the recognition of impairment losses on long-lived
assets to be held and used or to be disposed of and also broadens the definition
of what constitutes a discontinued operation and how the results of a
discontinued operation are to be measured and presented. SFAS No. 144 supercedes
SFAS No. 121 and APB Opinion No. 30, while retaining many of the requirements of
these two statements. Under SFAS No. 144, assets held for sale that are a
component of an entity will be included in discontinued operations if the
operations and cash flows will be or have been eliminated from the ongoing
operations of the entity and the entity will not have any significant continuing
involvement in the operations prospectively. SFAS No. 144 is effective for
fiscal years beginning after December 15, 2001, with early adoption encouraged.
SFAS No. 144 is not expected to materially change the methods we use to measure
impairment losses on long-lived assets, but may result in additional future
dispositions being reported as discontinued operations than was previously
permitted. We adopted SFAS No. 144 on January 1, 2002.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

MARKET RISK

We are exposed to various market risks. These risks arise from transactions
entered into in the normal course of business and are inherent in our
consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risks
include exposures to commodity prices through trading and marketing and
non-trading activities, interest rates, foreign currency exchange rates and
equity prices. A description of each market risk category is set forth below:

- Commodity price risk results from exposures to changes in spot prices,
forward prices and price volatilities of commodities, such as
electricity, natural gas and other energy commodities.

- Interest rate risk primarily results from exposures to changes in the
level of borrowings and changes in interest rates.

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- Currency rate risk results from exposures to changes in the value of
foreign currencies relative to our reporting currency, the U.S. dollar,
and exposures to changes in currency rates in transactions executed in
currencies other than a business segment's reporting currency.

- Equity price risk results from exposures to changes in prices of
individual equity securities.

Management has established comprehensive risk management policies to
monitor and manage these market risks. We seek to manage our exposures through
the use of derivative financial instruments and derivative commodity
instruments. 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.

Derivative instruments such as futures, forward contracts, swaps or
options, 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.

Our trading operations enter into derivative instrument transactions as a
means of risk management, optimization of our current power generation asset
position, and to take a market position. Derivative instrument transactions are
entered into in our non-trading operations to manage and hedge certain
exposures, such as exposure to changes in electricity and fuel prices, exposure
to purchase and sale commitments of natural gas, exposure to interest rate risk
on our floating-rate borrowings and foreign currency exposures related to our
foreign investments. 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 trading strategy.

TRADING MARKET RISK

Trading and marketing operations often involve market risk associated with
managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis, through derivative instruments
(Trading Energy Derivatives). Our trading and marketing businesses depend on
price movements and volatility levels to create business opportunities, but
these businesses must control risk within authorized limits.

We assess the risk of Trading Energy Derivatives using a value-at-risk
(VAR) method, in order to maintain our total exposure within authorized limits.
VAR is the potential loss in value of trading positions due to adverse market
movements over a defined time period within a specified confidence level. We
utilize the variance/covariance model of VAR, which relies on statistical
relationships to describe how changes in different markets can affect a
portfolio of instruments with different characteristics and market exposures.

For the VAR numbers reported below, a one-day holding period and a 95%
confidence level were used, except for our European trading operations which
uses a two-day to five-day holding period. This means that if VAR 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 portfolio in a one-day period would
exceed $10 million.

The VAR methodology employs a seasonally adjusted volatility-based approach
with the following critical parameters: forward prices and volatility estimates,
appropriate market-oriented holding periods and seasonally adjusted correlation
estimates. We use the delta approximation method for reporting option positions.
The instruments being evaluated could have features that may trigger a potential
loss in excess of calculated amounts if changes in commodity prices exceed the
confidence level of the model used. An inherent limitation of VAR is that past
changes in market risk may not produce accurate predictions of future market
risk. Moreover, VAR calculated for a one-day holding period does not fully
capture the market risk of positions that cannot be liquidated or offset with
hedges within one day. We cannot assure you that market volatility, failure of
counterparties to meet their contractual obligations, future transactions or a
failure of risk controls will not lead to significant losses from our trading,
marketing and risk management activities.

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

Our VAR limits are set by our board of directors, as further discussed
below. Violations in overall VAR limits are required to be reported to the Audit
Committee of our board of directors pursuant to our corporate-wide risk limit
parameters. For further discussion on our risk management framework, please read
"-- Risk Management Structure" below.

The following presents the daily VAR for substantially all of our Trading
Energy Derivative positions (in millions).

The following chart presents the daily VAR for substantially all of our
Trading Energy Derivatives during 2001 (in millions).

COMBINED DOMESTIC AND EUROPEAN VAR
FOR THE YEAR ENDED DECEMBER 31, 2001

(PERFORMANCE GRAPH)

During the beginning of 2001, the high VAR levels were due to high natural
gas and power prices and volatility levels, which continued from late 2000. VAR
exposure was lower in the second and third quarters of 2001 due to the
significant decline in natural gas and power prices and volatility levels.
During the fourth quarter of 2001, VAR levels increased due to increased power
marketing activities in ERCOT related to our Retail Energy business segment.

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NON-TRADING MARKET RISK

Commodity Price Risk

Commodity price risk is an inherent component of our electric power
generation businesses because the profitability of our generation assets depends
significantly on commodity prices sufficient to create gross margin. During
2001, the majority of our non-trading commodity price risk was related to our
electric power generation businesses. Prior to the energy delivery period, we
attempt, in part to hedge the economics of our electric power facilities by
selling power and purchasing equivalent fuel. Some power capacity is held in
reserve and sold in the spot market. Non-trading derivative instruments
(Non-trading Energy Derivatives) are used to mitigate exposure to variability in
future cash flows from probable, anticipated future transactions attributable to
a commodity risk. In this way, more certainty is provided as to the financial
contribution associated with the operation of these assets. Beginning in 2002,
our commodity price risk exposures related to our Retail Energy operations
increased as we began to provide retail electric services to all customers of
the T&D Utility who did not select another retail electric provider. For a
discussion of risk factors affecting our Retail Energy operations, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Certain Factors Affecting Our Future Earnings -- Factors Affecting
the Results of Our Retail Energy Operations" in Item 7 of this Form 10-K.

To reduce our commodity price risk from market fluctuations in the revenues
derived from the sale of natural gas and related transportation, we enter into
futures transactions, forward contracts, swaps and options in order to hedge
some expected purchases of natural gas and sales of natural gas (a portion of
which are firm commitments at the inception of the hedge). Non-trading Energy
Derivatives are also utilized to fix the price of compressor fuel or other
future operational gas requirements and to protect natural gas distribution
earnings against unseasonably warm weather during peak gas heating months,
although usage to date for this purpose has not been material.

Derivative instruments, which we use as economic hedges, create exposure to
commodity prices, which we use to 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. We measure the commodity risk of our
Non-trading Energy Derivatives using a sensitivity analysis. The sensitivity
analysis performed on our Non-trading Energy Derivatives measures the potential
loss in earnings based on a hypothetical 10% movement in energy prices. An
increase of 10% in the market prices of energy commodities from their December
31, 2001 levels would have decreased the fair value of our Non-trading Energy
Derivatives by $38 million, excluding non-trading derivatives liabilities
associated with our European Energy business segment's stranded cost import
contracts.

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, excluding the stranded cost import
contracts, is managed to complement the physical transaction portfolio, thereby
reducing overall risks within limits. Therefore, the adverse impact to the fair
value of the portfolio of Non-trading Energy Derivatives held 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 intended as hedges, and
which are effective as hedges, may still have some percentage which is not
effective. The change in value of the Non-

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trading Energy Derivatives which represents the ineffective component of the
hedges, is recorded in our results of operations. During 2001, we recognized
revenues of $8 million in our Statements of Consolidated Income due to hedge
ineffectiveness.

Our European Energy business segment's stranded cost import contracts have
exposure to commodity prices. For information regarding these contracts, please
read Notes 5(b) and 14(h) to our consolidated financial statements. A decrease
of 10% in market prices of energy commodities from their December 31, 2001
levels would result in a loss of earnings of $98 million.

Interest Rate Risk

We have issued long-term debt and have obligations under bank facilities
that subject us to the risk of loss associated with movements in market interest
rates. We utilize interest-rate swaps in order to hedge a portion of our
floating-rate obligations.

We have outstanding long-term debt and commercial paper obligations under
bank facilities, mandatory redeemable preferred securities of subsidiary trusts
holding solely our junior subordinated debentures (Trust Preferred Securities),
securities held in our nuclear decommissioning trust, some lease obligations and
our obligations under the ZENS that subject us to the risk of loss associated
with movements in market interest rates. We utilize interest-rate swaps in order
to hedge portions of our floating-rate debt and to hedge a portion of the
interest rate applicable to a future offering of long-term debt.

Our floating-rate obligations aggregated $5.8 billion and $4.2 billion at
December 31, 2000 and 2001, respectively. If the floating interest rates were to
increase by 10% from December 31, 2001 rates, our combined interest expense
would increase by a total of $1.2 million each month in which such increase
continued.

At December 31, 2000 and 2001, we had outstanding fixed-rate debt
(excluding indexed debt securities) and Trust Preferred Securities aggregating
$5.5 billion and $6.2 billion, respectively, in principal amount and having a
fair value of $6.2 billion each year. These instruments are fixed-rate and,
therefore, do not expose us to the risk of loss in earnings due to changes in
market interest rates (please read Notes 10 and 11 to our consolidated financial
statements). However, the fair value of these instruments would increase by
approximately $682 million if interest rates were to decline by 10% from their
levels at December 31, 2001. In general, such an increase in fair value would
impact earnings and cash flows only if we were to reacquire all or a portion of
these instruments in the open market prior to their maturity.

As discussed in Note 14(k) to our consolidated financial statements, we
contributed $14.8 million in 1999, 2000 and 2001 to a trust established to fund
our share of the decommissioning costs for the South Texas Project. In 2002, we
will begin contributing $2.9 million per year to this trust. The securities held
by the trust for decommissioning costs had an estimated fair value of $169
million as of December 31, 2001, of which approximately 46% were fixed-rate debt
securities that subject us to risk of loss of fair value with movements in
market interest rates. If interest rates were to increase by 10% from their
levels at December 31, 2001, the decrease in fair value of the fixed-rate debt
securities would not be material to us. In addition, the risk of an economic
loss is mitigated. Any unrealized gains or losses are accounted for in
accordance with SFAS No. 71 as a regulatory asset/liability because we believe
that our future contributions, which are currently recovered through the
ratemaking process, will be adjusted for these gains and losses. For further
discussion regarding the recovery of decommissioning costs pursuant to the Texas
Electric Restructuring Law, please read Note 4(a) to our consolidated financial
statements.

As discussed in Note 10(b) to our consolidated financial statements, RERC
Corp.'s $500 million aggregate principal amount of 6 3/8% Term Enhanced
Remarketable Securities (TERM Notes) include an embedded option to remarket the
securities. The option is expected to be exercised in the event that the ten-
year Treasury rate in 2003 is below 5.66%. At December 31, 2001, we could
terminate the option at a cost of $21 million. A decrease of 10% in the December
31, 2001 level of interest rates would increase the cost of termination of the
option by approximately $16 million.

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As discussed in Note 8 to our consolidated financial statements, upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was
bifurcated into a debt component of $122 million and a derivative component of
$788 million. The debt component of $122 million is a fixed-rate obligation and,
therefore, does not expose us to the risk of loss in earnings due to changes in
market interest rates. However, the fair value of the debt component would
increase by approximately $18 million if interest rates were to decline by 10%
from levels at December 31, 2001. Changes in the fair value of the derivative
component will be recorded in our Statements of Consolidated Income and,
therefore, we are exposed to changes in the fair value of the derivative
component as a result of changes in the underlying risk-free interest rate. If
the risk-free interest rate were to increase by 10% from December 31, 2001
levels, the fair value of the derivative component would increase by
approximately $10 million, which would be recorded as a loss in our Statements
of Consolidated Income.

During 2001, we entered into interest rate swaps having an aggregate
notional amount of $1.8 billion to fix the interest rate applicable to floating
rate short-term debt and interest rate swaps of $425 million to fix the interest
rate applicable to floating rate long-term debt. At December 31, 2001, the swaps
relating to short-term debt could be terminated at a cost of $12 million and the
swaps related to long-term debt, of which $225 million had expired as of
December 31, 2001, could be terminated at a cost of $4 million. The swaps
relating to short-term debt do not qualify as cash flow hedges under SFAS No.
133, and are marked to market in our Consolidated Balance Sheets with changes
reflected in interest expense in the Statements of Consolidated Income. The
swaps relating to long-term debt qualify for hedge accounting under SFAS No. 133
and the periodic settlements are recognized as an adjustment to interest expense
in the Statements of Consolidated Income over the term of the swap agreement. A
decrease of 10% in the December 31, 2001 level of interest rates would increase
the cost of terminating the swaps related to short-term debt and long-term debt
outstanding at December 31, 2001 by $4 million each.

During 2001, we entered into forward-starting interest rate swaps having an
aggregate notional amount of $500 million to hedge the interest rate on a future
offering of five-year notes. At December 31, 2001, these swaps could be
terminated at a cost of $2 million. These swaps qualify as cash flow hedges
under SFAS No. 133. Should the expected issuance of the debt no longer be
probable, any deferred amount will be recognized immediately into income. A
decrease of 10% in the December 31, 2001 level of interest rates would increase
the cost of terminating these swaps by $12 million.

For information regarding the accounting for these interest rate swaps,
please read Note 5 to our consolidated financial statements.

Foreign Currency Exchange Rate Risk

Our European operations expose us to risk of loss in the fair value of our
foreign investments due to the fluctuation in foreign currencies relative to our
reporting currency, the U.S. dollar. Additionally, our European Energy business
segment transacts in several European currencies, although the majority of its
business is conducted in the Euro and prior to January 2001, the Dutch Guilder.
As of December 31, 2001, we had entered into foreign currency swaps and foreign
currency forward contracts and had issued Euro-denominated borrowings to hedge
our foreign currency exposure of our net European investment. Changes in the
value of the foreign currency hedging instruments and Euro -- denominated
borrowings are recorded as foreign currency translation adjustments as a
component of accumulated other comprehensive income (loss) in stockholders'
equity. As of December 31, 2000 and 2001, we had recorded a loss of $2 million
and $96 million, respectively, in cumulative net translation adjustments. The
cumulative translation adjustments will be realized in earnings and cash flows
only upon the disposition of the related investments. During the normal course
of business, we review our currency hedging strategies and determine the hedging
approach we deem appropriate based upon the circumstances of each situation.

As of December 31, 2001, our European Energy business segment had entered
into transactions to purchase $271 million at fixed exchange rates in order to
hedge future fuel purchases payable in U.S. dollars. As of December 31, 2001,
the fair value of these financial instruments was a $3 million asset. An
increase in

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the value of the Euro of 10% compared to the U.S. dollar from its December 31,
2001 level would result in loss in the fair value of these foreign currency
financial instruments of $27 million.

Our European Energy business segment's stranded cost import contracts have
foreign currency exposure. An increase of 10% in the U.S. dollar relative to the
Euro from their December 31, 2001 levels would result in a loss of earnings of
$6 million.

Beginning in January 2002, our remaining Latin America operations will use
the Argentine peso as their functional currency (please read Note 2(o) to our
consolidated financial statements). These foreign operations will expose us to
risk of loss in earnings and cash flows due to the fluctuation in foreign
currencies relative to our consolidated reporting currency, the U.S. dollar. We
account for adjustments resulting from translation of our investments with
functional currencies other than the U.S. dollar as a charge or credit directly
to a separate component of stockholders' equity.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of
approximately 26 million shares of AOL TW Common, which are held by us to
facilitate our ability to meet our obligations under the ZENS. Please read Note
8 to our consolidated financial statements for a discussion of the effect of
adoption of SFAS No. 133 on our ZENS obligation and our historical accounting
treatment of our ZENS obligation. Subsequent to adoption of SFAS No. 133, a
decrease of 10% from the December 31, 2001 market value of AOL TW Common would
result in a net loss of approximately $3 million, which would be recorded as a
loss in our Statements of Consolidated Income.

As discussed above under "-- Interest Rate Risk," we contribute to a trust
established to fund our share of the decommissioning costs for the South Texas
Project, which held debt and equity securities as of December 31, 2001. The
equity securities expose us to losses in fair value. If the market prices of the
individual equity securities were to decrease by 10% from their levels at
December 31, 2001, the resulting loss in fair value of these securities would
not be material to us. Currently, the risk of an economic loss is mitigated as
discussed above under "-- Interest Rate Risk."

We have equity investments, which are classified as "available-for-sale"
under SFAS No. 115. As of December 31, 2001, the value of these securities was
$12 million. A 10% decline in the market value per share of these securities
from December 31, 2001 would result in a loss in fair value of $1 million.

RISK MANAGEMENT STRUCTURE

We have a risk control framework to limit, monitor, measure and manage the
risk in our existing portfolio of assets and contracts and to risk-measure and
authorize new transactions. These risks include market, credit, liquidity and
operational exposures. We believe that we have effective procedures for
evaluating and managing these risks to which we are exposed. Key risk control
activities include limits on trading and marketing exposures and products,
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, VAR 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, as detailed below.

Board of Directors. Our board of directors affirms the overall strategy
and approves overall risk limits for commodity trading and marketing.

127

Audit Committee. The Audit Committee of our board of directors assesses
the adequacy of the risk control organization and policies. The Audit Committee
of our board of directors meets at least four times a year to:

- approve the risk control organization structure;

- approve the corporate-wide risk control policy;

- monitor compliance with trading limits;

- review significant risk control issues; and

- recommend to our board of directors corporate-wide commodity risk limit
parameters for trading and marketing activities.

Executive Management. Our executive management appoints the Risk Oversight
Committee members, reviews and approves recommendations of the Risk Oversight
Committee prior to presentations to the Audit Committee of our board of
directors, and approves and monitors broad risk limit allocations to the
business segments and product types. Our executive management receives daily
position reports of our trading and marketing activities.

Risk Oversight Committee. The Risk Oversight Committee, which is comprised
of corporate and business segment officers, oversees all of our trading,
marketing and hedging activities and other activities involving market risks.
These activities expose us to commodity price, credit, foreign currency and
interest rate risks. The Risk Oversight Committee meets at least monthly. For
trading, marketing and hedging activities, the Risk Oversight Committee:

- monitors compliance of our trading units;

- reviews daily position reports for trading and marketing activities;

- recommends adjustments to trading limits, products and policies to the
Audit Committee of our board of directors;

- approves business segment's detailed policies and procedures;

- allocates board of director-approved trading and marketing risk capital
limits, including VAR limits;

- approves new trading, marketing and hedging products and commodities;

- approves entrance into new trading markets;

- monitors processes and information systems related to the management of
our risk to market exposures; and

- places guidelines and limits around hedging activities.

Commitment Review Committee. The Commitment Review Committee, which is
comprised of corporate officers, establishes corporate-wide standards for the
evaluation of capital projects and other significant commitments, evaluates
proposed capital projects and other significant commitments, and makes
recommendations to the chief executive officer. The Commitment Review Committee
is scheduled to meet on an as needed basis.

Corporate Risk Control Organization. Our Corporate Risk Control
Organization is headed by a chief risk control officer who has corporate-wide
oversight for maintaining consistent application of corporate risk policies
within individual business segments. The Corporate Risk Control Organization:

- recommends the corporate-wide risk management policies and procedures
which are approved by the Audit Committee of our board of directors;

- provides updates of trading and marketing activities to the Audit
Committee of our board of directors on a regular basis;

128

- provides oversight of our ongoing development and implementation of
operational risk policies, framework and methodologies;

- monitors effectiveness of the corporate-wide risk management policies,
procedures and risk limits;

- evaluates the business segment risk control organizations, including
information systems and reporting;

- evaluates all significant valuation methodologies, assumptions and
models;

- evaluates allocation of risk limits within our business segments;

- reviews daily position reports of trading and marketing activities; and

- reviews inherent risks in proposed transactions.

Business Segment Risk Control Organizations. The Corporate Risk Control
Organization also serves as the risk control organization for the business
segments that will comprise CenterPoint Energy. Each of Reliant Resources'
business segments has a Business Segment Risk Control Organization, which is
headed by a risk control officer who reports to the Corporate Risk Control
Organization and the business segment's executive management outside of the
commercial trading organization. The Business Segment Risk Control Organization:

- develops and maintains the risk control infrastructure, including
policies, processes, personnel and information and valuation systems, to
analyze and report the daily risk positions to Executive Management, the
Risk Oversight Committee, the Corporate Risk Control Organization, the
Internal Audit Department and the Controllers Organization;

- reviews credit exposures for customers and counterparties;

- reviews all significant valuation methodologies, assumptions and models
used for risk measurement, mark-to-market valuations and structured
transaction evaluations;

- ensures that risk systems can adequately measure positions and related
risk exposures for new products and transactions;

- evaluates new transactions for compliance with risk policies and limits;
and

- evaluates effectiveness of hedges.

The management of each of the business segments is responsible for the
management of its risks and for maintaining an environment conducive to
effective risk control activities as part of its overall responsibility for the
business unit. Commercial management has in-depth knowledge of the primary
sources of risk in their individual markets and the instruments available to
hedge our exposures. Commercial management assigns risk limits that have been
allocated to specific markets and to individual traders, within the limits
imposed by the Risk Oversight Committee. Risk limits are monitored on a daily
basis. Risk limit violations, including VAR, are reported to the appropriate
level of management in the business segment, the Corporate Risk Control
Organization, the Risk Oversight Committee, the board of directors and the Audit
Committee of the board of directors.

Segregation of duties and management oversight are fundamental elements of
our risk management process. There are segregation of duties among the trading
and marketing functions; transaction validation and documentation; risk
measurement and reporting; settlements function; accounting and financial
reporting functions; and treasury function. These risk management processes and
related controls are reviewed by our corporate Internal Audit Department on a
regular basis. When appropriate, external advisors or consultants with relevant
experience will assist the Internal Audit Department with their reviews.

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

Credit risk is inherent in our commercial activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. Broad credit policies and parameters are set by the Risk
Oversight Committee. The Business Segment Risk Control Organizations prepare
daily analyses of credit exposures. We enter into derivative instruments
primarily with counterparties having a minimum investment grade credit rating
(i.e., a minimum credit rating for such entity's senior unsecured debt of BBB-
for Standard & Poor's and Fitch or Baa3 for Moody's). In addition, we seek to
enter into netting agreements that permit us to offset receivables and payables
with a given counterparty. We also attempt to enter into agreements that enable
us to either obtain collateral from a counterparty or to terminate upon the
occurrence of adverse credit-related events. We are re-evaluating our current
credit risk practices in light of changes in the marketplace, recent corporate
failures and changing credit practices by the rating agencies.

It is our policy that all transactions must be within approved counterparty
or customer credit limits. For each business segment, counterparty credit limits
are established by the applicable business segment's credit risk control group.
We employ tiered levels of approval authority for counterparty credit limits,
with authority increasing from the operating business segment's credit analysts
through the business segment's risk control officer, the Risk Oversight
Committee and our executive management. The Business Segment Risk Control
Organization monitors credit exposure daily. The mark-to-market values and cash
settlement values for all transactions are compared to the authorized credit
threshold for each counterparty. For long-term arrangements, we periodically
review the financial condition of these counterparties in addition to monitoring
the effectiveness of these contracts in achieving our objectives.

For information regarding our provision related to our energy sales in the
California market, please read Note 14(g) to our consolidated financial
statements. For information regarding our net provision related to energy sales
to Enron which filed a voluntary petition for bankruptcy, please read Note 21 to
our consolidated financial statements.

The following table presents the distribution by credit ratings of our
total trading and marketing assets and total non-trading derivative assets as of
December 31, 2001, after taking into consideration netting and set-off
agreements with counterparties within each balance sheet caption (in millions).

130

The following table presents credit exposure by maturity for total trading
and marketing assets and non-trading derivative assets, net of collateral, as of
December 31, 2001 (in millions).

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

(1) For unrated counterparties, we perform financial statement analysis,
considering contractual rights and restrictions, and collateral, to create a
synthetic credit rating.

(2) In lieu of making an individual assessment of the credit of unrated
counterparties, we may make a determination that the collateral held in
respect of such obligations is sufficient to cover a substantial portion of
our exposure. In making this determination, we take into account various
factors, including market volatility.

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

131

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF THE COMPANY

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED INCOME

See Notes to the Company's Consolidated Financial Statements
132

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

See Notes to the Company's Consolidated Financial Statements
133

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to the Company's Consolidated Financial Statements

134

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

See Notes to the Company's Consolidated Financial Statements
135

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED STOCKHOLDERS' EQUITY

See Notes to the Company's Consolidated Financial Statements
136

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

Reliant Energy, Incorporated (Reliant Energy), together with its
subsidiaries (collectively, the Company), is a diversified international energy
services company that provides energy and energy services primarily in North
America and Western Europe. Reliant Energy is both an electric utility company
and a utility holding company through its wholly owned subsidiary Reliant Energy
Resources Corp. (RERC).

The Company's financial reporting business segments include the following:
Electric Operations, Natural Gas Distribution, Pipelines and Gathering,
Wholesale Energy, European Energy, Retail Energy, Latin America and Other
Operations. Electric Operations includes the operations of Reliant Energy HL&P,
an electric utility. Natural Gas Distribution consists of intrastate natural gas
sales to, and natural gas transportation and distribution for, residential,
commercial, industrial and institutional customers and some non-rate regulated
retail gas marketing operations to commercial and industrial customers.
Pipelines and Gathering includes the interstate natural gas pipeline operations
and the natural gas gathering and pipelines services businesses. Wholesale
Energy is engaged in the acquisition, development and operation of non-rate
regulated power generation facilities as well as the wholesale energy trading,
marketing, power origination and risk management services in North America.
European Energy is engaged in the operation of power generation facilities in
the Netherlands as well as wholesale energy trading and power origination
activities in Europe. Retail Energy consists of the Company's unregulated retail
electric operations, and has historically been reported in the Other Operations
business segment. Other Operations includes unallocated general corporate
expenses, a communications business and non-operating investments. Latin America
primarily consists of an electric utility and an electric cogeneration plant
located in Argentina. Wholesale Energy, European Energy, Retail Energy and
certain operations included within Other Operations are currently owned by
Reliant Resources.

Reliant Energy is in the process of separating its regulated and
unregulated businesses into two publicly traded companies. In December 2000,
Reliant Energy transferred a significant portion of its unregulated businesses
to Reliant Resources, Inc. (Reliant Resources) which, at the time, was a wholly
owned subsidiary. In May 2001, Reliant Resources conducted an initial public
offering (Offering) of approximately 20% of its common stock (59.8 million
shares of its common stock) at a price of $30 per share, and received net
proceeds from the Offering of $1.7 billion. After the Offering, Reliant Energy
owned approximately 80% of Reliant Resources. As of December 31, 2001, Reliant
Energy owns approximately 83% of Reliant Resources due to treasury stock
repurchases of $189 million during 2001 by Reliant Resources. As a result of the
Offering, the Company recorded directly into stockholders' equity as a component
of common stock a $509 million unrealized gain on the sale of subsidiaries'
stock. Pursuant to a master separation agreement between Reliant Energy and
Reliant Resources, Reliant Resources used $147 million of the net proceeds to
repay certain indebtedness owed to Reliant Energy. In connection with the
Offering, Reliant Energy converted $1.7 billion of intercompany indebtedness
owed by Reliant Resources and its subsidiaries prior to the closing of the
Offering to equity as a capital contribution to Reliant Resources. In December
2001, Reliant Energy's shareholders approved an agreement and plan of merger by
which the following will occur (which we refer to as the Restructuring):

- CenterPoint Energy will become the holding company for Reliant Energy and
its subsidiaries;

- Reliant Energy and its subsidiaries will become subsidiaries of
CenterPoint Energy; and

- each share of Reliant Energy common stock will be converted into one
share of CenterPoint Energy common stock.

After the Restructuring, Reliant Energy plans, subject to further corporate
approvals, market and other conditions, to complete the separation of its
regulated and unregulated businesses by distributing the shares of common stock
of Reliant Resources that the Company owns to its shareholders (Distribution).
The Company's goal is to complete the Restructuring and subsequent Distribution
as quickly as possible after all
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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the necessary conditions are fulfilled, including receipt of an order from the
Securities and Exchange Commission (SEC) granting the required approvals under
the Public Utility Holding Company Act of 1935 (1935 Act) and an extension from
the IRS of its private letter ruling that the Company has obtained regarding the
tax-free treatment of the Distribution. Although receipt or timing of regulatory
approvals cannot be assured, the Company believes it meets the standards for
such approvals. Reliant Energy currently expects to complete the Restructuring
and Distribution in the summer of 2002.

Effective December 1, 2000, Reliant Energy's board of directors approved a
plan to dispose of the Company's Latin America business segment through sales of
its assets. Accordingly, in its 2000 consolidated financial statements, the
Company reported the results of its Latin America business segment as
discontinued operations in accordance with Accounting Principles Board (APB)
Opinion No. 30 "Reporting the Results of Operations -- Reporting the Effects of
Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently
Occurring Events and Transactions," (APB Opinion No. 30) for each of the three
years in the period ended December 31, 2000. On December 20, 2001, negotiations
for the sale of the remaining Latin America investments were terminated as a
result of the recent economic developments in Argentina. The Company will
continue to evaluate options related to the future disposition of these assets.

Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Consolidated Statements of Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by Emerging Issues Task Force (EITF) Issue No. 90-6
(EITF 90-6). For additional information regarding the disposal of the Latin
America business segment, see Note 19.

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) RECLASSIFICATIONS AND USE OF ESTIMATES

Some amounts from the previous years have been reclassified to conform to
the 2001 presentation of financial statements. These reclassifications do not
affect earnings.

The preparation of financial statements in conformity with generally
accepted accounting principles 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.

(b) MARKET RISK AND UNCERTAINTIES

The Company is subject to the risk associated with price movements of
energy commodities and the credit risk associated with the Company's risk
management activities. For additional information regarding these risks, see
Notes 5, 14(g) and 21. The Company is also subject to risks relating to the
supply and prices of fuel and electricity, seasonal weather patterns,
technological obsolescence and the regulatory environment in the United States,
and Western Europe and Latin America.

(c) PRINCIPLES OF CONSOLIDATION

The accounts of Reliant Energy and its wholly owned and majority owned
subsidiaries are included in the consolidated financial statements. All
significant intercompany transactions and balances are eliminated in
consolidation. The Company uses the equity method of accounting for investments
in entities in which the Company has an ownership interest between 20% and 50%
and exercises significant influence. For additional information regarding these
investments, see Note 7. Other investments, excluding marketable securities, are
generally carried at cost. The results of the Company's European Energy business
segment are consolidated on
138

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

a one-month lag basis due to the availability of financial information. The
Company has made adjustments to the European Energy business segment's accounts
to include the effect of the settlement of our indemnity for certain energy
obligations in December 2001 (see Note 14(h)). The Company owns approximately
83% of Reliant Resources and has reflected the third-party interest in Reliant
Resources as minority interest in the Consolidated Balance Sheets and Statements
of Consolidated Income.

(d) REVENUES

The Company records revenue for electricity and natural gas sales and
services to retail customers, except for certain contracted sales to large
commercial, industrial and institutional customers, under the accrual method and
these revenues are generally recognized upon delivery. Pipelines and Gathering
record revenues as transportation services are provided. Energy sales and
services not billed by month-end are accrued based upon estimated energy and
services delivered. Domestic non-rate regulated electric power and other
non-rate regulated energy services are sold at market-based prices through
existing power exchanges or through third-party contracts. Prior to January 1,
2001, energy revenues related to the Company's power generation facilities in
Europe were generated under a regulated pricing structure, which included
compensation for the cost of fuel, capital and operation and maintenance
expenses. The wholesale electric market in the Netherlands opened to competition
on January 1, 2001. Accordingly, beginning in 2001, electric power and other
energy services in Europe are sold at market-based prices or through third-party
contracts.

The Company's energy trading, marketing, power origination and risk
management services activities and contracted sales of electricity to large
commercial, industrial and institutional customers are accounted for under
mark-to-market accounting. Under the mark-to-market method of accounting,
financial instruments and contractual commitments are recorded at fair value in
revenues upon contract execution. The net changes in their fair values are
recognized in the Statements of Consolidated Income as revenues in the period of
change. Trading and marketing revenues related to the physical sale of natural
gas, electric power and other energy related commodities are recorded on a gross
basis in the delivery period. For additional discussion regarding trading and
marketing revenue recognition and the related estimates and assumptions that can
affect reported amounts of such revenues, see Note 5.

The gains and losses related to financial instruments and contractual
commitments qualifying and designated as hedges related to the sale of electric
power and sales and purchases of natural gas are recognized in the same period
as the settlement of the underlying physical transaction. These realized gains
and losses are included in operating revenues and operating expenses in the
Statements of Consolidated Income. For additional discussion, see Note 5.

(e) LONG-LIVED ASSETS AND INTANGIBLES

The Company records property, plant and equipment at historical cost. The
Company recognizes repair and maintenance costs incurred in connection with
planned major maintenance, such as turbine and generator overhauls, control
system upgrades and air conditioner replacements, under the "accrual in advance"
method for its non-rate regulated power generation operations acquired or
developed prior to December 31, 1999. Planned major maintenance cycles primarily
range from two to ten years. Under the accrual in advance method, the Company
estimates the costs of planned major maintenance and accrues the related expense
over the maintenance cycle. As of December 31, 2000 and 2001, the Company's
maintenance reserve was $27 million and $19 million, respectively, of which $20
million and $17 million, respectively, were included in

139

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

other long-term liabilities and the remainder in other current liabilities. The
Company expenses all other repair and maintenance costs as incurred. Property,
plant and equipment includes the following:

The Company records goodwill for the excess of the purchase price over the
fair value assigned to the net assets of an acquisition. Goodwill has been
amortized on a straight-line basis over 5 to 40 years. See Note 3 and the
following table for additional information regarding goodwill and the related
amortization periods.

The Company recognizes specifically identifiable intangibles, including air
emissions regulatory allowances and water rights and permits, when specific
rights and contracts are acquired. As of December 31, 2000 and 2001, specific
intangibles were $284 million and $315 million, respectively. The Company
amortizes air emissions regulatory allowances primarily on a units-of-production
basis as utilized. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range between 5 and 35 years.

The Company periodically evaluates long-lived assets, including property,
plant and equipment, goodwill and specifically identifiable intangibles, 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. An impairment analysis
of generating facilities requires estimates of possible future market prices,
load growth, competition and many other factors over the lives of the
facilities. A resulting impairment loss is highly dependent on these underlying
assumptions. During 2001, the Company determined equipment and goodwill
associated with its Communications business was impaired and accordingly
recognized

140

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$22 million of fixed asset impairments and $19 million of goodwill impairments
(see Note 20). For discussion of goodwill impairment analysis in 2002, see Note
2(q).

During December 2001, the Company evaluated its European Energy business
segment's long-lived assets and goodwill for impairment. As of December 31,
2001, pursuant to Statement of Financial Accounting Standards (SFAS) No. 121,
"Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to
Be Disposed Of" (SFAS No. 121), no impairment had been indicated. For discussion
of goodwill impairment analysis in 2002, see Note 2(q).

During the fourth quarter of 2001, the Distribution of Reliant Resources
was deemed to be a probable event. As Reliant Resources has an option, subject
to the completion of the Distribution, to purchase the Company's Texas
generation assets in 2004 (see Note 4(b)), the Company was required to evaluate
these assets for potential impairment in accordance with SFAS No. 121, due to an
expected decrease in the number of years the Company expects to hold and operate
these assets. As of December 31, 2001, no impairment had been indicated. The
Company anticipates that future events, such as the expected public offering of
the Company's Texas generation operations (see Note 4(b)), or change in the
estimated holding period of the Texas generation assets, will require the
Company to re-evaluate these assets for impairment between now and 2004. If an
impairment is indicated, it could be material and will not be fully recoverable
through the 2004 true-up proceeding calculations (see Note 4(a)).

The Texas Electric Restructuring Law provides the Company recovery of the
regulatory book value of its Texas generating assets for the amount the
regulatory book value exceeds the estimated market value. If the Texas
generating assets are sold to Reliant Resources, or to a third party in the
future, a loss on sale of these assets, or an impairment of the recorded
recoverable electric generation plant mitigation regulatory asset (see Note
2(f)), will occur to the extent the recorded book value of the Texas generating
assets exceeds the regulatory book value. As of December 31, 2001, the recorded
book value was $638 million in excess of the regulatory book value. This amount
declines each year as the recorded book value is depreciated and increases by
the amount of non-environmental capital expenditures. For further discussion of
the difference between the regulatory book value and the recorded book value,
see Note 4.

(f) REGULATORY ASSETS AND LIABILITIES

The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of transmission and distribution operations of Reliant Energy HL&P and
the utility operations of Natural Gas Distribution and to some of the accounts
of Pipelines and Gathering. For information regarding Reliant Energy HL&P's
electric generation operations' discontinuance of the application of SFAS No. 71
in 1999 and the effect on its regulatory assets and the Texas Electric Choice
Plan (Texas Electric Restructuring Law), see Note 4(a).

141

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2000 and 2001:

If, as a result of changes in regulation or competition, the Company's
ability to recover these assets and liabilities would not be assured, then
pursuant to SFAS No. 101, "Regulated Enterprises Accounting for the
Discontinuation of Application of SFAS No. 71" (SFAS No. 101) and SFAS No. 121,
the Company would be required to write off or write down these regulatory assets
and liabilities. In addition, the Company would be required to determine any
impairment to the carrying costs of plant and inventory assets. See Note 4(a)
for a discussion of the discontinuation of SFAS No. 71 related to Reliant Energy
HL&P's electric generation operations.

Through December 31, 2001, the Texas Utility Commission provided for the
recovery of most of Reliant Energy HL&P's fuel and purchased power costs from
customers through a fixed fuel factor included in electric rates. Included in
the above table in recoverable electric generation related regulatory assets,
net are $558 million and $200 million of regulatory assets related to the
recovery of fuel costs as of December 31, 2000 and 2001.

In December 2001, the Company recorded a regulatory asset for recoverable
electric generation plant mitigation for $2.0 billion and recorded a regulatory
liability of $1.1 billion for excess mitigation, resulting in net regulatory
assets of $841 million on which the Company will not earn a return and which are
not included in the Company's rate base. Recoverable electric plant generation
regulatory assets are anticipated to be recovered in the 2004 true-up
proceedings as further discussed in Note 4(a). The Company is entitled to
recover its full amount of stranded costs in the 2004 true-up proceeding. That
recovery would include any amounts whose earlier mitigation was prevented by
excess mitigation credits and the reversal of redirected depreciation ordered by
the Texas Utility Commission.

In 2001, the Company monetized $738 million of regulatory assets in a
securitization financing authorized by the Texas Utility Commission pursuant to
the Texas Electric Restructuring Law. For additional information regarding the
securitization financing, see Note 4(a).

For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets and the related amortization
during 1999, 2000 and 2001, see Notes 2(g) and 4(a).

(g) DEPRECIATION AND AMORTIZATION EXPENSE

Depreciation is computed using the straight-line method based on economic
lives or a regulatory mandated method. Other amortization expense includes
amortization of regulatory assets and air emissions regulatory allowances and
other intangibles. See Notes 2(f) and 4(a) for additional discussion of these
items.

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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table presents depreciation, goodwill amortization and other
amortization expense for 1999, 2000 and 2001.

In June 1998, the Texas Utility Commission issued an order approving a
transition to competition plan (Transition Plan) filed by Reliant Energy HL&P in
December 1997. In order to reduce Reliant Energy HL&P's exposure to potential
stranded costs related to generation assets, the Transition Plan permitted the
redirection of depreciation expense to generation assets that Reliant Energy
HL&P otherwise would apply to transmission, distribution and general plant
assets (Redirected Depreciation). In addition, the Transition Plan provided that
all earnings above a stated overall annual rate of return on invested capital be
used to recover Reliant Energy HL&P's investment in generation assets
(Accelerated Depreciation). Reliant Energy HL&P implemented the Transition Plan
effective January 1, 1998 and pursuant to its terms, recorded $194 million in
Accelerated Depreciation and $195 million in Redirected Depreciation in 1998 and
$104 million in Accelerated Depreciation and $99 million in Redirected
Depreciation in the first six months in 1999. Due to the discontinuance of SFAS
No. 71 to Reliant Energy HL&P's generation operations, the provisions for
Accelerated and Redirected Depreciation of the Transition Plan were no longer
applied effective July 1, 1999. For additional information regarding the
discontinuance of SFAS No. 71 to the Electric Operations business segments'
generation operations and the related Texas Electric Restructuring Law, as well
as an October 3, 2001 order finding that the Company had overmitigated its
stranded costs, see Note 4(a).

(h) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING
CONSTRUCTION

Allowance for funds used during construction (AFUDC) represents the
approximate net composite interest cost of borrowed funds and a reasonable
return on the equity funds used for construction. Although AFUDC increases both
utility plant and earnings, it is realized in cash through depreciation
provisions included in rates for subsidiaries that apply SFAS No. 71. Interest
and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component
of projects under construction and will be amortized over the assets' estimated
useful lives. During 1999, 2000 and 2001, the Company capitalized interest and
AFUDC related to debt of $19 million, $45 million and $68 million, respectively.

(i) INCOME TAXES

The Company files a consolidated federal income tax return. The Company
follows a policy of comprehensive interperiod income tax allocation. The Company
uses the liability method of accounting for deferred income taxes and measures
deferred income taxes for all significant income tax temporary differences.
Investment tax credits were deferred and are being amortized over the estimated
lives of the related property. Unremitted earnings from the Company's foreign
operations are deemed to be permanently reinvested in foreign operations. For
additional information regarding income taxes, see Note 13.

(j) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable, principally from customers, are net of an allowance
for doubtful accounts of $89 million and $136 million at December 31, 2000 and
2001, respectively. The provision for doubtful
143

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

accounts in the Company's Statements of Consolidated Income for 1999, 2000 and
2001 was $16 million, $80 million and $90 million, respectively. In addition,
during the year ended December 31, 2001, the Company wrote off $15 million of
receivables for refunds related to energy sales in California and $88 million
related to energy sales to Enron Corp. and its affiliates (Enron) which filed a
voluntary petition for bankruptcy during the fourth quarter of 2001. For
information regarding the provision against receivable balances related to
energy sales in the California market and to Enron, see Notes 14(g) and 21,
respectively.

During 1999, 2000 and 2001, the Company had an agreement under which it
sold substantially all of the customer accounts receivable of Reliant Energy
HL&P. Receivables aggregating $4.4 billion, $4.9 billion and $5.8 billion were
sold in 1999, 2000 and 2001, respectively. In December 2001, Reliant Energy HL&P
terminated the agreement under which it sold its customer accounts receivable
and recorded an early termination charge of $20 million in the Statements of
Consolidated Income. Proceeds for the repurchase of receivables, which occurred
in January 2002, were obtained from a combination of bank loans and the sale of
commercial paper. Net proceeds from the sale of customer accounts receivable
were $523 million at December 31, 2001. Such proceeds were not reflected as debt
in the Consolidated Balance Sheets.

(k) INVENTORY

Inventory consists principally of materials and supplies, coal and lignite,
natural gas and heating oil. Inventories used in the production of electricity
and in the retail natural gas distribution operations are valued at the lower of
average cost or market except for coal and lignite, which are valued under the
last-in, first-out method. Heating oil and natural gas used in the trading and
marketing operations are accounted for under mark-to-market accounting as
discussed in Note 5.

(l) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES

In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value within other long-term
assets in the Company's Consolidated Balance Sheets and any unrealized gain or
loss, net of tax, as a separate component of stockholders' equity and
accumulated other comprehensive (loss) income. In accordance with SFAS No. 115,
the Company reports "trading" securities at estimated fair value in the
Company's Consolidated Balance Sheets, and any unrealized holding gains and
losses are recorded as other income (expense) in the Company's Statements of
Consolidated Income.

As of December 31, 2000 and 2001, the Company held "available-for-sale"
debt and equity securities in its nuclear decommissioning trust, which is
reported at its fair value of $159 million and $169 million, respectively, in
the Company's Consolidated Balance Sheets in other long-term assets. Any
unrealized losses or gains are accounted for in accordance with SFAS No. 71 as a
regulatory asset/liability.

In addition, as of December 31, 2000 and 2001, the Company held marketable
equity securities of $5 million and $12 million, respectively, classified as
"available-for-sale." At December 31, 2000, the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

accumulated unrealized loss, net of tax, relating to these equity securities was
$2 million. At December 31, 2001, the accumulated unrealized gain, net of tax,
relating to these equity securities was $6 million.

During 2000, pursuant to SFAS No. 115, the Company incurred a pre-tax
impairment loss equal to the $27 million of cumulative unrealized losses that
had been charged to accumulated other comprehensive loss through December 31,
1999. Management's determination to recognize this impairment resulted from a
combination of events occurring in 2000 related to this investment. These events
affecting the investment included changes occurring in the investment's senior
management, announcement of significant restructuring charges and related
downsizing for the entity, reduced earnings estimates for this entity by
brokerage analysts and the bankruptcy of a competitor of the investment in the
first quarter of 2000. These events, coupled with the stock market value of the
Company's investment in these securities continuing to be below the Company's
cost basis, caused management to believe the decline in fair value of these
"available-for-sale" securities to be other than temporary.

As of December 31, 2000 and 2001, the Company held an investment in AOL
Time Warner common stock, which was classified as a "trading" security. For
information regarding the Company's investment in AOL Time Warner, Inc. common
stock, see Note 8.

As of December 31, 2000, the Company did not hold debt or equity securities
that are classified as "trading", other than its investment in AOL Time Warner.
As of December 31, 2001, the Company held equity securities classified as
"trading" totaling $1 million, other than its investment in AOL Time Warner. The
Company recorded unrealized holding gains on "trading" securities, excluding
unrealized gains and losses related to the Company's investment in AOL Time
Warner, included in gains from investments in the Statements of Consolidated
Income of $16 million, $4 million and $5 million during 1999, 2000 and 2001,
respectively.

(m) PROJECT DEVELOPMENT COSTS

Project development costs include costs for professional services, permits
and other items that are incurred incidental to a particular project. The
Company expenses these costs as incurred until the project is considered
probable. After a project is considered probable, capitalizable costs incurred
are capitalized to the project. When project operations begin, the Company
begins to amortize these costs on a straight-line basis over the life of the
facility. As of December 31, 2000 and 2001, the Company had recorded in the
Consolidated Balance Sheets project development costs of $7 million and $9
million, respectively.

(n) ENVIRONMENTAL COSTS

The Company expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. The Company expenses
amounts that relate to an existing condition caused by past operations, and that
do not have future economic benefit. The Company records undiscounted
liabilities related to these future costs when environmental assessments and/or
remediation activities are probable and the costs can be reasonably estimated.
Subject to SFAS No. 71, a corresponding regulatory asset is recorded in
anticipation of recovery through the rate making process by subsidiaries that
apply SFAS No. 71 in some circumstances.

(o) FOREIGN CURRENCY ADJUSTMENTS

Local currencies are the functional currency of the Company's 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. Through

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

December 31, 2001, the U.S. dollar had been the functional currency for the
Company's operations in Argentina since the revenues and costs of these
operations were based primarily on U.S. dollar-indexed contracts. Since the
inception of the Company's operations in Argentina, the Argentine peso has been
pegged to the U.S. dollar at a rate of one Argentine peso to one U.S. dollar. As
a result, no foreign currency adjustments have resulted from these operations
through 2001. The Company has determined that the functional currency for its
Argentina operations in 2002 will be the Argentine peso as a result of Argentine
legislation enacted in January 2002 requiring that all U.S. dollar-indexed
contracts be restructured to Argentine pesos.

(p) STATEMENTS OF CONSOLIDATED CASH FLOWS

For purposes of reporting cash flows, the Company considers cash
equivalents to be short-term, highly liquid investments with maturities of three
months or less from the date of purchase. As of December 31, 2001, the Company
has recorded $167 million of restricted cash that is available for Reliant
Energy Mid-Atlantic Power Holdings LLC and its subsidiaries' (collectively,
REMA) working capital needs and future lease payments. For additional discussion
regarding REMA's lease transactions, see Note 14(b). In connection with a
financing completed in October 2001, the Company was required to establish
restricted cash accounts to collateralize the bonds that were issued in this
financing transaction. These restricted cash accounts are reflected as
Restricted Cash in the Consolidated Balance Sheets and are classified as
long-term as they are not available for withdrawal until the maturity of the
bonds. Cash and Cash Equivalents does not include Restricted Cash. For
additional information regarding the securitization financing, see Note 4(a).

(q) NEW ACCOUNTING PRONOUNCEMENTS

Staff Accounting Bulletin No. 101, "Revenue Recognition" (SAB No. 101), was
issued by the SEC on December 3, 1999. SAB No. 101 summarizes certain of the SEC
staff's views in applying generally accepted accounting principles to revenue
recognition in financial statements. The consolidated financial statements
reflect the accounting guidance provided in SAB No. 101.

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141 "Business Combinations" (SFAS No. 141) and SFAS No. 142 "Goodwill and
Other Intangible Assets" (SFAS No. 142). SFAS No. 141 requires business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method of accounting and broadens the criteria for recording intangible
assets separate from goodwill. Recorded goodwill and intangibles will be
evaluated against these new criteria and may result in certain intangibles being
transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. SFAS
No. 142 provides for a nonamortization approach, whereby goodwill and certain
intangibles with indefinite lives will not be amortized into results of
operations, but instead will be reviewed periodically for impairment and written
down and charged to results of operations only in the periods in which the
recorded value of goodwill and certain intangibles with indefinite lives is more
than its fair value. The Company adopted the provisions of each statement which
apply to goodwill and intangible assets acquired prior to June 30, 2001 on
January 1, 2002. The adoption of SFAS No. 141 did not have a material impact on
the Company's historical results of operations or financial position. On January
1, 2002, the Company discontinued amortizing goodwill into the results of
operations pursuant to SFAS No. 142. The Company recognized $81 million of
goodwill amortization expense in the Statements of Consolidated Income during
2001, excluding a $19 million write-off of its Communications business goodwill
balance which was recorded as goodwill amortization expense (see Note 20). The
Company is in the process of determining further effects of adoption of SFAS No.
142 on its consolidated financial statements, including the review of goodwill
and certain intangible assets for impairment. The Company has not completed its
review pursuant to SFAS No. 142. However, based on the Company's preliminary
review, the Company believes an impairment of its European Energy business
segment goodwill is reasonably possible. As of December 31, 2001, net goodwill
associated with the European Energy business segment is $632 million. The
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company has not completed its preliminary review of its other business segments
with net goodwill totaling $2.0 billion. The Company anticipates finalizing its
review of goodwill and certain intangible assets during 2002.

In August 2001, the FASB issued 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. SFAS No. 143 is effective for fiscal years beginning after
June 15, 2002, with earlier application encouraged. SFAS No. 143 requires
entities to record a cumulative effect of change in accounting principle in the
income statement in the period of adoption. The Company plans to adopt SFAS No.
143 on January 1, 2003 and is in the process of determining the effect of
adoption on its consolidated financial statements. For certain operations
subject to cost of service rate regulation, the Company is permitted to include
annual charges for cost of removal and nuclear decommissioning costs in the
revenues charged to customers.

In August 2001, the FASB issued SFAS No. 144 "Accounting for the Impairment
or Disposal of Long-Lived Assets" (SFAS No. 144). SFAS No. 144 provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121
and APB Opinion No. 30, while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 is effective for fiscal years beginning
after December 15, 2001, with early adoption encouraged. SFAS No. 144 is not
expected to materially change the methods used by the Company to measure
impairment losses on long-lived assets, but may result in additional future
dispositions being reported as discontinued operations than was previously
permitted. The Company adopted SFAS No. 144 on January 1, 2002.

See Note 5 for the Company's adoption of SFAS No. 133, "Accounting for
Derivative Instruments and Hedging Activities," as amended (SFAS No. 133) on
January 1, 2001 and adoption of subsequent cleared guidance.

(3) BUSINESS ACQUISITIONS

(a) RELIANT ENERGY MID-ATLANTIC POWER HOLDINGS, LLC

On May 12, 2000, a subsidiary of the Company purchased entities owning
electric power generating assets and development sites located in Pennsylvania,
New Jersey and Maryland having an aggregate net generating capacity of
approximately 4,262 MW. With the exception of development entities that were
sold to another subsidiary of Reliant Resources in July 2000, the assets of the
entities acquired are held by REMA. The purchase price for the May 2000
transaction was $2.1 billion. In 2002, the Company made an $8 million payment to
the prior owner for post-closing adjustments which resulted in an adjustment to
purchase price. The Company accounted for the acquisition as a purchase with
assets and liabilities of REMA reflected at their estimated fair values. The
Company's fair value adjustments related to the acquisition primarily included
adjustments in property, plant and equipment, air emissions regulatory
allowances, specific intangibles, materials and supplies inventory,
environmental reserves and related deferred taxes. The air emissions regulatory
allowances of $153 million are being amortized on a units-of-production basis as
utilized. The specific intangibles which relate to water rights and permits of
$43 million will be amortized over the estimated life of the related facility of
35 years. The excess of the purchase price over the fair value of the net assets
acquired of $5 million was recorded as goodwill and historically was amortized
over 35 years. The
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Company finalized these fair value adjustments in May 2001. There were no
additional material modifications to the preliminary adjustments from December
31, 2000. Funds for the acquisition of REMA were made available through
commercial paper borrowings by a finance subsidiary, which borrowings were
supported by credit facilities.

The net purchase price of REMA was allocated and the fair value adjustments
to the seller's book value are as follows:

Adjustments to property, plant and equipment, other intangibles which
includes air emissions regulatory allowances and other specific intangibles, and
environmental reserves included in other liabilities are based primarily on
valuation reports prepared by independent appraisers and consultants.

In August 2000, the Company, through subsidiaries, entered into separate
sale-leaseback transactions with each of three owner-lessors covering the
subsidiaries' respective 16.45%, 16.67% and 100% interests in the Conemaugh,
Keystone and Shawville generating stations, respectively, acquired as part of
the REMA acquisition. As lessee, Reliant Resources leases an interest in each
facility from each owner-lessor under a facility lease agreement. As
consideration for the sale of the Company's interest in the facilities, the
Company received $1.0 billion in cash. The Company used the $1.0 billion of sale
proceeds to repay certain commercial paper borrowings as described above.

The Company's results of operations include the results of REMA only for
the period beginning May 12, 2000. The following table presents selected actual
financial information and unaudited pro forma information for 1999 and 2000, as
if the acquisition had occurred on November 24, 1999 and January 1, 2000, as
applicable. Pro forma information for operations prior to November 24, 1999
would not be meaningful since historical financial results of the business and
the revenue generating activities underlying that period are substantially
different from the wholesale generation activities that REMA has been engaged in
after November 24, 1999. Pro forma amounts also give effect to the sale and
leaseback of interests in three of the REMA generating plants, which were
consummated in August 2000.

These unaudited pro forma results, based on assumptions deemed appropriate
by the Company's management, have been prepared for informational purposes only
and are not necessarily indicative of the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

amounts that would have resulted if the acquisition of the REMA entities had
occurred on November 24, 1999 and January 1, 2000, as applicable.
Purchase-related adjustments to the results of operations include the effects on
depreciation and amortization, interest expense and income taxes.

(b) RELIANT ENERGY POWER GENERATION BENELUX N.V.

Effective October 7, 1999, a subsidiary of the Company acquired REPGB, a
Dutch electric generation company, for a total net purchase price, payable in
Dutch Guilders (NLG), of $1.9 billion based on an exchange rate on October 7,
1999 of 2.06 NLG per U.S. dollar. The aggregate purchase price paid in 1999 by
the Company consisted of $833 million in cash. On March 1, 2000, under the terms
of the acquisition agreement, the Company funded the remaining purchase
obligation for $982 million. A portion ($596 million) of this obligation was
financed with a three-year term loan facility obtained in the first quarter of
2000.

The Company recorded the REPGB acquisition under the purchase method of
accounting, with assets and liabilities of REPGB reflected at their estimated
fair values. As outlined in the table below, the Company's fair value
adjustments related to the acquisition of REPGB primarily included increases in
property, plant and equipment, long-term debt, severance liabilities,
post-employment benefit liabilities and deferred foreign taxes. Additionally, a
$19 million receivable was recorded in connection with the acquisition as the
selling shareholders agreed to reimburse REPGB for some obligations incurred
prior to the purchase of REPGB. Adjustments to property, plant and equipment are
based on valuation reports prepared by independent appraisers and consultants.
The excess of the purchase price over the fair value of net assets acquired of
$877 million was recorded as goodwill and was historically amortized on a
straight-line basis over 30 years. The Company finalized these fair value
adjustments in September 2000. In 2002, the Company recorded a $43 million
reduction in goodwill related to the accounting for the purchase of treasury
shares. The Company finalized a severance plan (REPGB Plan) in connection with
the REPGB acquisition in September 2000 (commitment date) and in accordance with
EITF Issue No. 95-3 "Recognition of Liabilities in Connection with a Purchase
Business Combination," recorded this liability of $19 million in the third
quarter of 2000. During 2001, the Company utilized $8 million of the reserve for
the REPGB Plan. As of December 31, 2001, the remaining severance liability is
$11 million. The majority of the $11 million of remaining severance liability
will be disbursed in accordance with the terms and conditions outlined by a
collective labor bargaining agreement regarding employees near retirement age
(Social Plan) in accordance with applicable Dutch labor law. The Social Plan,
which by formula defines termination benefits, prescribes a payout period for up
to five years for an employee subsequent to termination date. In the fourth
quarter of 2001, the Dutch taxing authority finalized REPGB's tax basis of
property, plant and equipment as of October 1999. As a result, the Company
recorded an adjustment to decrease goodwill and accumulated deferred tax
liability by $5 million in the fourth quarter of 2001. As of December 31, 2001,
the tax basis of other certain assets and liabilities has not been finalized.

In connection with the acquisition of REPGB, the Company developed a
comprehensive business process reengineering and employee severance plan
intended to make REPGB competitive in the deregulated Dutch electricity market
that began January 1, 2001. The REPGB Plan's initial conceptual formulation was
initiated prior to the acquisition of REPGB in October 1999. The finalization of
the REPGB Plan was approved and completed in September 2000. The Company
identified 195 employees who were involuntarily terminated in REPGB's following
functional areas: plant operations and maintenance, procurement, inventory,
general and administrative, legal, finance and support. The Company has notified
all employees identified under the severance component of the REPGB Plan that
they are subject to involuntary termination and the majority of terminations
occurred during 2001. The termination benefits under the REPGB Plan are governed
by REPGB's Social Plan, a collective bargaining agreement between REPGB and its
various representative labor unions signed in 1998. The Social Plan provides
defined benefits for involuntarily severed employees depending upon age, tenure
and other factors, and was agreed to by the management of REPGB as a result of
the anticipated deregulation of the Dutch electricity market. The Social Plan is
still in force and binding on
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

the current management of the Company and REPGB. The Company is still executing
the REPGB Plan as of the date of these consolidated financial statements.

The net purchase price of REPGB was allocated and the fair value
adjustments to the seller's book value are as follows:

The following table presents selected actual financial information for 1999
and unaudited pro forma information for 1999, as if the acquisition of REPGB had
occurred on January 1, 1999. The pro forma results are based on assumptions
deemed appropriate by the Company's management, have been prepared for
informational purposes only and are not necessarily indicative of the
consolidated results that would have resulted if the acquisition of REPGB had
occurred on January 1, 1999. Purchase related adjustments to results of
operations include amortization of goodwill, interest expense and the effects on
depreciation and amortization of the assessed fair value of some of REPGB's net
assets and liabilities.

(c) FLORIDA GENERATION PLANT PURCHASE

On October 6, 1999, the Company purchased a steam turbine generation plant
(Indian River) with a net generating capacity of 619 MW from a Florida
municipality (Municipality) for a net purchase price of $188 million. Indian
River, located near Titusville, Florida, consists of three conventional steam
generation units fueled by both oil and natural gas. Under the Company's
ownership, the units will sell up to 578 MW of power generation from Indian
River to the Municipality through a power purchase agreement that was originally
scheduled to expire in September 2003, but has been extended through September
2007. During the option period, the Municipality has the right to purchase up to
500 MW for the first two years of the option period and 300 MW for the final two
years. Any excess power generated by the plant may be sold to other utilities
and rural electric cooperatives within the state and other entities within the
Florida wholesale market. The Company recorded the acquisition under the
purchase method of accounting. The purchase price has been allocated to assets
acquired and liabilities assumed based on their estimated fair market values at
the date of acquisition. The Company's fair value adjustments related to the
acquisition of Indian River primarily included increases in property, plant and
equipment, specific intangibles related to water rights and permits, major
maintenance reserves and related deferred taxes. The specific intangibles of
$112 million are being amortized over their contractual lives of 35 years. The
Company finalized these fair value adjustments during

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

September 2000. There were no material adjustments made to the purchase
allocation subsequent to December 31, 1999.

Net purchase price of Indian River was allocated as follows (in millions):

Current assets.............................................. $ 15
Property, plant and equipment............................... 93
Goodwill.................................................... 2
Other intangibles........................................... 112
Major maintenance reserve................................... (3)
Other long-term liabilities................................. (31)
----
Total..................................................... $188
====

The Company's results of operations include Indian River's results of
operations only for the period beginning with the October 6, 1999 acquisition
date. Pro forma information has not been presented for Indian River for 1999.
Pro forma information would not be meaningful since historical financial results
of the business and the revenue generating activities underlying that period as
described below are substantially different from the wholesale generation
activities that Indian River has been engaged in after October 6, 1999. Prior to
the Company's acquisition, the acquired Indian River generation operations were
fully integrated with, and its results of operations were consolidated into, the
Municipality's vertically-integrated utility operations. In addition, prior to
the Company's acquisition, the electric output of these facilities was sold
based on rates set by regulatory authorities and are not indicative of these
assets' future operating results as a wholesale electricity provider.

(4) REGULATORY MATTERS

(a) TEXAS ELECTRIC CHOICE PLAN AND DISCONTINUANCE OF SFAS NO. 71 FOR ELECTRIC
GENERATION OPERATIONS

In June 1999, the Texas legislature adopted the Texas Electric
Restructuring Law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail electric
competition. Retail pilot projects allowing competition for up to 5% of each
utility's load in all customer classes began in the third quarter of 2001, and
retail electric competition for all other customers began in January 2002. In
preparation for competition, the Company made significant changes in the
electric utility operations it conducts through its electric utility division,
Reliant Energy HL&P. In addition, the Texas Utility Commission issued a number
of new rules and determinations in implementing the Texas Electric Restructuring
Law.

The Texas Electric Restructuring Law defined the process for competition
and created a transition period during which most utility rates were frozen at
rates not in excess of their then-current levels. The Texas Electric
Restructuring Law provided for utilities to recover their generation related
stranded costs and regulatory assets (as defined in the Texas Electric
Restructuring Law).

Retail Choice. Under the Texas Electric Restructuring Law, beginning
January 1, 2002, retail customers of most investor owned electric utilities in
Texas became eligible to purchase their electricity from any of a number of
"retail electric providers," which are certified by the Texas Utility
Commission. Retail electric providers may not own or operate generation assets
and their sales prices are not subject to traditional cost-of-service rate
regulation. Retail electric providers that are affiliates of electric utilities
may compete substantially statewide for these sales, but prices they charge
within the affiliated electric utility's traditional service territory are
subject to some limitations at the outset of retail choice, as described below.
The Texas Utility Commission has prescribed regulations governing quality,
reliability and other aspects of service from retail electric providers. Reliant
Resources intends to compete in the Texas retail market and, as a result, has
certified three of its subsidiaries as retail electric providers.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Unbundling. As of January 1, 2002, electric utilities in Texas such as
Reliant Energy HL&P unbundled their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Texas Electric Restructuring Law, the Company submitted a
plan in January 2000 that was later amended and updated to accomplish the
required separation (the Business Separation Plan). For additional information
regarding the Business Separation Plan, see Note 4(b). The transmission and
distribution business will continue to be subject to cost-of-service rate
regulation and will be responsible for the delivery of electricity to retail
customers. The Company plans to transfer the Texas generation facilities that
were formerly part of the Reliant Energy HL&P integrated utility (Texas
generation business) to an indirect wholly owned partnership (Texas Genco) in
connection with the Restructuring. As a result of these changes, the Company's
Texas generation operations will no longer be conducted as part of an integrated
utility and will comprise a new business segment in 2002, Electric Generation.
Additionally, these operations will not be part of the Company's business if
they are acquired in 2004 by Reliant Resources pursuant to an option agreement
as described below. At that time, Reliant Resources will be an unaffiliated
company as a result of the planned Distribution.

Generation. Power generators began selling electric energy to wholesale
purchasers, including retail electric providers, at unregulated prices on
January 1, 2002. To facilitate a competitive market, each power generation
company affiliated with a transmission and distribution utility is required to
sell at auction 15% of the output of its installed generating capacity. The
first auction was held in September 2001 for power delivered beginning January
1, 2002. This obligation continues until January 1, 2007 unless before that date
the Texas Utility Commission determines that at least 40% of the quantity of
electric power consumed in 2000 by residential and small commercial load in the
electric utility's service area is being served by retail electric providers
other than the affiliated retail electric provider. See Note 4(b) for
information regarding the capacity auctions and the effect of the Business
Separation Plan on the Company. Texas Genco plans to auction all of its
remaining capacity (less approximately 10% withheld to provide for unforeseen
outages) during the time period prior to Reliant Resources' exercise of the
Texas Genco option discussed below. Pursuant to the Business Separation Plan,
Reliant Resources is entitled to purchase, at prices established in these
auctions, 50% (but no less than 50%) of the remaining capacity, energy and
ancillary services auctioned by Texas Genco.

Rates. Base rates charged by Reliant Energy HL&P on September 1, 1999 were
frozen until January 1, 2002. Pursuant to Texas Utility Commission regulations,
effective January 1, 2002, after the cycle meter read in January 2002, retail
rates charged to residential and small commercial customers by an affiliated
retail electric provider were reduced by 6% from the average rates (on a bundled
basis) in effect on January 1, 1999. Following adjustments for changes in fuel
prices, this actually resulted in a 17% rate reduction for Reliant Resources,
through its subsidiaries, as an affiliated retail provider. That reduced rate,
known as the "price to beat", is being charged by the affiliated retail electric
provider to residential and small commercial customers in the utility's service
area who have not elected service from another retail electric provider. The
affiliated retail electric provider may not offer different rates to residential
or small commercial customer classes in the utility's service area until the
earlier of the date the Texas Utility Commission determines that 40% of power
consumed by that class in the affiliated transmission and distribution utility's
service area is being served by non-affiliated retail electric providers or
January 1, 2005. In addition, the affiliated retail electric provider must make
the price to beat rate available to eligible consumers until January 1, 2007.

Stranded Costs. Reliant Energy HL&P will be entitled to recover its
stranded costs (i.e., the excess of net book value of generation assets (as
defined by the Texas Electric Restructuring Law) over the market value of those
assets) and its regulatory assets related to generation. The Texas Electric
Restructuring Law prescribes specific methods for determining the amount of
stranded costs and the details for their recovery. During the transition period
to deregulation (the Transition Period) which included 1998 and the first six
months of 1999, and extending through the base rate freeze period from July 1999
through 2001, the Texas Electric Restructuring Law provided that earnings above
a stated overall annual rate of return on invested
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

capital be used to recover the Electric Operations business segments' investment
in generation assets (Accelerated Depreciation). In addition, during the
Transition Period, the redirection of depreciation expense to generation assets
that the Electric Operation business segment would otherwise apply to
transmission, distribution and general plant assets was permitted for regulatory
purposes (Redirected Depreciation). See discussion of the accounting treatment
of Accelerated Depreciation and Redirected Depreciation for financial reporting
purposes below under "Accounting." We cannot predict the amount, if any, of
these costs that may not be recovered.

In accordance with the Texas Electric Restructuring Law, beginning on
January 1, 2002, and ending when the true-up proceeding is completed in January
2004, any difference between market power prices received in the generation
capacity auction and the Texas Utility Commission's earlier estimates of those
market prices will be included in the 2004 stranded cost true-up, as further
discussed below. This component of the true-up is intended to ensure that
neither the customers nor the Company are disadvantaged economically as a result
of the two-year transition period by providing this pricing structure.

On October 24, 2001, Reliant Energy Transition Bond Company LLC (Bond
Company), a Delaware limited liability company and direct wholly owned
subsidiary of Reliant Energy, issued $749 million aggregate principal amount of
its Series 2001-1 Transition Bonds pursuant to a financing order of the Texas
Utility Commission. Classes of the bonds have final maturity dates of September
15, 2007, September 15, 2009, September 15, 2011 and September 15, 2015, and
bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively. Scheduled
payments on the bonds are from 2002 through 2013. Net proceeds to the Bond
Company from the issuance were $738 million. The Bond Company paid Reliant
Energy $738 million for the transition property. Reliant Energy used the net
proceeds for general corporate purposes, including the repayment of
indebtedness.

The Transition Bonds are secured primarily by the "transition property,"
which includes the irrevocable right to recover, through non-bypassable
transition charges payable by certain retail electric customers, the qualified
costs of Reliant Energy HL&P authorized by the financing order. The holders of
the Bond Company's bonds have no recourse to any assets or revenues of Reliant
Energy, and the creditors of Reliant Energy have no recourse to any assets or
revenues (including, without limitation, the transition charges) of the Bond
Company. Reliant Energy has no payment obligations with respect to the
Transition Bonds except to remit collections of transition charges as set forth
in a servicing agreement between Reliant Energy and the Bond Company and in an
intercreditor agreement among Reliant Energy, the Bond Company and other
parties.

Costs associated with nuclear decommissioning will continue to be subject
to cost-of-service rate regulation and are included in a charge to transmission
and distribution customers. For further discussion of the effect of the Business
Separation Plan on funding of the nuclear decommissioning trust fund, see Note
4(b).

True-Up Proceeding. The Texas Electric Restructuring Law and current Texas
Utility Commission implementation guidance provide for a True-up Proceeding to
be initiated in January 2004. The purpose of the True-up Proceeding is to
quantify and reconcile the amount of stranded costs, the capacity auction
true-up, unreconciled fuel costs (see Note 2(f)), and other regulatory assets
associated with Reliant Energy HL&P's electric generating operations that were
not previously securitized through the Transition Bonds. The True-up Proceeding
will result in either additional charges or credits being assessed on certain
retail electric customers.

Accounting. Historically, Reliant Energy HL&P has applied the accounting
policies established in SFAS No. 71. Effective June 30, 1999, the Company
applied SFAS No. 101 to Reliant Energy HL&P's electric generation operations.
Reliant Energy HL&P's transmission and distribution operations continue to meet
the criteria of SFAS No. 71.

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In 1999, the Company evaluated the effects that the Texas Electric
Restructuring Law would have on the recovery of its generation related
regulatory assets and liabilities. The Company determined that a pre-tax
accounting loss of $282 million existed because it believes only the economic
value of its generation related regulatory assets (as defined by the Texas
Electric Restructuring Law) will be recovered. Therefore, the Company recorded a
$183 million after-tax extraordinary loss in the fourth quarter of 1999.
Pursuant to EITF Issue No. 97-4, the remaining recoverable regulatory assets
will not be written off and will become associated with the transmission and
distribution portion of the Company's electric utility business. For details
regarding Reliant Energy HL&P's regulatory assets, see Note 2(f).

At June 30, 1999, the Company performed an impairment test of its
previously regulated electric generation assets pursuant to SFAS No. 121 on a
plant specific basis. Under SFAS No. 121, an asset is considered impaired, and
should be written down to fair value, if the future undiscounted net cash flows
expected to be generated by the use of the asset are insufficient to recover the
carrying amount of the asset. For assets that are impaired pursuant to SFAS No.
121, the Company determined the fair value for each generating plant by
estimating the net present value of future cash inflows and outflows over the
estimated life of each plant. The difference between fair value and net book
value was recorded as a reduction in the current book value. The Company
determined that $808 million of electric generation assets were impaired in
1999. Of this amount, $756 million related to the South Texas Project Electric
Generating Station (South Texas Project) and $52 million related to two
gas-fired generation plants. The Texas Electric Restructuring Law provides for
recovery of this impairment through regulated cash flows during the transition
period and through charges to transmission and distribution customers. As such,
a regulatory asset was recorded for an amount equal to the impairment loss and
was included on the Company's Consolidated Balance Sheets as a regulatory asset.
The Company recorded amortization expense related to the recoverable impaired
plant costs and other assets created from discontinuing SFAS No. 71 of $221
million in the third and fourth quarters of 1999, $329 million in 2000 and $258
million in 2001.

The impairment analysis requires estimates of possible future market
prices, load growth, competition and many other factors over the lives of the
plants. The resulting impairment loss is highly dependent on these underlying
assumptions. In addition, after January 10, 2004, Reliant Energy HL&P must
finalize and reconcile stranded costs (as defined by the Texas Electric
Restructuring Law) in a filing with the Texas Utility Commission. Any positive
difference between the regulatory net book value and the fair market value of
the generation assets (as defined by the Texas Electric Restructuring Law) will
be collected through future charges. Any overmitigation of stranded costs may be
refunded by a reduction in future charges. This final reconciliation allows
alternative methods of third party valuation of the fair market value of these
assets, including outright sale, stock valuations and asset exchanges.

In order to reduce potential exposure to stranded costs related to
generation assets, Reliant Energy HL&P redirected $195 million and $99 million
of depreciation in 1998 and for the six months ended June 30, 1999,
respectively, from transmission and distribution related plant assets to
generation assets for regulatory and financial reporting purposes (Redirected
Depreciation). This redirection was in accordance with the Company's Transition
Plan. Subsequent to June 30, 1999, Redirected Depreciation expense could no
longer be recorded by the electric generation operations portion of Reliant
Energy HL&P for financial reporting purposes as this portion of electric
operations is no longer accounted for under SFAS No. 71. During the six months
ended December 31, 1999 and during 2000 and 2001, $99 million, $218 million and
$230 million in depreciation expense, respectively, was redirected from
transmission and distribution for regulatory and financial reporting purposes
and was established as an embedded regulatory asset included in transmission and
distribution related plant and equipment balances. As of December 31, 2000 and
2001, the cumulative amount of Redirected Depreciation for regulatory purposes
was $611 million and $841 million, respectively, prior to the effects of the
October 3, 2001 order discussed below.

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Additionally, as allowed by the Texas Utility Commission, in an effort to
further reduce potential exposure to stranded costs related to generation
assets, Reliant Energy recorded Accelerated Depreciation of $194 million and
$104 million in 1998 and for the six months ended June 30, 1999, respectively,
for regulatory and financial reporting purposes. Accelerated Depreciation
expense was recorded in accordance with the Company's Transition Plan during
this period. Subsequent to June 30, 1999, Accelerated Depreciation expense could
no longer be recorded by the electric generation operations portion of Reliant
Energy HL&P for financial reporting purposes, as this portion of electric
operations is no longer accounted for under SFAS No. 71. During the six months
ended December 31, 1999 and during 2000 and 2001, $179 million, $385 million and
$264 million of Accelerated Depreciation was recorded for regulatory reporting
purposes, reducing the regulatory book value of Reliant Energy HL&P's electric
generation assets.

The Texas Utility Commission issued a final order on October 3, 2001
(October 3, 2001 Order) that established the transmission and distribution
utility rates that became effective January 2002. In this Order, the Texas
Utility Commission found that Reliant Energy HL&P had overmitigated its stranded
costs by redirecting transmission and distribution depreciation and by
accelerating depreciation of generation assets as provided under the Transition
Plan and Texas Electric Restructuring Law. As a result of the October 3, 2001
Order, Reliant Energy HL&P was required to reverse the $841 million embedded
regulatory asset related to Redirected Depreciation, thereby reducing the net
book value of transmission and distribution assets. Reliant Energy HL&P was
required to record a regulatory liability of $1.1 billion related to Accelerated
Depreciation. The October 3, 2001 Order requires this amount to be refunded
through excess mitigation credits to certain retail electric customers during a
seven year period beginning in January 2002. On appeal, a Texas District court
upheld the Texas Utility Commission's order. An appeal may be taken to a Texas
Court of Appeal, but no further appeal has yet been filed.

As of December 31, 2001, in contemplation of the True-up Proceeding,
Reliant Energy HL&P has recorded a regulatory asset of $2.0 billion representing
the estimated recovery of previously incurred stranded costs, which includes a
regulatory liability of $1.1 billion plus the reversal of previously recorded
Redirected Depreciation. This estimated recovery is based upon current
projections of the market value of the Reliant Energy HL&P electric generation
assets to be covered by the True-up Proceeding calculations. Because generally
accepted accounting principles require the Company to estimate fair market
values in advance of the final reconciliation, the financial impacts of the
Texas Electric Restructuring Law with respect to the final determination of
stranded costs in 2004 are subject to material changes. Factors affecting such
changes may include estimation risk, uncertainty of future energy and commodity
prices and the economic lives of the plants. If events were to occur that made
the recovery of some of the remaining generation related regulatory assets no
longer probable, the Company would write off the remaining balance of such
assets as a charge against earnings. For additional discussion of potential
future impairment of the assets of the Company's Texas generation business, see
Note 2(e).

Other Accounting Policy Changes. As a result of discontinuing SFAS No. 71,
effective July 1, 1999, allowance for funds used during construction is no
longer accrued on generation related construction projects. Instead, interest is
being capitalized on these projects in accordance with SFAS No. 34,
"Capitalization of Interest Cost."

Previously, in accordance with SFAS No. 71, Reliant Energy HL&P deferred
the premiums and expenses that arose when long-term debt was redeemed and
amortized these costs over the life of the new debt. If no new debt was issued,
these costs would be amortized over the remaining original life of the retired
debt. Effective July 1, 1999, costs resulting from the retirement of debt
attributable to the generation operations of Reliant Energy HL&P will be
recorded in accordance with SFAS No. 4, "Reporting Gains and Losses from
Extinguishment of Debt," unless these costs will be recovered through regulated
cash flows. In that case, these costs will be deferred and recorded as a
regulatory asset by the entity through which the source of the regulated cash
flows will be derived.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) BUSINESS SEPARATION PLAN

Restructuring of Regulated Entities and Distribution of Reliant Resources
Stock. Pursuant to the Business Separation Plan, subject to receipt of an order
from the Securities and Exchange Commission (SEC) described below, Reliant
Energy will become a subsidiary of a new holding company, CenterPoint Energy,
which initially will own the Company's (a) electric transmission and
distribution operations, (b) natural gas distribution businesses, (c) electric
generating assets in Texas that were formerly operated by Reliant Energy HL&P,
(d) interstate pipelines, gas gathering and pipeline services operations, (e)
interests in energy companies in Latin America (see Note 19) and (f) interests
in Reliant Resources. In these Notes, references to Reliant Energy in connection
with events occurring or the performance of agreements after the Restructuring
generally refer to CenterPoint Energy.

Upon becoming a subsidiary of CenterPoint Energy, Reliant Energy will
transfer the stock of its principal operating subsidiaries to a subsidiary of
CenterPoint Energy and will transfer its electric generating assets in Texas
that were formerly operated by Reliant Energy HL&P to Texas Genco. In January
2004, Reliant Resources will have the right to exercise an option to acquire
Texas Genco, as further discussed below. As a result of the stock and asset
transfers described above, Reliant Energy will become solely a transmission and
distribution utility, with its other businesses becoming indirect subsidiaries
of CenterPoint Energy, which will assume all of Reliant Energy's debt other than
its first mortgage bonds. The indebtedness of certain wholly owned financing
subsidiaries of Reliant Energy is expected to be refinanced by the regulated
holding company by the end of 2002.

The Company anticipates that, upon completion of the Restructuring and
subject to approval by the Company's board of directors, market and other
conditions, CenterPoint Energy will distribute all of the stock it owns in
Reliant Resources to CenterPoint Energy's shareholders, affecting the separation
of its operations into two publicly traded corporations. The Company has
obtained a private letter ruling from the IRS providing for the tax-free
treatment of the Distribution that is predicated on the completion of the
Distribution by April 30, 2002. The Company has requested an extension of this
deadline. While there can be no assurance that the Company will receive the
extension, the Company anticipates that it will receive an extension that allows
it to proceed with the Distribution after April 30, 2002.

Reliant Energy has made and will continue to make internal asset and stock
transfers intended to allocate the assets and liabilities of Reliant Energy in
accordance with regulatory requirements and as contemplated by the Business
Separation Plan. Forms of each of the intercompany agreements described below
were prepared and entered into by Reliant Energy and Reliant Resources prior to
the Offering.

The Restructuring as currently planned cannot be completed unless and until
the SEC issues an order granting the required approvals under the Public Utility
Holding Company Act of 1935 (1935 Act). While the Company believes such an order
will be received, and that both the Restructuring and Distribution will be
completed during the summer of 2002, there can be no assurances that such will
be the case. The Restructuring has been designed to enable the Company to meet
all of the requirements of the Texas Electric Restructuring Law. The Company has
not formulated an alternative restructuring plan that could be implemented were
the SEC to refuse to grant the requested approvals for CenterPoint Energy.

Agreements Related to Texas Generating Assets. Pursuant to the Business
Separation Plan, Reliant Energy expects to cause Texas Genco to conduct an
initial public offering of approximately 20% of its capital stock by the end of
2002. If the initial public offering is not conducted, Reliant Energy may
distribute approximately 20% of Texas Genco's capital stock to its stockholders
in a transaction taxable both to it and its stockholders as part of the
valuation of stranded costs. In connection with the separation of its
unregulated businesses from its regulated businesses, Reliant Energy granted
Reliant Resources an option, subject to the completion of the Distribution, to
purchase all of the shares of capital stock of Texas Genco that will be owned by
Reliant Energy after the initial public offering or distribution (Texas Genco
Option). The Texas Genco

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Option may be exercised between January 10, 2004 and January 24, 2004. The per
share exercise price under the option will be the average daily closing price on
the national exchange for publicly held shares of common stock of Texas Genco
for the 30 consecutive trading days with the highest average closing price
during the 120 trading days immediately preceding January 10, 2004, plus a
control premium, up to a maximum of 10%, to the extent a control premium is
included in the valuation determination made by the Texas Utility Commission
relating to the market value of Texas Genco's common stock equity. The exercise
price is also subject to adjustment based on the difference between the cash
dividends paid during the period there is a public ownership interest in Texas
Genco and Texas Genco's earnings during that period. Reliant Resources has
agreed that if it exercises the Texas Genco Option and purchases the shares of
Texas Genco common stock, Reliant Resources will also purchase all notes and
other receivables from Texas Genco then held by Reliant Energy, at their
principal amount plus accrued interest. Similarly, if Texas Genco holds notes or
receivables from the Company, Reliant Resources will assume those obligations in
exchange for a payment to Reliant Resources by the Company of an amount equal to
the principal plus accrued interest.

Exercise of the Texas Genco Option by Reliant Resources will be subject to
various regulatory approvals, including Hart-Scott-Rodino antitrust clearance
and United States Nuclear Regulatory Commission (NRC) license transfer approval.
The option will be exercisable only if Reliant Energy or CenterPoint Energy
distributes all of the shares of Reliant Resources common stock it owns to its
shareholders.

At the time of the Restructuring, Texas Genco will become the beneficiary
of the decommissioning trust that has been established to provide funding for
decontamination and decommissioning of a nuclear electric generation station in
which Reliant Energy owns a 30.8% interest (see Note 6). The master separation
agreement provides that Reliant Energy will collect through rates or other
authorized charges to its electric utility customers amounts designated for
funding the decommissioning trust, and will pay the amounts to Texas Genco.
Texas Genco will in turn be required to deposit these amounts received from
Reliant Energy into the decommissioning trust. Upon decommissioning of the
facility, in the event funds from the trust are inadequate, Reliant Energy or
its successor will be required to collect through rates or other authorized
charges to customers as contemplated by the Texas Utilities Code all additional
amounts required to fund Texas Genco's obligations relating to the
decommissioning of the facility. Following the completion of the
decommissioning, if surplus funds remain in the decommissioning trust, the
excess will be refunded to Reliant Energy's or its successor's ratepayers.

(c) RELIANT ENERGY HL&P REGULATORY FILINGS

As of December 31, 2000 and 2001, Reliant Energy HL&P was under-collected
on fuel recovery by $558 million and $200 million, respectively. In two separate
filings with the Texas Utility Commission in 2000, Reliant Energy HL&P received
approval to implement fuel surcharges to collect the under-recovery of fuel
expenses, as well as to adjust the fuel factor to compensate for significant
increases in the price of natural gas. For additional information regarding this
matter, see Note 2(f).

On March 15, 2001, Reliant Energy HL&P filed an application with the Texas
Utility Commission to revise its fuel factor and address its undercollected fuel
costs of $389 million, which was the accumulated amount from September 2000
through February 2001, plus estimates for March and April 2001. Reliant Energy
HL&P requested to revise its fixed fuel factor to be implemented with the May
2001 billing cycle and proposed to defer the collection of the $389 million
until the 2004 stranded costs True-up Proceeding. On April 16, 2001, the Texas
Utility Commission issued an order approving interim rates effective with the
May 2001 billing cycle.

On June 21, 2001, Reliant Energy HL&P filed an application with the Texas
Utility Commission to terminate the interim factor and return to the prior fuel
factor due to the forecasted decline in natural gas prices. On July 20, 2001,
the Texas Utility Commission issued an order of dismissal approving Reliant
Energy HL&P's request that the interim rates approved on April 16, 2001,
effective with Reliant Energy HL&P's
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May 2001 billing month, be terminated and Reliant Energy HL&P prospectively bill
its customers using the prior fuel factor established in a previous order
beginning with Reliant Energy HL&P's August billing month. The Texas Utility
Commission also granted Reliant Energy HL&P a good cause exception in that
Reliant Energy HL&P will not be required to refund amounts collected through the
interim rates. Reliant Energy HL&P did not waive its right to collect any final
fuel balance. The final fuel balance is subject to review, and the amount to be
included in the 2004 stranded cost true-up will be determined during the final
fuel reconciliation. The Texas Utility Commission currently has scheduled
Reliant Energy HL&P to file its final fuel reconciliation in July 2002.

(d) ARKLA RATE CASE

On November 21, 2001, Arkla filed a rate case (Docket 01-243-U) with the
Arkansas Public Service Commission seeking an increase in rates for its Arkansas
customers of approximately $47 million on an annual basis. Arkla's last rate
increase was authorized in 1995. In the rate filing, Arkla maintains that its
rate base has grown by $183 million, and its operating expenses have increased
from $93 million to $106 million on an annual basis and, therefore, Arkla's
current rates for service to Arkansas customers do not provide a reasonable
opportunity for Arkla to cover its operating costs and earn a fair return on its
investment. A decision in the case is expected by the fourth quarter of 2002.

(5) DERIVATIVE FINANCIAL INSTRUMENTS

Effective January 1, 2001, the Company adopted SFAS No. 133, which
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts and for
hedging activities. This statement requires that derivatives be recognized at
fair value in the balance sheet and that changes in fair value be recognized
either currently in earnings or deferred as a component of other comprehensive
income (loss), depending on the intended use of the derivative, its resulting
designation and its effectiveness. If certain conditions are met, an entity may
designate a derivative instrument as hedging (a) the exposure to changes in the
fair value of an asset or liability (Fair Value Hedge), (b) the exposure to
variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign
currency exposure of a net investment in a foreign operation. For a derivative
not designated as a hedging instrument, the gain or loss is recognized in
earnings in the period it occurs.

Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax
increase in net income of $61 million and a cumulative after-tax increase in
accumulated other comprehensive loss of $252 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by approximately $703 million, $252 million, $805 million, and $341
million, respectively, in the Company's Consolidated Balance Sheets. During the
year ended December 31, 2001, $165 million of the initial after-tax transition
adjustment recognized in other comprehensive income was recognized in net
income.

The application of SFAS No. 133 is still evolving as the FASB clears issues
previously submitted to the Derivatives Implementation Group for consideration.
During the second quarter of 2001, an issue that applies exclusively to the
electric industry and allows the normal purchases and normal sales exception for
option-type contracts if certain criteria are met was approved by the FASB with
an effective date of July 1, 2001. The adoption of this cleared guidance had no
impact on the Company's results of operations. Certain criteria of this
previously approved guidance were revised in October and December 2001 and
became effective on April 1, 2002. The Company is currently in the process of
determining the effect of adoption of the revised guidance.

During the third quarter of 2001, the FASB cleared an issue related to
application of the normal purchases and normal sales exception to contracts that
combine forward and purchased option contracts. The effective date of this
guidance is April 1, 2002, and the Company is currently assessing the impact of
this

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

cleared issue and does not believe it will have a material impact on the
Company's consolidated financial statements.

The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business and are inherent in
the Company's consolidated financial statements. The Company utilizes derivative
instruments such as futures, physical forward contracts, swaps and options
(Energy Derivatives) to mitigate the impact of changes in electricity, natural
gas and fuel prices on its operating results and cash flows. The Company
utilizes cross-currency swaps, forward contracts and options to hedge its net
investments in and cash flows of its foreign subsidiaries, interest rate swaps
to mitigate the impact of changes in interest rates and other financial
instruments to manage various other market risks.

Trading and marketing operations often involve risk associated with
managing energy commodities and establishing open positions in the energy
markets, primarily on a short-term basis. These risks fall into three different
categories: price and volume volatility, credit risk of trading counterparties
and adequacy of the control environment for trading. The Company routinely
enters into Energy Derivatives to hedge purchase and sale commitments, fuel
requirements and inventories of natural gas, coal, electricity, crude oil and
products, emission allowances and other commodities and to minimize the risk of
market fluctuations in its trading, marketing, power origination and risk
management services operations.

Energy Derivatives primarily used by the Company are described below:

- Future 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,
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.

(a) ENERGY TRADING, MARKETING, POWER ORIGINATION AND PRICE RISK MANAGEMENT
ACTIVITIES

The Company offers energy price risk management services primarily related
to natural gas, electric power and other energy related commodities. These
activities also include the establishing of open positions in the energy
markets, primarily on a short-term basis, and transactions intended to optimize
the Company's power generation portfolio, but which do not qualify for hedge
accounting. The Company provides these services by utilizing a variety of
derivative instruments (Trading Energy Derivatives).

The Company applies mark-to-market accounting for all of its energy
trading, marketing, power origination and price risk management services
operations in North America and Europe, as well as to retail contracted sales to
large commercial, industrial and institutional customers. Accordingly, these
Trading Energy Derivatives are recorded at fair value with net realized and
unrealized gains (losses) recorded as a

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component of revenues. The recognized, unrealized balances are recorded as
trading and marketing assets/liabilities.

All of the fair values shown in the table above at December 31, 2000 and
2001 have been recognized in income. The fair values as of December 31, 2000 and
2001, are estimated using quoted prices where available, other valuation
techniques when market data is not available, for example in illiquid markets,
and other factors such as time value and volatility factor for the underlying
commitment. The Company's alternative pricing methodologies include, but are not
limited to, extrapolation of forward pricing curves using historically reported
data from illiquid pricing points. These same pricing techniques are used to
evaluate a contract prior to taking the position.

The fair values in the above table are subject to significant changes based
on fluctuating market prices and conditions. Changes in the assets and
liabilities from trading, power origination, marketing and price risk management
services result primarily from changes in the valuation of the portfolio of
contracts, newly originated transactions and the timing of settlements. The most
significant estimates include natural gas and power forward market prices,
volatility and credit risk. For the contracted retail electric sales to large
commercial, industrial and institutional customers, significant variables
affecting contract values also include the variability in electricity
consumption patterns due to weather and operational uncertainties (within
contract parameters). 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.

The weighted-average term of the trading portfolio, based on volumes, is
less than one year. The maximum term of the trading portfolio is 17 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 market conditions, market liquidity and the
Company's risk management portfolio needs and strategies. Terms regarding cash
settlements of these contracts vary with respect to the actual timing of cash
receipts and payments.

(b) NON-TRADING ACTIVITIES

Cash Flow Hedges. To reduce the risk from market fluctuations in revenues
and the resulting cash flows derived from the sale of electric power, natural
gas and other commodities, the Company may enter into Energy Derivatives in
order to hedge exposure to variability in cash flows (Non-trading Energy
Derivatives).

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The Non-trading Energy Derivative portfolios are managed to complement the
physical transaction portfolio, reducing overall risks within authorized limits.

The Company applies hedge accounting for its Non-trading Energy Derivatives
utilized in non-trading activities only if there is a high correlation between
price movements in the derivative and the item designated as being hedged. This
correlation, a measure of hedge effectiveness, is measured both at the inception
of the hedge and on an ongoing basis, with an acceptable level of correlation of
at least 80% to 120% for hedge designation. If and when correlation ceases to
exist at an acceptable level, hedge accounting ceases and mark-to-market
accounting is applied. During 2001, the amount of hedge ineffectiveness
recognized in earnings from derivatives that are designated and qualify as Cash
Flow Hedges was a gain of $8 million. No component of the derivative
instruments' gain or loss was excluded from the assessment of effectiveness. If
it becomes probable that an anticipated transaction will not occur, the Company
realizes in net income the deferred gains and losses recognized in accumulated
other comprehensive income (loss). During the year ended December 31, 2001,
there was a $3.6 million deferred loss recognized in earnings as a result of the
discontinuance of cash flow hedges because it was no longer probable that the
forecasted transaction would occur due to credit problems of a customer. Once
the anticipated transaction occurs, the accumulated deferred gain or loss
recognized in accumulated other comprehensive income (loss) is reclassified and
included in the Company's Statements of Consolidated Income under the captions
(a) fuel expenses, in the case of natural gas transactions, (b) purchased power,
in the case of electric power purchase transactions and (c) revenues, in the
case of electric power sales transactions. Cash flows resulting from these
transactions in Non-trading Energy Derivatives are included in the Statements of
Consolidated Cash Flows in the same category as the item being hedged. As of
December 31, 2001, the Company's current non-trading derivative assets and
liabilities and corresponding amounts in accumulated other comprehensive loss
were expected to be reclassified into net income during the next twelve months.

The maximum length of time the Company 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 eleven years.

In addition, as of December 31, 2001, the European Energy business segment
had entered into transactions to purchase $271 million at fixed exchange rates
in order to hedge future fuel purchases payable in U.S. dollars.

Interest Rate Swaps. During 2001, the Company entered into interest rate
swaps with an aggregate notional amount of $1.8 billion to fix the interest rate
applicable to floating rate short-term debt and interest rate swaps with a
notional amount of $425 million to fix the interest rate applicable to floating
rate long-term debt. At December 31, 2001, $225 million of the swaps relating to
long-term debt had expired. The swaps relating to short-term debt do not qualify
as cash flow hedges under SFAS No. 133, and are marked to market on the
Consolidated Balance Sheets with changes reflected in interest expense in the
Statements of Consolidated Income. The swaps relating to long-term debt qualify
for hedge accounting under SFAS No. 133 and the periodic settlements are
recognized as an adjustment to interest expense in the Statements of
Consolidated Income over the term of the swap agreement. During 2001, the
Company entered into forward-starting interest rate swaps having an aggregate
notional amount of $500 million to hedge the interest rate on a portion of a
future offering of five-year notes. These swaps qualify as cash flow hedges
under SFAS No. 133. Should the expected issuance of the debt no longer be
probable, any deferred amount will be recognized immediately into income. The
maximum length of time the Company is hedging its exposure to the payment of
variable interest rates is four years.

Hedge of the Foreign Currency Exposure of Net Investment in Foreign
Subsidiaries. The Company has substantially hedged the foreign currency
exposure of its net investment in its European subsidiaries through a
combination of Euro-denominated borrowings, foreign currency swaps and foreign
currency forward contracts to reduce the Company's exposure to changes in
foreign currency rates. During the normal course of business,
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the Company reviews its currency hedging strategies and determines the hedging
approach deemed appropriate based upon the circumstances of each situation.

The Company records the changes in the value of the foreign currency
hedging instruments and Euro-denominated borrowings as foreign currency
translation adjustments included as a component of accumulated other
comprehensive loss. The effectiveness of the hedging instruments can be measured
by the net change in foreign currency translation adjustments attributed to the
Company's net investment in its European subsidiaries. These amounts generally
offset amounts recorded in stockholders' equity as adjustments resulting from
translation of the hedged investment into U.S. dollars. During 2001, the
derivative and non-derivative instruments designated as hedging the net
investment in the Company's European subsidiaries resulted in a gain of $31
million, which is included in the balance of the cumulative translation
adjustment.

Other Derivatives. In December 2000, the Dutch parliament adopted
legislation allocating to the Dutch generation sector, including REPGB,
financial responsibility for various stranded costs contracts and other
liabilities. The legislation became effective in all material respects on
January 1, 2001. In particular, the legislation allocated to the Dutch
generation sectors, including REPGB, financial responsibility to purchase
electricity and gas under gas supply and electricity contracts. These contracts
are derivatives pursuant to SFAS No. 133. As of December 31, 2001, the Company
had recognized $369 million in short-term and long-term non-trading derivative
liabilities for REPGB's portion of these stranded costs contracts. Future
changes in the valuation of these stranded cost import contracts which remain an
obligation of REPGB will be recorded as adjustments to the Company's Statements
of Consolidated Income. The valuation of the contracts could be affected by,
among other things, changes in the price of electric power, coal, low sulfur
fuel oil and the value of the United States dollar and British pound relative to
the Euro. For additional information regarding REPGB's stranded costs and the
related indemnification by former shareholders of these stranded costs during
2001, see Note 14(h).

During 2001, Reliant Resources entered into two structured transactions
which were recorded on the Consolidated Balance Sheets in non-trading derivative
assets and liabilities 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 or
2003. The change in fair value of these derivative assets and liabilities must
be recorded in the Statements of Consolidated Income for each reporting period.
During 2001, $117 million of net non-trading derivative liabilities were settled
related to these transactions, and a $1 million pre-tax unrealized gain was
recognized. As of December 31, 2001, Reliant Resources has recognized $221
million of non-trading derivative assets and $103 million of non-trading
derivative liabilities related to these transactions.

(c) CREDIT RISKS

In addition to the risk associated with price movements, credit risk is
inherent in the Company's risk management activities and hedging activities.
Credit risk relates to the risk of loss resulting from non-performance of
contractual obligations by a counterparty. The Company has off-balance sheet
risk to the extent that the counterparties to these transactions may fail to
perform as required by the terms of each contract. The Company enters into
derivative instruments primarily with counterparties having at least a minimum
investment grade credit rating (i.e. a minimum credit rating for such entity's
senior unsecured debt of BBB- for Standard & Poor's and Fitch or Baa3 for
Moody's). In addition, the Company seeks to enter into netting agreements that
permit it to offset receivables and payables with a given counterparty. The
Company also attempts to enter into agreements that enable the Company to obtain
collateral from a counterparty or to terminate upon the occurrence of
credit-related events. For long-term arrangements, the Company periodically
reviews the financial condition of these counterparties in addition to
monitoring the effectiveness of these financial contracts in achieving the
Company's objectives. If the counterparties to these arrangements fail to
perform, the Company would seek to compel performance at law or otherwise obtain
compensatory damages. The Company might be forced to acquire alternative hedging
arrangements or be required to replace the

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underlying commitment at then-current market prices. In this event, the Company
might incur additional losses to the extent of amounts, if any, already paid to
the counterparties. For information regarding the provision related to energy
sales in California, see Note 14(g). For information regarding the net provision
recorded in 2001 related to energy sales to Enron, see Note 21.

The following tables show the composition of the trading and marketing
assets of the Company as of December 31, 2000 and 2001 and the non-trading
derivative assets as of December 31, 2001.

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

(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.

(2) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions, and collateral,
to create a synthetic credit rating.

(d) TRADING AND NON-TRADING -- GENERAL POLICY

The Company has established a Risk Oversight Committee comprised of
corporate and business segment officers that oversees all commodity price,
foreign currency and credit risk activities, including the Company's trading,
marketing, power origination, risk management services and hedging activities.
The committee's duties are to approve the Company's commodity risk policies,
allocate risk capital within limits established by
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the Company's board of directors, approve trading of new products and
commodities, monitor risk positions and monitor compliance with the Company's
risk management policies and procedures and trading limits established by the
Company's board of directors.

The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.

(6) JOINTLY OWNED ELECTRIC UTILITY PLANT

The Company has a 30.8% interest in the South Texas Project, which consists
of two 1,250 MW nuclear generating units and bears a corresponding 30.8% share
of capital and operating costs associated with the project. The South Texas
Project is owned as a tenancy in common among its four co-owners, with each
owner retaining its undivided ownership interest in the two nuclear-fueled
generating units and the electrical output from those units. The four co-owners
have delegated management and operating responsibility for the South Texas
Project to the South Texas Project Nuclear Operating Company (STPNOC). STPNOC is
managed by a board of directors comprised of one director from each of the four
owners, along with the chief executive officer of STPNOC. As of December 31,
2001, the total utility plant in service and construction work in progress for
the total South Texas Project was $5.8 billion and $120 million, respectively.
The Company's investment in the South Texas Project was $316 million (net of
$2.2 billion accumulated depreciation which includes an impairment loss recorded
in 1999 of $756 million). For additional information regarding the impairment
loss, see Note 4(a). The Company's investment in nuclear fuel was $35 million
(net of $286 million amortization) as of December 31, 2001.

(7) EQUITY INVESTMENTS IN UNCONSOLIDATED SUBSIDIARIES

The Company has a 50% interest in a 490 MW electric generation plant in
Boulder City, Nevada. The plant became operational in May 2000. Reliant
Resources has a 50% partnership interest in a 100 MW cogeneration plant in
Orange, Texas which began commercial operations in December 1999. In addition,
Reliant Resources, through REPGB, acquired a 22.5% interest in BV Nederlands
Elektriciteit Administratiekantoor (NEA), which was formerly the coordinating
body for the Dutch electricity generating sector. For information regarding
Reliant Resources' investment in NEA and financial impacts, see Note 14(h). See
Note 3(b) for a description of 1999 equity accounting related to REPGB during
1999.

Reliant Resources' equity investments in unconsolidated subsidiaries are as
follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Reliant Resources' income (loss) from equity investments of unconsolidated
subsidiaries is as follow:

During 1999, there were no distributions from these investments. During
2000 and 2001, $18 million and $27 million, respectively, were the net
distributions from these investments.

(8) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES

(a) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES

On July 6, 1999, the Company converted its 11 million shares of Time Warner
Inc. (TW) convertible preferred stock (TW Preferred) into 45.8 million shares of
Time Warner common stock (TW Common). Prior to the conversion, the Company's
investment in the TW Preferred was accounted for under the cost method at a
value of $990 million in the Company's Consolidated Balance Sheets. The TW
Preferred which was redeemable after July 6, 2000, had an aggregate liquidation
preference of $100 per share (plus accrued and unpaid dividends), was entitled
to annual dividends of $3.75 per share until July 6, 1999 and was convertible by
the Company. The Company recorded pre-tax dividend income with respect to the TW
Preferred of $21 million in 1999 prior to the conversion. Effective on the
conversion date, the shares of TW Common were classified as trading securities
under SFAS No. 115 and an unrealized gain was recorded in the amount of $2.4
billion ($1.5 billion after-tax) to reflect the cumulative appreciation in the
fair value of the Company's investment in Time Warner securities. Unrealized
gains and losses resulting from changes in the market value of the TW Common
(now AOL TW Common) are recorded in the Company's Statements of Consolidated
Income.

(b) ACES

In July 1997, in order to monetize a portion of the cash value of its
investment in TW Preferred, the Company issued 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES) having an original principal amount
of $1.052 billion and maturing July 1, 2000. The market value of ACES was
indexed to the market value of TW Common. On the July 1, 2000 maturity date, the
Company tendered 37.9 million shares of TW Common to fully settle its
obligations in connection with its unsecured 7% ACES having a value of $2.9
billion.

(c) ZENS

On September 21, 1999, the Company issued approximately 17.2 million of its
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an
original principal amount of $1.0 billion. The original principal amount per
ZENS will increase each quarter to the extent that the sum of the quarterly cash
dividends and the interest paid during a quarter on the reference shares
attributable to one ZENS is less than $.045, so that the annual yield to
investors from the date the Company issued the ZENS to the date of computation
of the contingent principal amount is not less than 2.309%. At December 31,
2001, the principal amount of the ZENS had increased $3 million as the reference
shares no longer pay dividends. At maturity the holders of the ZENS will receive
in cash the higher of the original principal amount of the ZENS (subject to
adjustment as discussed above) or an amount based on the then-current market
value of AOL TW
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Common, or other securities distributed with respect to AOL TW Common (1.5
shares of AOL TW Common and such other securities, if any, are referred to as
reference shares). Each ZENS has an original principal amount of $58.25, and is
exchangeable at any time at the option of the holder for cash equal to 95% (100%
in some cases) of the market value of the reference shares attributable to one
ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the
amount of any quarterly cash dividends paid in respect of the quarterly interest
period on the reference shares attributable to each ZENS. Subject to some
conditions, the Company has the right to defer interest payments from time to
time on the ZENS for up to 20 consecutive quarterly periods. As of December 31,
2001, no interest payments on the ZENS had been deferred.

The Company used $537 million of the net proceeds from the offering of the
ZENS to purchase 9.2 million shares of TW Common (now 13.8 million shares of AOL
TW Common), which are classified as trading securities under SFAS No. 115. Prior
to the purchase of additional shares of TW Common on September 21, 1999, the
Company owned approximately 8 million shares of TW Common (now 12 million shares
of AOL TW Common). The Company now holds 25.8 million shares of AOL TW Common
that are expected to be held to facilitate the Company's ability to meet its
obligation under the ZENS.

Prior to January 1, 2001, an increase above $58.25 (subject to some
adjustments) in the market value per share of TW Common resulted in an increase
in the Company's liability for the ZENS. However, as the market value per share
of TW Common declined below $58.25 (subject to some adjustments), the liability
for the ZENS did not decline below the original principal amount. The market
value per share of TW Common was $52.24 as of December 31, 2000 and the market
value per share of AOL TW Common was $32.10 as of December 31, 2001. Upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was
bifurcated into a debt component and a derivative component (the holder's option
to receive the appreciated value of AOL TW Common at maturity). The derivative
component was valued at fair value and determined the initial carrying value
assigned to the debt component ($121 million) as the difference between the
original principal amount of the ZENS ($1.0 billion) and the fair value of the
derivative component at issuance ($879 million). Effective January 1, 2001 the
debt component was recorded at its accreted amount of $122 million and the
derivative component is recorded at its current fair value of $788 million, as a
current liability, resulting in a transition adjustment pre-tax gain of $90
million ($58 million net of tax). The transition adjustment gain was reported in
the first quarter of 2001 as the effect of a change in accounting principle.
Subsequently, the debt component will accrete through interest charges at 17.5%
up to the minimum amount payable upon maturity of the ZENS in 2029,
approximately $1.1 billion, and changes in the fair value of the derivative
component will be recorded in the Company's Statements of Consolidated Income.
During 2001, the Company recorded a $70 million loss on the Company's investment
in AOL TW Common. During 2001, the Company recorded a $58 million gain
associated with the fair value of the derivative component of the ZENS
obligation. Changes in the fair value of the AOL TW Common held by the Company
are expected to substantially offset changes in the fair value of the derivative
component of the ZENS.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table sets forth summarized financial information regarding
the Company's investment in AOL TW securities and the Company's ACES and ZENS
obligations (in millions).

(9) PREFERRED STOCK AND PREFERENCE STOCK

(a) PREFERRED STOCK

At December 31, 2000, Reliant Energy had 10,000,000 authorized shares of
cumulative preferred stock, of which 97,397 shares were outstanding. As of that
date, Reliant Energy's only outstanding series of preferred stock was its $4.00
Preferred Stock. The $4.00 Preferred Stock paid an annual dividend of $4.00 per
share, was redeemable at $105 per share and had a liquidation price of $100 per
share to third parties.

On December 14, 2001, Reliant Energy redeemed all outstanding shares of its
$4.00 Preferred Stock at $105 per share plus accrued dividends of $0.478 per
share for a total redemption payment of $10.3 million. At December 31, 2001,
Reliant Energy had 10,000,000 authorized shares of cumulative preferred stock,
none of which were outstanding.

(b) PREFERENCE STOCK

At December 31, 2000 and 2001, Reliant Energy had 10,000,000 authorized
shares of preference stock, none of which were outstanding for financial
reporting purposes. At December 31, 2001, Reliant Energy had issued and
outstanding shares of preference stock that were held by various financing
subsidiaries of the Company to support debt obligations of the subsidiaries to
third party lenders. The aggregate amount of debt outstanding at these
subsidiaries at December 31, 2001 was $2.9 billion.

Reliant Energy has a Shareholder Rights Plan, which states that each share
of Reliant Energy's common stock includes one associated preference stock
purchase right (Right) which entitles the registered holder to purchase from
Reliant Energy a unit consisting of one-thousandth of a share of Series A
Preference Stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Rights, which expire on July 11, 2010, are exercisable upon some events
involving the acquisition of 20% or more of Reliant Energy's outstanding common
stock. Upon the occurrence of such an event, each Right entitles the holder to
receive common stock with a current market price equal to two times the exercise
price of the Right. At anytime prior to becoming exercisable, Reliant Energy may
repurchase the Rights at a price of $0.005 per Right. There are 700,000 shares
of Series A Preference Stock reserved for issuance upon exercise of the Rights.

(10) LONG-TERM DEBT AND SHORT-TERM BORROWINGS

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(1) Includes amounts due or exchangeable within one year of the date noted.

(2) Includes borrowings at December 31, 2000 and 2001 which are denominated in
Euros. As of December 31, 2000 and 2001, the assumed exchange rate was 1.06
Euros and 1.12 Euros per U.S. dollar, respectively.

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(3) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS
obligation was bifurcated into a debt component and an embedded derivative
component. For additional information regarding ZENS, see Note 8(b). As ZENS
are exchangeable for cash at any time at the option of the holders, these
notes are classified as a current portion of long-term debt.

(4) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in long term debt is additional
unamortized premium related to fair value adjustments of long-term debt of
$12 million and $9 million at December 31, 2000 and 2001, respectively,
which is being amortized over the respective remaining term of the related
long-term debt.

(a) SHORT-TERM BORROWINGS

As of December 31, 2001, the Company had credit facilities, which included
the facilities of various financing subsidiaries, Reliant Resources, REPGB and
RERC Corp., with financial institutions which provide for an aggregate of $11.0
billion in committed credit. The facilities expire as follows: $6.6 billion in
2002, $3.6 billion in 2003 and $0.8 billion in 2004. As of December 31, 2001,
borrowings of $4.6 billion were outstanding or supported under these credit
facilities of which $0.8 billion were classified as long-term debt, based on
availability of committed credit with expiration dates exceeding one year and
management's intention to maintain these borrowings in excess of one year. The
remaining unused credit facilities totaled $6.4 billion. Various credit
facilities aggregating $2.4 billion may be used for letters of credit of which
$0.4 billion were outstanding as of December 31, 2001. Interest rates on
borrowings are based on the London Interbank Offered Rate (LIBOR) plus a margin,
Euro interbank deposits plus a margin, a base rate or a rate determined through
a bidding process. Credit facilities aggregating $5.4 billion are unsecured. The
credit facilities contain covenants and requirements that must be met to borrow
funds and obtain letters of credit, as applicable. Such covenants are not
anticipated to materially restrict the borrowers from borrowing funds or
obtaining letters of credit, as applicable, under such facilities. As of
December 31, 2001, the borrowers are in compliance with the covenants under all
of these credit agreements.

The Company sells commercial paper to provide financing for general
corporate purposes. As of December 31, 2001, $2.5 billion of commercial paper
was outstanding. The commercial paper borrowings are supported by various credit
facilities discussed above, including $4.7 billion in credit facilities expiring
in 2002 and a $350 million revolving credit facility expiring in 2003.

RERC Corp. has a receivables facility under which it sells its customer
accounts receivable. Advances under this facility are reflected in the
Consolidated Balance Sheets as short-term debt. At December 31, 2000 and 2001,
the amount of the receivables facility was $350 million and RERC Corp. had
received advances of $350 million and $346 million, respectively. Fees and
interest expense related to this facility for 1999, 2000 and 2001 aggregated $19
million, $24 million and $15 million, respectively. The size of the receivables
facility was increased from $300 million to $350 million in August 1999. For
information on the reduction in the size of the facility in 2002, see Note
22(b).

The weighted average interest rate on short-term borrowings as of December
31, 1999, 2000 and 2001 was 5.84%, 7.43% and 3.29%, respectively.

The Company's revolving credit agreements are broadly-syndicated committed
facilities which contain "material adverse change" clauses that could impact its
ability to borrow under these facilities. The "material adverse change" clauses
generally relate to the Company's ability to perform its obligations under the
agreements.

(b) LONG-TERM DEBT

Maturities. The Company's maturities of long-term debt and sinking fund
requirements, excluding the ZENS obligation, are $538 million in 2002, $1.2
billion in 2003, $90 million in 2004, $390 million in 2005 and

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$218 million in 2006. The 2002 and 2003 amounts are net of sinking fund payments
that can be satisfied with bonds that had been acquired and retired as of
December 31, 2001.

Liens. At December 31, 2001, substantially all physical assets used in the
conduct of the business and operations of the Electric Operations business
segment are subject to liens securing the First Mortgage Bonds. After the
Restructuring, only the assets of the transmission and distribution utility are
expected to be subject to liens securing the First Mortgage Bonds. Sinking fund
requirements on the First Mortgage Bonds may be satisfied by certification of
property additions at 100% of the requirements as defined by the Mortgage and
Deed of Trust. Sinking or improvement/replacement fund requirements for 1999,
2000 and 2001 have been satisfied by certification of property additions. The
replacement fund requirement to be satisfied in 2002 is $334 million.

RERC Corp. Debt Issuance. In February 2001, RERC Corp. issued $550 million
of unsecured notes that bear interest at 7.75% per year and mature in February
2011. Net proceeds to RERC Corp. were $545 million. RERC Corp. used the net
proceeds from the sale of the notes to pay a $400 million dividend to Reliant
Energy, and for general corporate purposes. Reliant Energy used the $400 million
proceeds from the dividend for general corporate purposes, including the
repayment of short-term borrowings.

Securitization. For a discussion of the securitization financing completed
in October 2001, see Note 4(a).

Purchase of Convertible Debentures. At December 31, 2000 and 2001, RERC
Corp. had issued and outstanding $98 million and $86 million, respectively,
aggregate principal amount ($93 million and $82 million, respectively, carrying
amount) of its 6% Convertible Subordinated Debentures due 2012 (Subordinated
Debentures). The holders of the Subordinated Debentures receive interest
quarterly and have the right at any time on or before the maturity date thereof
to convert each Subordinated Debenture into 0.65 shares of Reliant Energy common
stock and $14.24 in cash. After the Restructuring, each Subordinated Debenture
will be convertible into 0.65 shares of CenterPoint Energy common stock and
$14.24 in cash. After the Distribution, each Subordinated Debenture will be
convertible into an increased number of CenterPoint Energy shares based on a
formula as provided in the relevant indenture and $14.24 in cash. During 2001,
RERC Corp. purchased $11 million aggregate principal amount of its Subordinated
Debentures.

TERM Notes. RERC Corp.'s $500 million aggregate principal amount of 6 3/8%
Term Enhanced ReMarketable Securities (TERM Notes) provide an investment bank
with a call option, which gives it the right to have the TERM Notes redeemed
from the investors on November 1, 2003 and then remarketed if it chooses to
exercise the option. The TERM Notes are unsecured obligations of RERC Corp.
which bear interest at an annual rate of 6 3/8% through November 1, 2003. On
November 1, 2003, the holders of the TERM Notes are required to tender their
notes at 100% of their principal amount. The portion of the proceeds
attributable to the call option premium will be amortized over the stated term
of the securities. If the option is not exercised by the investment bank, RERC
Corp. will repurchase the TERM Notes at 100% of their principal amount on
November 1, 2003. If the option is exercised, the TERM Notes will be remarketed
on a date, selected by RERC Corp., within the 52-week period beginning November
1, 2003. During this period and prior to remarketing, the TERM Notes will bear
interest at rates, adjusted weekly, based on an index selected by RERC Corp. If
the TERM Notes are remarketed, the final maturity date of the TERM Notes will be
November 1, 2013, subject to adjustment, and the effective interest rate on the
remarketed TERM Notes will be 5.66% plus RERC Corp.'s applicable credit spread
at the time of such remarketing.

Extinguishments of Debt. During the second quarter of 2000, REPGB
negotiated the repurchase of $272 million aggregate principal amount of its
long-term debt for a total cost of $286 million, including $14 million in
expenses. The book value of the debt repurchased was $293 million, resulting in
an extraordinary gain on the early extinguishment of long-term debt of $7
million. Borrowings under a short-term

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banking facility and proceeds from the sale of trading securities by REPGB were
used to finance the debt repurchase.

During 1999, the Company's regulated operations recorded losses from the
extinguishment of debt of $22 million. There were no losses recorded from the
early extinguishment of debt in 2000 and 2001. As these costs will be recovered
through regulated cash flows, these costs have been deferred and a regulatory
asset has been recorded. For further discussion regarding the accounting, see
Note 4(a).

(c) OFF-BALANCE SHEET FINANCINGS

For information regarding off-balance sheet financings and REMA
sale-leaseback transactions related to Reliant Resources, see Notes 14(b) and
14(l).

(11) TRUST PREFERRED SECURITIES

In February 1997, two Delaware statutory business trusts created by Reliant
Energy (HL&P Capital Trust I and HL&P Capital Trust II) issued to the public (a)
$250 million aggregate amount of preferred securities and (b) $100 million
aggregate amount of capital securities, respectively. In February 1999, a
Delaware statutory business trust created by Reliant Energy (REI Trust I) issued
$375 million aggregate amount of preferred securities to the public. Reliant
Energy accounts for REI Trust I, HL&P Capital Trust I and HL&P Capital Trust II
as wholly owned consolidated subsidiaries. Each of the trusts used the proceeds
of the offerings to purchase junior subordinated debentures issued by Reliant
Energy having interest rates and maturity dates that correspond to the
distribution rates and the mandatory redemption dates for each series of
preferred securities or capital securities.

The junior subordinated debentures are the trusts' sole assets and their
entire operations. Reliant Energy considers its obligations under the Amended
and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where
applicable, Agreement as to Expenses and Liabilities, relating to each series of
preferred securities or capital securities, taken together, to constitute a full
and unconditional guarantee by Reliant Energy of each trust's obligations with
respect to the respective series of preferred securities or capital securities.

The preferred securities and capital securities are mandatorily redeemable
upon the repayment of the related series of junior subordinated debentures at
their stated maturity or earlier redemption. Subject to some limitations,
Reliant Energy has the option of deferring payments of interest on the junior
subordinated debentures. During any deferral or event of default, Reliant Energy
may not pay dividends on its capital stock. As of December 31, 2001, no interest
payments on the junior subordinated debentures had been deferred.

In June 1996, a Delaware statutory business trust created by RERC Corp.
(RERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. RERC Corp. accounts for RERC Trust as a wholly owned
consolidated subsidiary. RERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by RERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent RERC Trust's sole assets
and its entire operations. RERC Corp. considers its obligation under the Amended
and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to
the convertible preferred securities, taken together, to constitute a full and
unconditional guarantee by RERC Corp. of RERC Trust's obligations with respect
to the convertible preferred securities.

The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Each convertible preferred security is
convertible at the option of the holder into $33.62 of cash and 1.55 shares of
Reliant Energy common stock. During 2000 and 2001, convertible preferred
securities of $0.3 million and $0.04 million,
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

respectively, were converted. As of December 31, 2000 and 2001, $0.4 million
liquidation amount of convertible preferred securities were outstanding. Subject
to some limitations, RERC Corp. has the option of deferring payments of interest
on the convertible junior subordinated debentures. During any deferral or event
of default, RERC Corp. may not pay dividends on its common stock to Reliant
Energy. As of December 31, 2001, no interest payments on the convertible junior
subordinated debentures had been deferred.

The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of each series of the preferred securities,
convertible preferred securities or capital securities of the trusts and the
identity and similar terms of each related series of junior subordinated
debentures are as follows:

(12) STOCK-BASED INCENTIVE COMPENSATION PLANS AND RETIREMENT PLANS

(a) INCENTIVE COMPENSATION PLANS

The Company has long-term incentive compensation plans (LICP) that provide
for the issuance of stock-based incentives, including performance-based shares,
performance-based units, restricted shares, stock options and stock appreciation
rights, to key employees of the Company, including officers. As of December 31,
2001, 716 current and 54 former employees of the Company participate in the
plans. A maximum of approximately 39 million shares of Reliant Energy common
stock may be issued under these plans.

Awards in Reliant Resources common stock have been made from the Reliant
Resources, Inc. Long-Term Incentive Plan (Resources LICP). Under the Resources
LICP, participant awards may be in the form of stock options, performance-based
shares or units, stock appreciation rights, restricted or unrestricted grants of
common stock. As of December 31, 2001, 735 current employees and 4 former
employees of Reliant Resources participate in the Resources LICP.

Performance-based shares, performance-based units and restricted shares are
granted to employees without cost to the participants. The performance shares
and units vest three years after the grant date based upon the performance of
the Company 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 six-year period. Upon vesting, the shares are issued
to the plans' participants.

In 2001, awards of Reliant Resources performance-based shares and
restricted shares have been made to Reliant Resources participants. For all
other participants, awards have been made in performance-based units and
restricted shares of Reliant Energy. During 1999, 2000 and 2001, the Company,
including Reliant Resources, recorded compensation expense of $8 million, $22
million and $9 million, respectively, related to performance-based shares,
performance-based units and restricted share grants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following table summarizes Reliant Energy's performance-based units,
performance-based shares and restricted share grant activity for the years 1999
through 2001:

The maximum value associated with the performance-based units granted in
2001 was $150.

The following table summarizes Reliant Resources' performance-based shares
and restricted share grant activity during 2001:

Assuming the Distribution occurs during calendar year 2002, the Company's
compensation committee will authorize the conversion of outstanding Reliant
Energy performance-based shares for the performance cycle ending December 31,
2002 to a number of time-based restricted shares of Reliant Energy's common
stock equal to the number of performance-based shares that would have vested if
the performance objectives for the performance cycle were achieved at the
maximum level. These time-based restricted shares will vest if the participant
holding the shares remains employed with the Company or with Reliant Resources
and its subsidiaries through December 31, 2002. On the date of the Distribution,
holders of these time-based restricted shares will receive shares of Reliant
Resources common stock in the same manner as other holders

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of Reliant Energy common stock, but these shares of common stock will be subject
to the same time-based vesting schedule, as well as to the terms and conditions
of the plan under which the original performance shares were granted. Thus,
following the Distribution, employees who held performance-based shares under
the LICP for the performance cycle ending December 31, 2002 will hold time-based
restricted shares of Reliant Energy common stock and time-based restricted
shares of Reliant Resources common stock, which will vest following continuous
employment through December 31, 2002.

Under both the Resources LICP and the Company's plans, stock options
generally become exercisable in one-third increments on each of the first
through third anniversaries of the grant date. The exercise price is the average
of the high and low sales price of the common stock on the New York Stock
Exchange on the grant date. The Company applies APB Opinion No. 25, "Accounting
for Stock Issued to Employees" (APB Opinion No. 25), and related interpretations
in accounting for its stock option plans. Accordingly, no compensation expense
has been recognized for these fixed stock options. The following table
summarizes stock option activity related to the Company and Reliant Resources
for the years 1999 through 2001:

Exercise prices for Reliant Energy stock options outstanding held by
Company employees ranged from $7.00 to $50.00. Exercise prices for Reliant
Resources stock options outstanding held by Company employees

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ranged from $15.65 to $34.03. The following tables provide information with
respect to outstanding Reliant Energy and Reliant Resources stock options held
by the Company's employees on December 31, 2001:

The following table provides information with respect to Reliant Energy
stock options exercisable at December 31, 2001:

As of December 31, 2001, Reliant Resources had 6,500 options exercisable at
an exercise price of $30.00.

In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation"
(SFAS No. 123), the Company applies the guidance contained in APB Opinion No. 25
and discloses the required pro forma effect on net income of the fair value
based method of accounting for stock compensation. The weighted average fair
values at date of grant for Reliant Energy options granted during 1999, 2000 and
2001 were $3.13, $5.07 and $9.25, respectively. The weighted average fair value
at date of grant for Reliant Resources options granted

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

during 2001 was $13.35. The fair values were estimated using the Black-Scholes
option valuation model with the following weighted-average assumptions:

Pro forma information for 1999, 2000 and 2001 is provided to take into
account the amortization of stock-based compensation to expense on a
straight-line basis over the vesting period. Had compensation costs been
determined as prescribed by SFAS No. 123, the Company's, including Reliant
Resources', net income would have been reduced by $5 million, $10 million, and
$26 million in 1999, 2000 and 2001, respectively. Earnings per share would have
been reduced by $0.02 per share, $0.03 per share and $0.09 per share in 1999,
2000 and 2001, respectively.

Subject to the Distribution, the Company expects to convert all outstanding
Reliant Energy stock options granted prior to the Offering to a combination of
adjusted Reliant Energy stock options and Reliant Resources stock options. For
the converted stock options, the sum of the intrinsic value of the Reliant
Energy stock options immediately prior to the record date of the Distribution
will equal the sum of the intrinsic values of the adjusted Reliant Energy stock
options and the Reliant Resources stock options granted immediately after the
record date of the Distribution. As such, Reliant Resources employees who do not
work for the Company will hold stock options of the Company. Both the number and
the exercise price of all outstanding Reliant Energy stock options that were
granted on or after the Offering will be adjusted to maintain the total
intrinsic value of the grants.

(b) PENSION

The Company sponsors multiple pension plans. The principal retiree benefit
plans are discussed below. Other such plans are not significant individually or
in the aggregate.

The Company maintains a pension plan which is a noncontributory defined
benefit plan covering substantially all employees in the United States and
certain employees in foreign countries. The benefit accrual is in the form of a
cash balance of 4% of annual pay. Prior to 1999, the pension plan accrued
benefits based on years of service, final average pay and covered compensation.
As a result, certain employees participating in the plan as of December 31, 1998
are eligible for transition benefits through 2008.

The Company's funding policy is to review amounts annually in accordance
with applicable regulations in order to achieve adequate funding of projected
benefit obligations. The assets of the pension plans consist principally of
common stocks and interest bearing obligations. Included in such assets are
approximately 4.5 million shares of Reliant Energy common stock contributed from
treasury stock during 2001. As of December 31, 2001, the fair value of Reliant
Energy common stock was $120 million or 8.7% of the pension plan assets.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

REPGB is a foreign subsidiary of the Company and participates along with
other companies in the Netherlands in making payments to pension funds which are
not administered by the Company. The Company treats these payments as a defined
contribution pension plan which provides retirement benefits for most of its
employees. The contributions are principally based on a percentage of the
employee's base compensation and charged against income as incurred. This
expense was $2 million, $6 million and $6 million for the three months ended
December 31, 1999 and during 2000 and 2001, respectively.

Net pension cost for the Company (excluding REPGB) includes the following
components:

Following are reconciliations of the Company's beginning and ending
balances of its retirement plan benefit obligation, plan assets and funded
status for 2000 and 2001 (excluding REPGB):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The transitional asset at January 1, 1986, is being recognized over 17
years, and the prior service cost is being recognized over 15 years.

Effective March 1, 2001, the Company no longer accrues benefits under a
noncontributory pension plan for its domestic non-union employees of Reliant
Resources and its participating subsidiaries' employees (Resources
Participants). Effective March 1, 2001, each Resources Participant's unvested
accrued benefit was fully vested and a one-time benefit enhancement was provided
to some qualifying participants. After the Distribution, each Resources
Participant may elect to have his accrued benefit (a) left in the Company's
pension plan, (b) rolled over to a new Reliant Resources savings plan or an
individual IRA account, or (c) paid in a lump sum or annuity distribution.
During the first quarter of 2001, the Company incurred a charge to earnings of
$84 million (pre-tax) for a one-time benefit enhancement and a gain of $23
million (pre-tax) related to the curtailment of the Company's pension plan.

In addition to the noncontributory pension plans discussed above, the
Company maintains non-qualified pension plans which allow participants to retain
the benefits to which they would have been entitled under the Company's
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.
The expense associated with these non-qualified plans was $5 million, $25
million and $25 million in 1999, 2000 and 2001, respectively. Expense for 2001
includes a one-time benefit enhancement of $15 million, which is included in the
$84 million discussed above. The accrued benefit liability for the nonqualified
pension plan was $92 million and $99 million at December 31, 2000 and 2001,
respectively. In addition, these accrued benefit liabilities include the
recognition of minimum liability adjustments of $30 million as of December 31,
2000 and $20 million as of December 31, 2001, which are reported as a component
of comprehensive income, net of income tax effects.

The Company's prepaid pension asset is presented in the Consolidated
Balance Sheets under the caption "Other Assets -- Other."

(c) SAVINGS PLAN

The Company has employee savings plans that qualify as cash or deferred
arrangements under Section 401(k) of the Internal Revenue Code of 1986, as
amended (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. The Company matches 75% to 125% (based on certain
performance goals achieved) of the first 6% of each employee's compensation
contributed, with most matching contributions subject to a vesting schedule. A
substantial portion of the Company's match is invested in Reliant Energy common
stock.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Effective March 1, 2001, the Company amended its savings plan for Reliant
Resources participants and REMA's non-union employee savings plan to generally
provide for (a) employer matching contributions equal to 100% of the first 6% of
each employee's contributions to the plan, (b) a 2% employer contribution on a
payroll basis for 2002, limited to the first $85,000 of compensation, and (c)
discretionary employer contributions up to 3% at the end of the plan year based
on each employee's eligible compensation. Effective March 1, 2001, all prior and
future employer contributions on behalf of such employees are fully vested.

The Company's savings plan has a leveraged Employee Stock Ownership Plan
(ESOP) component. The Company may use ESOP shares to satisfy its obligation to
make matching contributions under the Company's savings plan. Debt service on
the ESOP loan is paid using all dividends on shares in the ESOP, interest
earnings on funds held in the ESOP and cash contributions by the Company. Shares
of Reliant Energy common stock are released from the encumbrance of the ESOP
loan based on the proportion of debt service paid during the period.

The Company recognizes benefit expense for the ESOP equal to the fair value
of the ESOP shares committed to be released. The Company credits to unearned
ESOP shares the original purchase price of ESOP shares committed to be released
to plan participants with the difference between the fair value of the shares
and the original purchase price recorded to common stock. Dividends on allocated
ESOP shares are recorded as a reduction to retained earnings. Dividends on
unallocated ESOP shares are recorded as a reduction of principal or accrued
interest on the ESOP loan.

The ESOP share balances at December 31, 2000 and 2001 were as follows:

As a result of the ESOP and the Company stock fund, the savings plan has
significant holdings of Reliant Energy common stock. As of December 31, 2000 and
2001, an aggregate of 33,437,216 shares and 33,505,474 shares of Reliant
Energy's common stock were held by the savings plan, which represented 66.0% and
56.1% of its investments, respectively. Given the concentration of the
investments in Reliant Energy's common stock, the savings plan and its
participants have market risk related to this investment.

The Company's savings plan benefit expense was $35 million, $53 million and
$55 million in 1999, 2000 and 2001, respectively.

(d) POSTRETIREMENT BENEFITS

The Company sponsors multiple postretirement plans. The principal retiree
benefit plans are discussed below. Other such plans are not significant
individually or in the aggregate.

The Company provides certain healthcare and life insurance benefits for
retired employees on a contributory and non-contributory basis. Employees become
eligible for these benefits if they have met certain age and service
requirements at retirement, as defined in the plans. Under plan amendments
effective in early 1999, health care benefits for future retirees were changed
to limit employer contributions for medical coverage.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Such benefit costs are accrued over the active service period of employees.
The net unrecognized transition obligation, resulting from the implementation of
accrual accounting, is being amortized over approximately 20 years.

The Company is required to fund a portion of its obligations in accordance
with rate orders. All other obligations are funded on a pay-as-you-go basis.

Net postretirement benefit cost for the Company includes the following
components:

Following are reconciliations of the Company's beginning and ending
balances of its postretirement benefit plans benefit obligation, plan assets and
funded status for 2000 and 2001:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The assumed health care rates gradually decline to 5.5% for both medical
categories by 2010. The actuarial gains and losses are due to changes in
actuarial assumptions.

If the health care cost trend rate assumptions were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2001 would
increase by approximately 3.6%. The annual effect of the 1% increase on the
total of the service and interest costs would be an increase of approximately
3%. If the health care cost trend rate assumptions were decreased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2001 would
decrease by approximately 3.5%. The annual effect of the 1% decrease on the
total of the service and interest costs would be a decrease of 2.9%.

Effective March 1, 2001, the Company discontinued providing subsidized
postretirement benefits to its Resources Participants. The Company incurred a
pre-tax loss of $40 million during the first quarter of 2001 related to the
curtailment of the Company's postretirement obligation.

The Company's postretirement obligation is presented as a liability in the
Consolidated Balance Sheets under the caption "Benefit Obligations."

(e) POSTEMPLOYMENT BENEFITS

Net postemployment benefit costs for 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) were $11 million, $2 million and $6 million in 1999,
2000 and 2001, respectively.

The Company's postemployment obligation is presented as a liability in the
Consolidated Balance Sheets under the caption "Benefit Obligations."

(f) OTHER NON-QUALIFIED PLANS

Since 1985, the Company has had in effect deferred compensation plans which
permit eligible participants to elect each year to defer a percentage of that
year's salary (prior to December 1993, up to 25% or 40%, depending on age, and
beginning in December 1993, up to 100%) and up to 100% of that year's annual
bonus. In general, employees who attain the age of 60 during employment and
participate in the Company's deferred compensation plans may elect to have their
deferred compensation amounts repaid in (a) fifteen equal annual installments
commencing at the later of age 65 or termination of employment or (b) a lump-sum
distribution following termination of employment. Interest generally accrues on
deferrals made in 1989 and
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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. During 1999, 2000
and 2001, the Company, including Reliant Resources, recorded interest expense
related to its deferred compensation obligation of $22 million, $14 million and
$17 million, respectively. The discounted deferred compensation obligation
recorded by the Company, including Reliant Resources, was $159 million and $161
million as of December 31, 2000 and 2001, respectively.

Each Reliant Resources participant has elected to have his non-qualified
deferred compensation plan account balance, after the Distribution: (a) placed
in a new Reliant Resources deferred compensation plan, which generally mirrors
the former Reliant Energy deferred compensation plans; or, (b) rolled over to
the new non-qualified deferred compensation plan discussed below.

Effective January 1, 2002, select key and highly compensated employees were
eligible to participate in a new non-qualified deferred compensation 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. The Company funds these
deferred compensation liabilities by making contributions to a rabbi trust. Plan
participants direct the allocation of their deferrals between one or more of the
Company's designated investment funds within the rabbi trust. Participants may
withdraw their deferrals and accumulated earnings, if any, at any time before
their normal distributions would have commenced with a ten percent penalty.

The Company's obligations under other non-qualified plans are presented as
a liability in the Consolidated Balance Sheets under the caption "Benefit
Obligations."

(g) OTHER EMPLOYEE MATTERS

As of December 31, 2001, approximately 36% of the Company's employees are
subject to collective bargaining arrangements, of which contracts covering 8% of
the Company's employees will expire prior to December 31, 2002.

(13) INCOME TAXES

The components of income before taxes are as follows:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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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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 financial statements and
their respective tax bases:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Tax Attribute Carryforwards. At December 31, 2001, the Company had $13
million, $530 million and $45 million of federal, state and foreign net
operating loss carryforwards, respectively. The losses are available to offset
future respective federal and state taxable income through the year 2021. The
foreign losses available to offset future foreign taxable income will not expire
under current foreign jurisdiction tax law.

The valuation allowance reflects a net increase of $49 million in 2000 and
a net decrease of $37 million in 2001. These net changes resulted from a
reassessment of the Company's future ability to use federal, state and foreign
tax net operating loss carryforwards.

REPGB Tax Holiday. Under 1998 Dutch tax law relating to the Dutch
electricity industry, REPGB qualifies for a zero percent tax rate through
December 31, 2001. The tax holiday applies only to the Dutch income earned by
REPGB. Beginning January 1, 2002, REPGB is subject to Dutch corporate income tax
at standard statutory rates, which is currently 34.5%, and was enacted in 2001.
Prior to 2001, the enacted rate was 35%. The effect of the change in the enacted
tax rate was not material to the Company's results of operations.

As discussed in Note 14(h), the Dutch parliament has adopted legislation
allocating to the Dutch generation sector, including REPGB, financial
responsibility for certain stranded costs and other liabilities incurred by NEA
prior to the deregulation of the Dutch wholesale market. These obligations
include NEA's obligations under an out-of-market gas supply contract and three
out-of-market electricity contracts. As a result of the above, the Company
recorded a net stranded cost liability of $369 million and a related deferred
tax asset of $127 million at December 31, 2001 for the Company's statutorily
allocated share of these gas supply and electricity contracts. The Company
believes that the costs incurred by REPGB subsequent to the tax holiday ending
in 2001 related to these contracts will be deductible for Dutch tax purposes.
However, due to uncertainties related to the deductibility of these costs, the
Company has recorded an offsetting liability in other liabilities of $127
million as of December 31, 2001.

Undistributed Earnings of Foreign Subsidiaries. The undistributed earnings
of foreign subsidiaries aggregated $298 million as of December 31, 2001, which,
under existing tax law, will not be subject to U.S. income tax until
distributed. Provisions for U.S. taxes have not been accrued on these
undistributed earnings, as these earnings have been, or are intended to be,
permanently reinvested. In the event of a distribution of these earnings in the
form of dividends, the Company will be subject to U.S. income taxes net of
allowable foreign tax credits.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Tax Refunds. In 2000, the Company received refunds from the IRS totaling
$126 million in taxes and interest following audits of tax returns and refund
claims for Reliant Energy's 1985, 1986 and 1990 through 1995 tax years, and RERC
Corp.'s 1979 through 1993 tax years. The pre-tax income statement effect of $40
million ($26 million after-tax) was recorded in 2000 in other income in the
Company's Statements of Consolidated Income. Of the refunds, $26 million was
recorded as a reduction in goodwill. Reliant Energy's consolidated federal
income tax returns have been audited and settled through the 1996 tax year. All
of RERC Corp.'s consolidated federal income tax returns for tax years ending on
or prior to Reliant Energy's acquisition of RERC Corp. have been audited and
settled.

(14) COMMITMENTS AND CONTINGENCIES

(a) COMMITMENTS AND GUARANTEES

The following information is presented separately for the Company's
regulated and unregulated businesses:

RELIANT ENERGY (TO BECOME CENTERPOINT ENERGY SUBSEQUENT TO THE RESTRUCTURING)

Capital and Environmental Commitments. Reliant Energy anticipates
investing up to $397 million in capital and other special project expenditures
between 2002 and 2006 for environmental compliance. Reliant Energy anticipates
expenditures to be as follows (in millions):

2002........................................................ $234
2003........................................................ 132
2004........................................................ 28
2005........................................................ 3
2006........................................................ --
----
Total..................................................... $397
====

Fuel and Purchased Power. Fuel commitments include several long-term coal,
lignite and natural gas contracts related to Texas power generation operations,
which have various quantity requirements and durations that are not classified
as non-trading derivatives assets and liabilities or trading and marketing
assets and liabilities in the Company's Consolidated Balance Sheets as of
December 31, 2001 as these contracts meet the SFAS No. 133 exception to be
classified as "normal purchases contracts" (see Note 5) or do not meet the
definition of a derivative. Minimum payment obligations for coal and
transportation agreements that extend through 2009 are approximately $199
million in 2002, $129 million in 2003, $133 million in 2004, $137 million in
2005 and $141 million in 2006. Purchase commitments related to lignite mining
and lease agreements, natural gas purchases and storage contracts, and purchased
power are not material to Reliant Energy's operations. Prior to January 1, 2002,
the Electric Operations business segment was allowed recovery of these costs
through rates for electric service. As of December 31, 2001, some of these
contracts are above market. Reliant Energy anticipates that stranded costs
associated with these obligations will be recoverable through the stranded cost
recovery mechanisms contained in the Texas Electric Restructuring Law. For
information regarding the Texas Electric Restructuring Law, see Note 4(a).

Reliant Energy's other long-term fuel supply commitments which have various
quantity requirements and durations are not considered material either
individually or in the aggregate to its results of operations or cash flows.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

RELIANT RESOURCES -- UNREGULATED BUSINESSES

As of December 31, 2001, the Wholesale Energy business segment had entered
into commitments associated with various non-rate regulated electric generating
projects, including commitments for the purchase of combustion turbines,
aggregating $440 million. In addition, the Wholesale Energy business segment has
options to purchase additional generating equipment for a total estimated cost
of $42 million for future generation projects. Reliant Resources is actively
attempting to remarket this equipment.

Reliant Resources is a party to several 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
non-trading derivatives assets and liabilities or trading and marketing assets
and liabilities in the Consolidated Balance Sheets as of December 31, 2001 as
these contracts meet the SFAS No. 133 exception to be classified as "normal
purchases contracts" (see Note 5) or do not meet the definition of a derivative.
The maximum duration of any of these commitments is 21 years. Minimum purchase
commitment obligations under these agreements are as follows for the next five
years, as of December 31, 2001 (in millions):

The maximum duration under any individual fuel supply contract and
transportation contract is 18 years and 21 years, respectively.

Reliant Resources' aggregate electric capacity commitments, including
capacity auction products, are for 7,496 MW, 1,800 MW, 1,000 MW, 1,000 MW and
1,000 MW for 2002, 2003, 2004, 2005 and 2006, respectively. The maximum duration
under any individual commitment is five years. Included in the above purchase
power and electric capacity commitments are amounts to be acquired from Texas
Genco in 2002 and 2003 of $213 million and $57 million, respectively.

As of December 31, 2001, Reliant Resources has commitments, including
electric energy and capacity sale contracts and district heating contracts (see
Note 14(h)) which are not classified as non-trading derivative assets and
liabilities or trading and marketing assets and liabilities in the Consolidated
Balance Sheets as these contracts meet the SFAS No. 133 exception to be
classified as "normal sales contracts" or do not meet the definition of a
derivative. The estimated minimum sale commitments under these contracts are
$450 million, $211 million, $194 million, $174 million and $159 million in 2002,
2003, 2004, 2005 and 2006, respectively.

In addition, in January 2002, Reliant Resources began providing retail
electric services to approximately 1.5 million residential and small commercial
customers previously served by Reliant Energy's electric utility division.
Within Reliant Energy's electric utility division's territory, prices that may
be charged to residential and small commercial customers by this retail electric
service provider are subject to a fixed, specified price (price to beat) at the
outset of retail competition. The Texas Utility Commission's regulations allow
this 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 its price of
purchased energy. The retail electric provider may request that its price to
beat be adjusted twice a year.

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Reliant Resources will not be permitted to sell electricity to residential and
small commercial customers in the incumbent's traditional service territory at a
price other than the price to beat until January 1, 2005, unless before that
date the Texas Utility Commission determines that 40% or more of the amount of
electric power that was consumed in 2000 by the relevant class of customers is
committed to be served by other retail electric providers.

Reliant Resources guarantees the performance of certain of its
subsidiaries' trading and hedging obligations. As of December 31, 2001, the
fixed maximum amount of such guarantees was $4.7 billion. In addition, Reliant
Resources has issued letters of credit totaling $51 million in connection with
its trading activities. Reliant Resources does not consider it likely that it
would be required to perform or otherwise incur any losses associated with these
guarantees.

In addition to the above discussions, Reliant Resources' other commitments
have various quantity requirements and durations and are not considered material
either individually or in the aggregate to its results of operations or cash
flows.

(b) LEASE COMMITMENTS

In August 2000, the Company, entered into separate sale-leaseback
transactions with each of three owner-lessors covering the subsidiaries'
respective 16.45%, 16.67% and 100% interests in the Conemaugh, Keystone and
Shawville generating stations, respectively, acquired in the REMA acquisition.
As lessee, the Company leases an interest in each facility from each
owner-lessor under a facility lease agreement. The equity interests in all the
subsidiaries of REMA are pledged as collateral for REMA's lease obligations. In
addition, the subsidiaries have guaranteed the lease obligations. The lease
documents contain restrictive covenants that restrict REMA's ability to, among
other things, make dividend distributions unless REMA satisfies various
conditions. The covenant restricting dividends would be suspended if the direct
or indirect parent of REMA, meeting specified criteria, including having a
rating on REMA's long-term unsecured senior debt of at least BBB from Standard
and Poor's and Baa2 from Moody's, guarantees the lease obligations. The Company
will make lease payments through 2029. The lease term expires in 2034. As of
December 31, 2001, REMA had $167 million of restricted funds that are available
for REMA's working capital needs and to make future lease payments, including a
lease payment of $55 million which was made in January 2002.

In the first quarter of 2001, Reliant Resources 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.
This electricity will be generated by two gas-fired, simple-cycle peaking
plants, with fuel oil backup which are being constructed by a tolling partner.
Reliant Resources anticipates construction to be completed by the summer of
2002, at which time Reliant Resources will commence tolling payments. The
tolling arrangements qualify as operating leases.

In February 2001, the Company entered into a lease for office space for
Reliant Resources in a building under construction. The lease agreement was
assigned by the Company to Reliant Resources by an assignment and assumption
agreement in June 2001. The lease term, which commences in the second quarter
2003, is 15 years with two five-year renewal options. Reliant Resources has the
right to name the building.

The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2001, which primarily relate to the REMA leases mentioned above. Other
non-cancelable, long-term operating leases for Reliant Energy and Reliant
Resources principally

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

consist of tolling arrangements, as discussed above, rental agreements for
building space, data processing equipment and vehicles, including major work
equipment.

Total lease expense for all operating leases was $39 million, $62 million
and $112 million during 1999, 2000 and 2001, respectively. During 2001, the
Company made lease payments related to the REMA lease of $259 million. As of
December 31, 2001, the Company had recorded a prepaid lease obligation related
to the REMA sale-leaseback of $59 million and $122 million in other current
assets and other long-term assets, respectively.

(c) CROSS BORDER LEASES

During the period from 1994 through 1997, under cross border lease
transactions, REPGB leased several of its power plants and related equipment and
turbines to non-Netherlands based investors (the head leases) and concurrently
leased the facilities back under sublease arrangements with remaining terms as
of December 31, 2001 of 1 to 23 years. REPGB utilized proceeds from the head
lease transactions to prepay its sublease obligations and to provide a source
for payment of end of term purchase options and other financial undertakings.
The initial sublease obligations totaled $2.4 billion of which $1.6 billion
remained outstanding as of December 31, 2001. These transactions involve REPGB
providing to a foreign investor an ownership right in (but not necessarily title
to) an asset, with a leaseback of that asset. The net proceeds to REPGB of the
transactions were recorded as a deferred gain and are currently being amortized
to income over the lease terms. At December 31, 2000 and 2001, the unamortized
deferred gain on these transactions totaled $77 million and $68 million,
respectively. The power plants, related equipment and turbines remain on the
financial statements of REPGB and continue to be depreciated.

REPGB is required to maintain minimum insurance coverages, perform minimum
annual maintenance and, in specified situations, post letters of credit. REPGB's
shareholder is subject to some restrictions with respect to the liquidation of
REPGB's shares. In the case of early termination of these contracts, REPGB would
be contingently liable for some payments to the sublessors, which at December
31, 2001, are estimated to be $272 million. Starting in March 2000, REPGB was
required by some of the lease agreements to obtain standby letters of credit in
favor of the sublessors in the event of early termination. The amount of the
required letters of credit was $272 million as of December 31, 2001. Commitments
for these letters of credit have been obtained as of December 31, 2001.

(d) NAMING RIGHTS TO HOUSTON SPORTS COMPLEX

In October 2000, Reliant Resources acquired the naming rights for the new
football stadium for the Houston Texans, the National Football League's newest
franchise. In addition, the naming rights cover the entertainment and convention
facilities included in the stadium complex. The agreement extends for 32 years.
In addition to naming rights, the agreement provides Reliant Resources with
significant sponsorship rights.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The aggregate cost of the naming rights will be approximately $300 million.
During the fourth quarter of 2000, Reliant Resources incurred an obligation to
pay $12 million in order to secure the long-term commitment and for the initial
advertising of which $10 million was expensed in the Statement of Consolidated
Income in 2000. Starting in 2002, when the new stadium is operational, Reliant
Resources will pay $10 million each year through 2032 for annual advertising
under this agreement.

(e) TRANSPORTATION AGREEMENT

A subsidiary of RERC Corp. had an agreement (ANR Agreement) with ANR
Pipeline Company (ANR) that contemplated that this subsidiary would transfer to
ANR an interest in some of RERC Corp.'s pipeline and related assets. As of
December 31, 2000 and 2001, the Company had recorded $41 million in other
long-term liabilities in the Company's Consolidated Balance Sheets to reflect
the Company's obligation to ANR for the use of 130 million cubic feet (Mmcf)/day
of capacity in some of the Company's transportation facilities. The level of
transportation will decline to 100 Mmcf/day in the year 2003 with a refund of $5
million to ANR. The ANR Agreement will terminate in 2005 with a refund of $36
million.

(f) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Legal Matters

Reliant Energy HL&P Municipal Franchise Fee Lawsuits. In February 1996,
the cities of Wharton, Galveston and Pasadena filed suit, for themselves and a
proposed class of all similarly situated cities in Reliant Energy HL&P's service
area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a
wholly owned subsidiary of Reliant Energy) alleging underpayment of municipal
franchise fees. Plaintiffs claim that they are entitled to 4% of all receipts of
any kind for business conducted within these cities over the previous four
decades. Because the franchise ordinances at issue affecting Reliant Energy HL&P
expressly impose fees only on its own receipts and only from sales of
electricity for consumption within a city, the Company regards all of
plaintiffs' allegations as spurious and is vigorously contesting the case. The
plaintiffs' pleadings asserted that their damages exceeded $250 million. The
269th Judicial District Court for Harris County granted partial summary judgment
in favor of Reliant Energy dismissing all claims for franchise fees based on
sales tax collections. Other motions for partial summary judgment were denied. A
six-week jury trial of the original claimant cities (but not the class of
cities) ended on April 4, 2000 (Three Cities case). Although the jury found for
Reliant Energy on many issues, they found in favor of the original claimant
cities on three issues, and assessed a total of $4 million in actual and $30
million in punitive damages. However, the jury also found in favor of Reliant
Energy on the affirmative defense of laches, a defense similar to a statute of
limitations defense, due to the original claimant cities having unreasonably
delayed bringing their claims during the 43 years since the alleged wrongs
began.

The trial court in the Three Cities case granted most of Reliant Energy's
motions to disregard the jury's findings. The trial court's rulings reduced the
judgment to $1.7 million, including interest, plus an award of $13.7 million in
legal fees. In addition, the trial court granted Reliant Energy's motion to
decertify the class and vacated its prior orders certifying a class. Following
this ruling, 45 cities filed individual suits against Reliant Energy in the
District Court of Harris County.

The Three Cities case has been appealed. The Company believes that the $1.7
million damage award resulted from serious errors of law and that it will be set
aside by the Texas appellate courts. In addition, the Company believes that
because of an agreement between the parties limiting fees to a percentage of the
damages, reversal of the award of $13.7 million in attorneys' fees in the Three
Cities case is probable.

The extent to which issues in the Three Cities case may affect the claims
of the other cities served by Reliant Energy HL&P cannot be assessed until
judgments are final and no longer subject to appeal. However, the trial court's
rulings disregarding most of the jury's findings are consistent with Texas
Supreme Court

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opinions over the past decade. The Company estimates the range of possible
outcomes for the plaintiffs to be between zero and $18 million inclusive of
interest and attorneys' fees.

California Wholesale Market. Reliant Energy, Reliant Energy Services, REPG
and several other subsidiaries of Reliant Resources, as well as three officers
of some of these companies, have been named as defendants in class action
lawsuits and other lawsuits filed against a number of companies that own
generation plants in California and other sellers of electricity in California
markets. Pursuant to the terms of the master separation agreement between
Reliant Energy and Reliant Resources (see Note 4(c)), Reliant Resources has
agreed to indemnify Reliant Energy for any damages arising under these lawsuits
and may elect to defend these lawsuits at its own expense. Three of these
lawsuits were filed in the Superior Court of the State of California, San Diego
County; two were filed in the Superior Court in San Francisco County; and one
was filed in the Superior Court of Los Angeles County. While the plaintiffs
allege various violations by the defendants of state antitrust laws and state
laws against unfair and unlawful business practices, each of the lawsuits is
grounded on the central allegation that defendants conspired to drive up the
wholesale price of electricity. In addition to injunctive relief, the plaintiffs
in these lawsuits seek treble the amount of damages alleged, restitution of
alleged overpayments, disgorgement of alleged unlawful profits for sales of
electricity, costs of suit and attorneys' fees. The cases were initially removed
to federal court and were then assigned to Judge Robert H. Whaley, United States
District Judge, pursuant to the federal procedures for multi-district
litigation. On July 30, 2000, Judge Whaley remanded the cases to state court.
Upon remand to state court, the cases were assigned to Superior Court Judge
Janis L. Sammartino pursuant to the California state coordination procedures. On
March 4, 2002, Judge Sammartino adopted a schedule proposed by the parties that
would result in a trial beginning on March 1, 2004. On March 8, 2002, the
plaintiffs filed a single, consolidated complaint naming numerous defendants,
including Reliant Energy Services and other Reliant Resources' subsidiaries,
that restated the allegations described above and alleged that damages against
all defendants could be as much as $1 billion.

Plaintiffs have voluntarily dismissed Reliant Energy from two of the three
class actions in which it was named as a defendant. The ultimate outcome of the
lawsuits cannot be predicted with any degree of certainty at this time. However,
the Company believes, based on its analysis to date of the claims asserted in
these lawsuits and the underlying facts, that resolution of these lawsuits will
not have a material adverse effect on the Company's financial condition, results
of operations or cash flows.

On March 11, 2002, the California Attorney General filed a civil lawsuit in
San Francisco Superior Court naming Reliant Energy, Reliant Resources, Reliant
Energy Services, REPG, and several other subsidiaries of Reliant Resources as
defendants. Pursuant to the terms of the master separation agreement between
Reliant Energy and Reliant Resources (see Note 4(c)), Reliant Resources has
agreed to indemnify Reliant Energy for any damages arising under these lawsuits
and may elect to defend these lawsuits at its own expense. The Attorney General
alleges various violations by the defendants 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).
In addition to injunctive relief, the Attorney General seeks restitution and
disgorgement of alleged unlawful profits for sales of electricity, and civil
penalties. The ultimate outcome of this lawsuit cannot be predicted with any
degree of certainty at this time.

On March 19, 2002, the California Attorney General filed a complaint with
the FERC naming Reliant Energy Services and "all other public utility sellers"
in California as defendants. The complaint alleges that sellers with
market-based rates have violated their tariffs by not filing with the FERC
transaction-specific information about all of their sales and purchases at
market-based rates. The California Attorney General argues that, as a result,
all past sales should be subject to refund if found to be above just and
reasonable levels. The ultimate outcome of this complaint proceeding cannot be
predicted with any degree of certainty at this time. However, the Company
believes, based on its analysis to date of the claims asserted in the complaint,
the underlying facts, and the relevant statutory and regulatory provisions, that
resolution of this

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

lawsuit will not have a material adverse effect on the Company's financial
condition, results of operations or cash flows.

Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the
Federal False Claim Act against RERC and certain of its subsidiaries alleging
mismeasurement of natural gas produced from federal and Indian lands. The suit
seeks undisclosed damages, along with statutory penalties, interest, costs, and
fees. The complaint is part of a larger series of complaints filed against 77
natural gas pipelines and their subsidiaries and affiliates. An earlier single
action making substantially similar allegations against the pipelines was
dismissed by the U.S. District Court for the District of Columbia on grounds of
improper joinder and lack of jurisdiction. As a result, the various individual
complaints were filed in numerous courts throughout the country. This case was
consolidated, together with the other similar False Claim Act cases filed and
transferred to the District of Wyoming. Motions to dismiss were denied. The
defendants intend to vigorously contest this case.

In addition, RERC, REGT, REFS and MRT have been named as defendants in a
class action filed in May 1999 against approximately 245 pipeline companies and
their affiliates. The plaintiffs in the case purport to represent a class of
natural gas producers and fee royalty owners who allege that they have been
subject to systematic gas mismeasurement by the defendants, including certain
Reliant Energy entities, for more than 25 years. The plaintiffs seek
compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. The action is currently pending in state court in Stevens
County, Kansas. Plaintiffs initially sued Reliant Energy Services, but that
company was dismissed without prejudice on June 8, 2001. Other Reliant Energy
entities that were misnamed or duplicative have also been dismissed. MRT and
REFS have filed motions to dismiss for lack of personal jurisdiction and are
currently responding to discovery on personal jurisdiction. All four Reliant
Energy defendants have joined in a motion to dismiss.

The defendants plan to raise significant affirmative defenses based on the
terms of the applicable contracts, as well as on the broad waivers and releases
in take or pay settlements that were granted by the producer-sellers of natural
gas who are putative class members.

Environmental Matters

Clean Air Standards. The Company has participated in a lawsuit against the
Texas Natural Resource Conservation Commission (TNRCC) regarding the limitation
of the emission of oxides of nitrogen (NOx) in the Houston area. A settlement of
the lawsuit was reached with the TNRCC in the second quarter of 2001 and revised
emissions limitations were adopted by the TNRCC in the third quarter of 2001.
The revised limitations provide for an increase in allowable NOx emissions,
compared to the original TNRCC requirements, through 2004. Further emission
reduction requirements may or may not be required through 2007, depending upon
the outcome of further investigations of regional air quality issues. To achieve
the TNRCC NOx reduction requirements, the Company anticipates investing up to
$721 million in capital and other special project expenditures by 2004,
including costs incurred through December 31, 2001, and potentially up to an
additional $88 million between 2004 and 2007. The Texas Electric Restructuring
Law provides for stranded cost recovery for expenditures incurred before May 1,
2003 to achieve the NOx reduction requirements

Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit
against Reliant Energy Gas Transmission Company, Inc., Reliant Energy Pipeline
Services, Inc., RERC, Reliant Energy Services, Inc., other Reliant Energy
entities and third parties (Docket No. 460, 916-Div. "B"), in the 1st Judicial
District Court, Caddo Parish, Louisiana. The petition has now been supplemented
five times. As of March 11, 2002, there were 628 plaintiffs, a majority of whom
are Louisiana residents who live near the Wilcox Aquifer. In addition to the
Reliant Energy entities, the plaintiffs have sued the State of Louisiana through
its Department of Environmental Quality, several individuals, some of whom are
present employees of the State of Louisiana, the Bayou South Gas Gathering
Company, L.L.C., Martin Timber Company, Inc., and several trusts.
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The suit alleges that, at some unspecified date prior to 1985, the
defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox
Aquifer which lies beneath property owned or leased by the defendants and which
is the sole or primary drinking water aquifer in the area. The primary source of
the contamination is alleged by the plaintiffs to be a gas processing facility
in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility." This
facility was purportedly used for gathering natural gas from surrounding wells,
separating gasoline and hydrocarbons from the natural gas for marketing, and
transmission of natural gas for distribution. This site was originally leased
and operated by predecessors of Reliant Energy Gas Transmission Company in the
late 1940s and was operated until Arkansas Louisiana Gas Company ceased
operations of the plant in the late 1970s.

Beginning about 1985, the predecessors of certain Reliant Energy defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they own or lease. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or dimunition of value of their
property, and in addition seek damages for trespass, punitive, and exemplary
damages. The quantity of monetary damages sought is unspecified. As of December
31, 2001, the Company is unable to estimate the monetary damages, if any, that
the plaintiffs may be awarded in this matter.

Manufactured Gas Plant Sites. RERC and its predecessors operated a
manufactured gas plant (MGP) until 1960 adjacent to the Mississippi River in
Minnesota, formerly known as Minneapolis Gas Works (MGW). RERC has substantially
completed remediation of the main site other than ongoing water monitoring and
treatment. The manufactured gas was stored in separate holders. RERC is
negotiating clean-up of one such holder. There are six other former MGP sites in
the Minnesota service territory. Remediation has been completed on one site. Of
the remaining five sites, RERC believes that two were neither owned nor operated
by RERC. RERC believes it has no liability with respect to the sites it neither
owned nor operated.

At December 31, 2000 and 2001, RERC had accrued $18 million and $23
million, respectively, for remediation of the Minnesota sites. At December 31,
2001, the estimated range of possible remediation costs was $11 million to $49
million. The cost estimates of the MGW site are based on studies of that site.
The remediation costs for the other sites are based on industry average costs
for remediation of sites of similar size. The actual remediation costs will be
dependent upon the number of sites remediated, the participation of other
potentially responsible parties (PRP), if any, and the remediation methods used.

Issues relating to the identification and remediation of MGPs are common in
the natural gas distribution industry. The Company has received notices from the
United States Environmental Protection Agency and others regarding its status as
a PRP for other sites. Based on current information, the Company has not been
able to quantify a range of environmental expenditures for potential remediation
expenditures with respect to other MGP sites.

Other Minnesota Matters. At December 31, 2000 and 2001, RERC had recorded
accruals of $4 million and $5 million, respectively for other environmental
matters in Minnesota for which remediation may be required. At December 31, 2001
the estimated range of possible remediation costs was $4 million to $8 million.

Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at sites found to be contaminated.
Although the Company is not aware of additional specific sites, it is possible
that other contaminated sites may exist and that remediation costs may be
incurred for these sites. Although the total

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amount of these costs cannot be known at this time, based on experience by the
Company and that of others in the natural gas industry to date and on the
current regulations regarding remediation of these sites, the Company believes
that the costs of any remediation of these sites will not be material to the
Company's financial position, results of operations or cash flows.

REMA Ash Disposal Site Closures and Site Contaminations. Under the
agreement to acquire REMA (see Note 3(a)), the Company became responsible for
liabilities associated with ash disposal site closures and site contamination at
the acquired facilities in Pennsylvania and New Jersey prior to a plant closing,
except for the first $6 million of remediation costs at the Seward Generating
Station. A prior owner retained liabilities associated with the disposal of
hazardous substances to off-site locations prior to November 24, 1999. As of
December 31, 2000 and 2001, REMA has liabilities associated with six future ash
disposal site closures and six current site investigations and environmental
remediations. The Company has recorded its estimate of these environmental
liabilities in the amount of $36 million as of December 31, 2000 and 2001. The
Company expects approximately $16 million will be paid over the next five years.

REPGB Asbestos Abatement and Soil Remediation. Prior to the Company's
acquisition of REPGB (see Note 3(b)), REPGB had a $25 million obligation
primarily related to asbestos abatement, as required by Dutch law, and soil
remediation at six sites. During 2000, the Company initiated a review of
potential environmental matters associated with REPGB's properties. REPGB began
remediation in 2000 of the properties identified to have exposed asbestos and
soil contamination, as required by Dutch law and the terms of some leasehold
agreements with municipalities in which the contaminated properties are located.
All remediation efforts are to be fully completed by 2005. As of December 31,
2000 and 2001, the recorded estimated undiscounted liability for this asbestos
abatement and soil remediation was $24 million and $18 million, respectively.

Other. From time to time the Company has received notices from regulatory
authorities or others regarding its status as a PRP in connection with sites
found to require remediation due to the presence of environmental contaminants.
The Company has from time to time received notices from regulatory authorities
regarding alleged noncompliance with environmental regulatory requirements. In
addition, the Company has been named as a defendant in litigation related to
allegedly contaminated sites and in recent years has been named, along with
numerous others, as a defendant in several lawsuits filed by a large number of
individuals who claim injury due to exposure to asbestos while working at sites
along the Texas Gulf Coast. Most of these claimants have been workers who
participated in construction of various industrial facilities, including power
plants, and some of the claimants have worked at locations owned by the Company.
The Company anticipates that additional claims like those received may be
asserted in the future and intends to continue vigorously contesting claims
which it does not consider to have merit. Although their ultimate outcome cannot
be predicted at this time, the Company does not believe, based on its experience
to date, that these matters, either individually or in the aggregate, will have
a material adverse effect on the Company's financial position, results of
operations or cash flows.

Other Matters

The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.

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(g) CALIFORNIA WHOLESALE MARKET UNCERTAINTY.

Receivables. During portions of 2000 and 2001, prices for wholesale
electricity in California increased dramatically as a result of a combination of
factors, including higher natural gas prices and emission allowance costs,
reduction in available hydroelectric generation resources, increased demand,
decreased net electric imports and limitations on supply as a result of
maintenance and other outages. The resulting supply and demand imbalance
disproportionately impacted California utilities that relied too heavily on
short-term power markets to meet their load requirements. Although wholesale
prices increased, California's deregulation legislation kept retail rates frozen
at 10% below 1996 levels for two of California's public utilities, Pacific Gas
and Electric (PG&E) and Southern California Edison Company (SCE), until rates
were raised by the California Public Utilities Commission (CPUC) early in 2001.

Due to the disparity between wholesale and retail rates, the credit ratings
of PG&E and SCE fell below investment grade. Additionally, PG&E filed for
protection under the bankruptcy laws on April 6, 2001. As a result, PG&E and SCE
are no longer considered creditworthy and since January 17, 2001 have not
directly purchased power from third-party suppliers through the Cal ISO to serve
their net short load. Pursuant to emergency legislation enacted by the
California Legislature, the California Department of Water Resources (CDWR) has
negotiated and purchased power through short and long-term contracts on behalf
of PG&E and SCE to meet their net short loads. In December 2001, the CDWR began
making payments to the Cal ISO for real-time transactions. The CDWR has now made
payment through the Cal ISO for most real-time energy deliveries subsequent to
January 17, 2001.

In addition, certain contracts intended to serve as collateral for sales to
the California Power Exchange (Cal PX) were seized by California Governor Gray
Davis in February 2001. The Ninth Circuit Court of Appeals subsequently ruled
that Governor Davis' seizure of these contracts was wrongful. The Company has
filed a lawsuit, currently pending in California, to require the state of
California to compensate it for the seizure of these contracts. Although SCE
made a payment on March 1, 2002 to the Cal PX that included amounts it owed to
the Company under these contracts, the Company is still seeking to recover the
market value of the contracts at the time they were seized by Governor Davis,
which was significantly higher than the contract value, and to collect amounts
owed as a result of payment defaults by PG&E under the contracts. The timing and
ultimate resolution of these claims is uncertain at this time.

On September 20, 2001, PG&E filed a Plan of Reorganization and an
accompanying disclosure statement with the bankruptcy court. Under this plan,
PG&E would pay all allowed creditor claims in full, through a combination of
cash and long-term notes. Components of the plan will require the approval of
the FERC, the SEC and the Nuclear Energy Regulatory Commission, in addition to
the bankruptcy court. PG&E has stated it seeks to have this plan confirmed by
December 31, 2002. A number of parties are contesting PG&E's reorganization
plan, including a number of California parties and agencies. The bankruptcy
judge in the PG&E case has ordered that the CPUC may file a competing plan. The
details of the CPUC's proposal are unknown at this time. The ability of PG&E to
have its reorganization plan confirmed, including the provision providing for
the payment in full of unsecured creditors, is uncertain at this time.

On October 5, 2001, a federal district court in California entered a
stipulated judgment approving a settlement between SCE and the CPUC in an action
brought by SCE regarding the recovery of its wholesale power costs under the
filed rate doctrine. Under the stipulated judgment, a rate increase approved
earlier in 2001 will remain in place until the earlier of SCE recovering $3.3
billion or December 31, 2002. After that date, the CPUC will review the
sufficiency of retail rates through December 31, 2005. A consumer organization
has appealed the judgment to the Ninth Circuit Court of Appeals, and no hearing
has been held to date. Under the stipulated judgment, any settlement with SCE's
creditors that is entered into after March 1, 2002 must be approved by the CPUC.
The Company has appealed this provision of the judgment. On March 1, 2002, SCE
made a payment to the Cal PX that included amounts it owed the Company. The
Company has made a filing with FERC seeking an order providing for the
disbursement of the funds owed to
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the suppliers. The FERC and the bankruptcy court governing the Cal PX bankruptcy
proceedings are considering how to dispense this money and it remains uncertain
when those funds will be paid over to the Company.

As of December 31, 2000, the Company was owed a total of $282 million by
the Cal PX and the Cal ISO. As of December 31, 2001, the Company was owed a
total of $302 million by the Cal ISO, the Cal PX, the CDWR, and California
Energy Resources Scheduling for energy sales in the California wholesale market
during the fourth quarter of 2000 through December 31, 2001. From January 1,
2002 through March 26, 2002, the Company has collected $45 million of these
receivable balances. As of December 31, 2001, the Company had a pre-tax
provision of $68 million against receivable balances related to energy sales in
the California market, including $39 million recorded in 2000 and $29 million
recorded in 2001. Management will continue to assess the collectability of these
receivables based on further developments affecting the California electricity
market and the market participants described herein.

FERC Market Mitigation. In response to the filing of a number of
complaints challenging the level of wholesale prices, the FERC initiated a staff
investigation and issued a number of orders implementing a series of wholesale
market reforms. Under these orders, and subject to review and adjustment based
on the pending refund proceeding described below, the Company may face an as yet
undetermined amount of refund liability. See "-- FERC Refunds" below. Under
these orders, for the period January 1, 2001 through June 19, 2001,
approximately $20 million of the $149 million charged by the Company for sales
in California to the Cal ISO and the Cal PX were identified as being subject to
possible refunds. During the second quarter of 2001, the Company accrued refunds
of $15 million, $3 million of which had been previously expensed during the
first quarter of 2001.

On April 26, 2001, the FERC issued an order replacing the previous price
review procedures and establishing a market monitoring and mitigation plan,
effective May 29, 2001, for the California markets. The plan establishes a cap
on prices during periods when power reserves fall below 7% in the Cal ISO
(reserve deficiency periods). The Cal ISO is instructed to use data submitted
confidentially by gas-fired generators in California and daily indices of
natural gas and emissions allowance costs to establish the market-clearing price
in real-time based on the marginal cost of the highest-cost generator called to
run. The plan also requires generators in California to offer all their
available capacity for sale in the real-time market, and conditions sellers'
market-based rate authority such that sellers engaging in certain bidding
practices will be subject to increased scrutiny by the FERC, potential refunds
and even revocation of their market-based rate authority.

On June 19, 2001, the FERC issued an order modifying the market monitoring
and mitigation plan adopted in its April 26 order, to apply price controls to
all hours, instead of just hours of low operating reserve, and to extend the
mitigation measures to other Western states in addition to California, including
Arizona, Colorado, Idaho, Montana, Nevada, New Mexico, Oregon, Utah, Washington
and Wyoming. The FERC set July 2, 2001 as the refund effective date for sales
subject to the price mitigation plan throughout the West region. This means that
transactions after that date may be subject to refund if found to be unjust or
unreasonable. The proxy market clearing price calculated by the Cal ISO will
apply during periods of reserve deficiency to all sales in the Cal ISO and
Western spot markets. In non-reserve deficiency hours in California, the maximum
price in California and the other Western states will be capped at 85% of the
highest Cal ISO hourly market clearing price established during the most recent
reserve deficiency period. Sellers other than marketers will be allowed to bid
higher than the maximum prices, but such bids are subject to justification and
potential refund. Justification of higher prices is limited to establishing
higher actual gas costs than the proxy calculation averages and making a showing
that conditions in natural gas markets changed significantly. The modified
monitoring and mitigation plan went into effect June 20, 2001, and will
terminate on September 30, 2002, covering two summer peak seasons, or
approximately 16 months.

On December 19, 2001, the FERC issued a series of orders on price
mitigation in California and the West region. These orders largely maintained
existing mitigation mechanisms, but did make a temporary modifica-
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tion to the way that mitigated market clearing prices will be set during the
winter months, allowing the maximum prices to rise if gas prices rise. The FERC
removed the requirement that non-reserve deficiency prices be limited to 85% of
the most recent reserve deficiency prices, allowing prices to rise to a
mitigated clearing price of $108/MWh (above which price transactions must be
justified as described above). In addition, the FERC determined that if gas
prices in California rise by 10%, the mitigated price may be revised to take
that change into account. The formula will then track subsequent cumulative
changes of at least 10%, but may not fall below a maximum price of $108/MWh.
This modification is effective December 20, 2001 through April 30, 2002, at
which point the previous mitigation formula is reinstated.

Also, the December 19 orders affirm the June 19 order's requirement that
generators must offer all available capacity for sale in the real-time market.
As a result of this requirement, the Company's opportunity to sell ancillary
services in the West region in the future may be reduced. During 2001, the
Company recorded $42 million in revenues related to ancillary services in the
West region.

In addition to the impact on ancillary services sales, certain aspects of
the December 19, 2001 orders may have retroactive application that may affect
prices charged in the West region since June 21, 2001. Because the precise
application of the December 19, 2001 order is not known at this time, the
Company cannot anticipate the resulting impact on earnings.

The Company believes that while the mitigation plan will reduce volatility
in the market, the Company will nevertheless be able to profitably operate its
facilities in the West. Additionally, as noted above, the mitigation plan allows
sellers, such as the Company, to justify prices above the proxy price. However,
previous efforts by the Company to justify prices above the proxy price have
been rejected by the FERC and there is no certainty that the FERC will allow for
the recovery of costs above the proxy price. Finally, any adverse impacts of the
mitigation plan on the Company's operations would be mitigated, in part, by the
Company's forward hedging activities.

FERC Refunds. The FERC issued an order on July 25, 2001 adopting a refund
methodology and initiating a hearing schedule to determine (1) revised mitigated
prices for each hour from October 2, 2000 through June 20, 2001; (2) the amount
owed in refunds by each supplier according to the methodology (these amounts may
be in addition to or in place of the refund amounts previously determined by the
FERC); and (3) the amount currently owed to each supplier. The amounts of any
refunds will be determined by the FERC after the conclusion of the hearing
process. On December 19, 2001, the FERC issued an order modifying the
methodology to be used to determine refund amounts. The schedule currently
anticipates that the Administrative Law Judge will make his refund amount
recommendations to the FERC in October 2002. However, the Company does not know
when the FERC will issue its final decision. The Company has not reserved any
amounts for potential future refund liability resulting from the FERC refund
hearing, nor can it currently predict the amount of these potential refunds, if
any, because the methodology used to calculate these refunds is not final and
will depend on information that is still subject to review and challenge in the
hearing process. Any refunds that are determined in the FERC proceeding will
likely be offset against unpaid amounts owed, if any, to the Company for its
prior sales.

On November 20, 2001, the FERC instituted an investigation under Section
206 of the Federal Power Act regarding the tariffs of all sellers with
market-based rates authority, including the Company. In this proceeding, the
FERC conditions the market-based rate authority of all sellers on their not
engaging in anti-competitive behavior. Such condition will apply upon a further
order from FERC establishing a refund effective date. This condition allows the
FERC, if it determines that a seller has engaged in anti-competitive behavior
subsequent to the start of the refund effective period, to order refunds back to
the date of such behavior. The FERC invited comments regarding this proposal,
and the Company has filed comments in opposition to the proposal. On March 11,
2002, the FERC's Staff held a conference with market participants to discuss the
comments FERC has received, and possible modification of the proposed conditions
to address concerns raised in the comments while protecting consumers against
anticompetitive behavior. The timing of
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further action by FERC is uncertain. If the FERC does not modify or reject its
proposed approach for dealing with anti-competitive behavior, the Company's
future earnings may be affected by the open-ended refund obligation.

On February 13, 2002, the FERC issued an order initiating a staff
investigation into potential manipulation of electric and natural gas prices in
the Western region for the period January 1, 2000 forward. While this order does
not propose any action against the Company, if the investigation results in
findings that markets were dysfunctional during this period, those findings may
be used in support of existing or future claims by the FERC or others that
prices in the Company's long-term contracts entered into after January 1, 2000
for sales in the West region should be altered.

Other Investigations. In addition to the FERC investigation discussed
above, several state and other federal regulatory investigations and complaints
have commenced in connection with the wholesale electricity prices in California
and other neighboring Western states to determine the causes of the high prices
and potentially to recommend remedial action. In California, the California
State Senate and the California Office of the Attorney General have separate
ongoing investigations into the high prices and their causes. Although these
investigations have not been completed and no findings have been made in
connection with either of them, the California Attorney General has filed a
civil lawsuit in San Francisco Superior Court alleging that the Company has
violated state laws against unfair and unlawful business practices and a
complaint with the FERC alleging the Company violated the terms of its tariff
with the FERC (see Note 14(f)). Adverse findings or rulings could result in
punitive legislation, sanctions, fines or even criminal charges against the
Company or its employees. The Company is cooperating with both investigations
and has produced a substantial amount of information requested in subpoenas
issued by each body. The Washington and Oregon attorneys general have also begun
similar investigations.

Legislative Efforts. Since the inception of the California energy crisis,
various pieces of legislation, including tax proposals, have been introduced in
the U.S. Congress and the California Legislature addressing several issues
related to the increase in wholesale power prices in 2000 and 2001. For example,
a bill was introduced in the California legislature that would have created a
"windfall profits" tax on wholesale electricity sales and would subject exempt
wholesale generators, such as the Company's subsidiaries that own generation
facilities in California, to regulation by the CPUC as "public utilities." To
date, only a few energy-related bills have passed and the Company does not
believe that the legislation that has been enacted to date on these issues will
have a material adverse effect on the Company. However, it is possible that
legislation could be enacted on either the state or federal level that could
have a material adverse effect on the Company's financial condition, results of
operations and cash flows.

(h) INDEMNIFICATION OF STRANDED COSTS

Background. In January 2001, the Dutch Electricity Production Sector
Transitional Arrangements Act (Transition Act) became effective and, among other
things, allocated to REPGB and the three other large-scale Dutch generation
companies, a share of the assets, liabilities and stranded cost commitments of
NEA. Prior to the enactment of the Transition Act, NEA acted as the national
electricity pooling and coordinating body for the generation output of REPGB and
the three other large-scale national Dutch generation companies. REPGB and the
three other large-scale Dutch generation companies are shareholders of NEA.

The Transition Act and related agreements specify that REPGB has a 22.5%
share of NEA's assets, liabilities and stranded cost commitments. NEA's stranded
cost commitments consisted primarily of various uneconomical or stranded cost
investments and commitments, including a gas supply and three power contracts
entered into prior to the liberalization of the Dutch wholesale electricity
market. REPGB's stranded cost obligations also include uneconomical district
heating contracts which were previously administrated by NEA prior to
deregulation of the Dutch power market.

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The gas supply contract expires in 2016 and provides for gas imports
aggregating 2.283 billion cubic meters per year. Prior to December 31, 2001, one
of the stranded cost power contracts was settled. The two remaining stranded
cost power contracts have the following capacities and terms: (a) 300 MW through
2005, and (b) 600 MW through March 2002 and 750 MW through 2009. Under the
Transition Act, REPGB can either assume its 22.5% allocated interest in the
contracts or, subject to the terms of the contracts, sell its interests to third
parties. The district heating obligations relate to three heating water supply
contacts entered into with various municipalities and expire from 2013 through
2015. Under the district heating contracts, the municipal districts are required
to take annually a combined minimum of 5,549 terajoules (TJ) increasing annually
to 7,955 TJ over the life of the contracts.

The Transition Act also authorized the government to purchase from NEA at
least a majority of the shares in the Dutch national transmission grid company
which was sold to the Dutch government on October 25, 2001 for approximately NLG
2.6 billion (approximately $1.05 billion based on an exchange rate of 2.48 NLG
per U.S. dollar as of December 31, 2001).

Prior to December 31, 2001, the former shareholders agreed pursuant to a
share purchase agreement to indemnify REPGB for up to NLG 1.9 billion in
stranded cost liabilities (approximately $766 million). The indemnity obligation
of the former shareholders and various provincial and municipal entities
(including the city of Amsterdam), was secured by a NLG 900 million escrow
account (approximately $363 million).

The Transition Act provided that, subject to the approval of the European
Commission, the Dutch government will provide financial compensation to the
Dutch generation companies, including REPGB, for liabilities associated with (a)
long-term district heating contracts and (b) an experimental coal facility. In
July 2001, the European Commission ruled that under certain conditions the Dutch
government can provide financial compensation to the generation companies for
the district heating contracts. To the extent that this compensation is not
ultimately provided to the generation companies by the Dutch government, REPGB
was to collect its compensation directly from the former shareholders as further
discussed below.

In January 2001, the Company recognized an out-of-market, net stranded cost
liability for its gas and electric contracts and district heating commitments.
At such time, the Company recorded a corresponding asset of equal amount for the
indemnification of this obligation from REPGB's former shareholders and the
Dutch government, as applicable. Pursuant to SFAS No. 133, the gas and electric
contracts are marked-to-market (see Note 5). As of December 31, 2001, the
Company has recorded a liability of $369 million for its stranded cost gas and
electric commitments in non-trading derivative liabilities and a liability of
$206 million for its district heating commitments in current and non-current
other liabilities. As of December 31, 2001, the Company has recorded an
indemnification receivable from the Dutch government for the district heating
stranded cost liability of $206 million. The settlement of the indemnification
related to gas and electric contract commitments in December 2001 is discussed
below.

Settlement of Stranded Cost Indemnification. In December 2001, REPGB and
its former shareholders entered into a settlement agreement immediately
resolving the former shareholders of their stranded cost indemnity obligations
related to the gas supply and power contracts under the original share purchase
agreement, and provides conditional terms for the possible settlement of their
stranded cost indemnity obligation related to district heating obligations under
certain conditions. The settlement agreement was approved in December 2001 by
the Ministry of Economic Affairs of the Netherlands.

Under the settlement agreement, the former shareholders paid to REPGB NLG
500 million ($202 million) in January and February 2002. The payment represents
a settlement of the obligations of the former shareholders to indemnify REPGB
for all stranded cost liabilities other than those relating to the district
heating contracts. The full amount of this payment was placed into an escrow
account in the name of REPGB to fund its stranded cost obligations related to
the gas and electric import contracts. Any remaining escrow funds as of January
1, 2004 will be distributed to REPGB.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Under the settlement agreement, the former shareholders will continue to
indemnify REPGB for the stranded cost liabilities relating to district heating
contracts. The terms of the indemnity are as follows:

- The settlement agreement acknowledges that the Netherlands is finalizing
regulations for compensation of stranded cost associated with district
heating projects. Within 21 days after the date these compensation rules
take effect, REPGB can elect to receive one of two forms of
indemnification under the settlement agreement.

- If the compensation to be paid by the Netherlands under these rules is at
least as much as the compensation to be paid under the original
indemnification agreement, REPGB can elect to receive a one-time payment
of NLG 60 million ($24 million). In addition, unless the decree
implementing the new compensation rules provides for compensation for the
lifetime of the district heating projects, REPGB can receive an
additional cash payment of NLG 15 million ($6 million).

- If the compensation rules do not provide for compensation at least equal
to that provided under the original indemnification agreement, REPGB can
claim indemnification for stranded cost losses up to a maximum of NLG 700
million ($282 million) less the amount of compensation provided by the
new compensation rules and certain proceeds received from arbitrations.

- If no new compensation rules have taken effect on or prior to December
31, 2003, REPGB is entitled, but not obligated, to elect to receive
indemnification under the formula described above.

Under the terms of the original indemnification agreement, the former
shareholders were entitled to receive any and all distributions and dividends
above NLG 125 million ($51 million) paid by NEA. Under the settlement agreement,
the former shareholders waived all rights under the original indemnification
agreement to claim distributions of NEA.

Reliant Resources recognized a net gain of $37 million for the difference
between the sum of (a) the cash settlement payment of $202 million and the
additional rights to claim distributions of Reliant Resources' NEA investment
recognized of $248 million and (b) the amount recorded as stranded cost
indemnity receivable related to the stranded cost gas and electric commitments
of $369 million and claims receivable related to stranded cost incurred in 2001
of $44 million both previously recorded in the Consolidated Balance Sheets.

Investment in NEA. During the second quarter of 2001, Reliant Resources
recorded a $51 million pre-tax gain (NLG 125 million) recorded as equity income
for the preacquisition gain contingency related to the acquisition of REPGB for
the value of its equity investment in NEA. This gain was based on Reliant
Resources' evaluation of NEA's financial position and fair value. The fair value
of Reliant Resources' investment in NEA is dependent upon the ultimate
resolution of its existing contingencies and proceeds received from liquidating
its remaining net assets. Prior to the settlement agreement discussed above,
pursuant to the purchase agreement of REPGB, as amended, REPGB was entitled to a
NLG 125 million dividend from NEA with any remainder owing to the former
shareholders. As mentioned above, REPGB entered into an agreement with its
former shareholders to settle the original indemnification agreement and the
former shareholders waived all rights to distributions of NEA. Accordingly, as a
component of the net gain recognized from the settlement of the stranded cost
indemnity, Reliant Resources recorded a $248 million increase in its investment
in NEA. As of December 31, 2001, Reliant Resources has recorded $299 million in
equity investments of unconsolidated subsidiaries for its investment in NEA.

(i) OPERATIONS AGREEMENT WITH CITY OF SAN ANTONIO

As part of the 1996 settlement of certain litigation claims asserted by the
City of San Antonio with respect to the South Texas Project, the Company entered
into a 10-year joint operations agreement under which the Company and the City
of San Antonio, acting through the City Public Service Board of San Antonio
(CPS), share savings resulting from the joint dispatching of their respective
generating assets in

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order to take advantage of each system's lower cost resources. In January 2000,
the contract term was extended for three years and is expected to terminate in
2009. Under the terms of the joint operations agreement entered into between CPS
and Electric Operations, the Company has guaranteed CPS minimum annual savings
of $10 million up to a total cumulative savings of $150 million over the term of
the agreement. The cumulative obligation was met in the first quarter of 2001.
In 1999, 2000 and 2001, savings generated for CPS' account were $14 million, $60
million and $65 million, respectively. Through December 31, 2001, cumulative
savings generated for CPS' account were $189 million.

(j) NUCLEAR INSURANCE

The Company and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.

Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of December 31, 2001. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. The Company and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan.

There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.

(k) NUCLEAR DECOMMISSIONING

The Company contributed $14.8 million per year in 1999, 2000 and 2001 to a
trust established to fund its share of the decommissioning costs for the South
Texas Project. Pursuant to the October 3, 2001 Order, beginning in 2002, the
Company will contribute $2.9 million per year to this trust. There are various
investment restrictions imposed upon the Company by the Texas Utility Commission
and the NRC relating to the Company's nuclear decommissioning trust.
Additionally, the Company's board of directors has appointed the Nuclear
Decommissioning Trust Investment Committee to establish the investment policy of
the trust and oversee the investment of the trusts' assets. The securities held
by the trust for decommissioning costs had an estimated fair value of $169
million as of December 31, 2001, of which approximately 46% were fixed-rate debt
securities and the remaining 54% were equity securities. For a discussion of the
accounting treatment for the securities held in the Company's nuclear
decommissioning trust, see Note 2(l). In July 1999, an outside consultant
estimated the Company's portion of decommissioning costs to be approximately
$363 million. While the current funding levels currently exceed minimum NRC
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning
and changes in regulatory requirements, technology and costs of labor, materials
and equipment. Pursuant to the Texas Electric Restructuring Law, costs
associated with nuclear decommissioning that have not been recovered as of
January 1, 2002, will continue to be subject to cost-of-service rate regulation
and will be included in a charge to transmission and distribution customers. For
information regarding the effect of the Business Separation Plan on funding of
the nuclear decommissioning trust fund, see Note 4(b).

(l) CONSTRUCTION AGENCY AGREEMENT AND EQUIPMENT FINANCING STRUCTURE

In 2001, Reliant Resources, through several of its subsidiaries, entered
into operative documents with special purpose entities to facilitate the
development, construction, financing and leasing of several power
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

generation projects. The special purpose entities are not consolidated by the
Company. The special purpose entities have an aggregate financing commitment
from equity and debt participants (Investors) of $2.5 billion of which the last
$1.1 billion is currently available only if the cash is collateralized. The
availability of the commitment is subject to satisfaction of various conditions,
including the obligation to provide cash collateral for the loans and letters of
credit outstanding on November 27, 2004. Reliant Resources, through several of
its subsidiaries, acts as construction agent for the special purpose entities
and is responsible for completing construction of these projects by December 31,
2004, but Reliant Resources has generally limited its risk during construction
to an amount not in excess of 89.9% of costs incurred to date, except in certain
events. Upon completion of an individual project and exercise of the lease
option, Reliant Resources' subsidiaries will be required to make lease payments
in an amount sufficient to provide a return to the Investors. If Reliant
Resources does not exercise its option to lease any project upon its completion,
Reliant Resources must purchase the project or remarket the project on behalf of
the special purpose entities. Reliant Resources' ability to exercise the lease
option is subject to certain conditions. Reliant Resources must guarantee that
the Investors will receive an amount at least equal to 89.9% of their investment
in the case of a remarketing sale at the end of construction. At the end of an
individual project's initial operating lease term (approximately five years from
construction completion), Reliant Resources' subsidiary lessees have the option
to extend the lease with the approval of Investors, purchase the project at a
fixed amount equal to the original construction cost, or act as a remarketing
agent and sell the project to an independent third party. If the lessees elect
the remarketing option, they may be required to make a payment of an amount not
to exceed 85% of the project cost, if the proceeds from remarketing are not
sufficient to repay the Investors. Reliant Resources has guaranteed the
performance and payment of its subsidiaries' obligations during the construction
periods and, if the lease option is exercised, each lessee's obligations during
the lease period. At any time during the construction period or during the
lease, Reliant Resources may purchase a facility by paying an amount
approximately equal to the outstanding balance plus costs.

Reliant Resources, through its subsidiary, REPG, has entered into an
agreement with a bank whereby the bank, as owner, entered or will enter into
contracts for the purchase and construction of power generation equipment and
REPG, or its subagent, acts as the bank's agent in connection with administering
the contracts for such equipment. Under the agreement, the bank has agreed to
provide up to a maximum aggregate amount of $650 million. REPG and its subagents
must cash collateralize their obligation to administer the contracts. This cash
collateral is approximately equivalent to the total payments by the bank for the
equipment, interest and other fees. As of December 31, 2001, the bank had
assumed contracts for the purchase of eleven turbines, two heat recovery steam
generators and one air-cooled condenser with an aggregate cost of $398 million.
REPG, or its designee, has the option at any time to purchase, or, at equipment
completion, subject to certain conditions, including the agreement of the bank
to extend financing, to lease the equipment, or to assist in the remarketing of
the equipment under terms specified in the agreement. All costs, including the
purchase commitment on the turbines, are the responsibility of the bank. The
cash collateral is deposited by REPG or an affiliate into a collateral account
with the bank and earns interest at LIBOR less 0.15%. Under certain
circumstances, the collateral deposit or a portion of it, will be returned to
REPG or its designee. Otherwise, it will be retained by the bank. At December
31, 2001, REPG and its subsidiary had deposited $230 million into the collateral
account. The bank's payments for equipment under the contracts totaled $227
million as of December 31, 2001. 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
Reliant Resources' collateral deposits were returned to Reliant Resources. As of
December 31, 2001, there were equipment contracts with a total contractual
obligation of $140 million under which payments during construction totaled $83
million. Currently this equipment is not designated for current planned power
generation construction projects. Therefore, the Company anticipates that it
will either purchase the equipment, assist in the remarketing of the equipment
or negotiate to cancel the related contracts.

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(15) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of cash and cash equivalents, investments in debt and
equity securities classified as "available-for-sale" and "trading" in accordance
with SFAS No. 115, and short-term borrowings are estimated to be approximately
equivalent to carrying amounts and have been excluded from the table below. The
fair value of financial instruments included in the trading operations are
marked-to-market at December 31, 2000 and 2001 (see Note 5). The fair values of
non-trading derivative assets and liabilities are recognized in the Consolidated
Balance Sheets at December 31, 2001 (see Note 5). Therefore, these financial
instruments are stated at fair value and are excluded from the table below. The
fair values of non-trading derivative assets and liabilities as of December 31,
2000 have been determined using quoted market prices for the same or similar
instruments when available or other estimation techniques.

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(16) EARNINGS PER SHARE

The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share (EPS) calculations:

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

(1) Options to purchase 433,915, 442,385 and 2,074,437 shares were outstanding
for the years ended December 31, 1999, 2000 and 2001, respectively, but were
not included in the computation of diluted EPS because the options' exercise
price was greater than the average market price of the common shares for the
respective years.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(17) UNAUDITED QUARTERLY INFORMATION

Summarized quarterly financial data is as follows:

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

(1) Quarterly earnings per common share are based on the weighted average number
of shares outstanding during the quarter, and the sum of the quarters may
not equal annual earnings per common share.

The quarterly operating results incorporate the results of operations of
REMA from its respective acquisition date as discussed in Note 3(a). The
variances in revenues, operating income and net income (loss) from quarter to
quarter were primarily due to this acquisition, the seasonal fluctuations in
demand for energy and energy services and changes in energy commodity prices and
the timing of maintenance expenses on electric generation plants.

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RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Effective December 1, 2000, Reliant Energy's board of directors approved a
plan to dispose of the Company's Latin America business segment through sales of
its assets. Accordingly, in its 2000 consolidated financial statements, the
Company reported the results of its Latin America business segment as
discontinued operations in accordance with APB Opinion No. 30 for each of the
three years in the period ended December 31, 2000.

On December 20, 2001, negotiations for the sale of the Company's remaining
Latin America investments were terminated as a result of the recent adverse
economic developments in Argentina.

Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Statements of Consolidated Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by EITF 90-6. For additional discussion of our Latin
America business segment, see Note 19.

(18) REPORTABLE BUSINESS SEGMENTS

The Company's determination of reportable business segments considers the
strategic operating units under which the Company manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. Financial information
for REMA and REPGB are included in the business segment disclosures only for
periods beginning on their respective acquisition dates. The accounting policies
of the business segments are the same as those described in the summary of
significant accounting policies except that some executive benefit costs have
not been allocated to business segments. The Company evaluates performance based
on operating income excluding some corporate costs not allocated to the business
segments. Long-lived assets include net property, plant and equipment, net
goodwill, net air emissions regulatory allowances and other intangibles and
equity investments in unconsolidated subsidiaries. The Company accounts for
intersegment sales as if the sales were to third parties, that is, at current
market prices. In the fourth quarter of 2000, the Company transferred its
non-rate regulated retail gas marketing operations from Retail Energy to Natural
Gas Distribution and its natural gas gathering business from Wholesale Energy to
Pipelines and Gathering. In the third quarter of 2001, the Company began
reporting the results of its unregulated retail electric business as a separate
business segment entitled "Retail Energy". Historically, Retail Energy's
operations had been reported as part of the Other Operations business segment.
Reportable business segments from previous years have been restated to conform
to the 2001 presentation.

Effective December 1, 2000, Reliant Energy's board of directors approved a
plan to dispose of the Company's Latin America business segment through sales of
its assets. Accordingly, in its 2000 consolidated financial statements, the
Company reported the results of its Latin America business segment as
discontinued operations in accordance with APB Opinion No. 30 for each of the
three years in the period ended December 31, 2000.

On December 20, 2001, negotiations for the sale of the Company's remaining
assets in Argentina were terminated as a result of the recent adverse economic
developments in Argentina. The Company will continue to evaluate options related
to the future disposition of these assets. Accordingly, the Latin America
business segment is no longer reported as discontinued operations.

206

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company has identified the following reportable business segments:
Electric Operations, Natural Gas Distribution, Pipelines and Gathering,
Wholesale Energy, European Energy, Retail Energy, Latin America and Other
Operations. For a description of the financial reporting business segments, see
Note 1. Financial data for business segments, products and services and
geographic areas are as follows:

207

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

208

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

After the Distribution, CenterPoint Energy's business will consist
principally of regulated operations. As a result, CenterPoint Energy's business
segments will consist of the following:

- Electric Transmission and Distribution;

- Electric Generation;

- Natural Gas Distribution;

- Pipelines and Gathering; and

- Other Operations.

The Wholesale Energy, European Energy, Retail Energy and unregulated
portions of our Other Operations business segments will be conducted by Reliant
Resources as a separate publicly traded company. The operations conducted by the
Electric Generation business segment may also be acquired by Reliant Resources
in January 2004 pursuant to the Texas Genco Option. For additional information,
see Note 4(b).

(19) DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

Effective December 1, 2000, Reliant Energy's board of directors approved a
plan to dispose of the Company's Latin America business segment through sales of
its assets. Accordingly, in its 2000 consolidated financial statements, the
Company reported the results of its Latin America business segment as
discontinued operations in accordance with APB Opinion No. 30 for each of the
three years in the period ended December 31, 2000.

In the fourth quarter of 2000, the Latin America business segment sold its
investments in El Salvador, Colombia and Brazil for an aggregate $790 million in
after-tax proceeds. The Company recorded a $242 million after-tax ($294 million
pre-tax) loss in connection with the sale of these investments. The Company,
through its subsidiaries, continues to operate investments in Argentina which
include a 100% interest in a 160 MW cogeneration project, Argener, and a 90%
interest in a utility, EDESE (collectively, the Argentine Investments).

In the fourth quarter of 2000 and in the first quarter of 2001, the Company
recorded additional after-tax impairments related to the Argentine Investments
of $89 million and $7 million ($95 million and $6 million pre-tax),
respectively, based on the expected net realizable value of the businesses upon
their disposition.

On December 20, 2001, negotiations for the sale of the Argentine
Investments were terminated as a result of the recent adverse economic
developments in Argentina. The Company will continue to evaluate options related
to the future disposition of these assets.

Accordingly, the Latin America business segment is no longer reported as
discontinued operations. The related operating results and loss on disposal have
been reclassified within the Statements of Consolidated Income for all periods
into operating income with respect to consolidated subsidiaries and other income
with respect to equity investments in unconsolidated subsidiaries as required
for assets held for sale by EITF 90-6.

During December 2001, the Company concluded there were indicators of
impairment related to the remaining assets in this business segment, and
accordingly, an impairment evaluation was conducted at the end of the fourth
quarter under the guidelines of SFAS No. 121. This evaluation resulted in an
after-tax impairment charge of $43 million ($80 million pre-tax), representing
the excess of book value over estimated net realizable value. As of December 31,
2001, the Company had $8 million of Latin America net assets held for sale
recorded in its Consolidated Balance Sheets. The fair value of the remaining net
assets was determined using a net discounted cash flows approach. The charge was
included as a component of operating income with respect to consolidated
subsidiaries and other income with respect to equity investments in

209

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

unconsolidated subsidiaries. The impairment was primarily related to the recent
economic deterioration in Argentina.

(20) RELIANT ENERGY COMMUNICATIONS

During the third quarter of 2001, management decided to exit the Company's
Communications business which served as a facility-based competitive local
exchange carrier and Internet services provider and owned network operations
centers and managed data centers in Houston and Austin. Consequently, the
Company determined the goodwill associated with the Communications business was
impaired. The Company recorded a total of $54 million of pre-tax disposal
charges in the third and fourth quarters of 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.

(21) BANKRUPTCY OF ENRON CORP. AND ITS AFFILIATES

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

The non-trading derivatives with Enron were designated as Cash Flow Hedges
(see Note 5). The net gain on these derivative instruments previously reported
in other comprehensive income will remain in accumulated other comprehensive
loss and will be reclassified into earnings during the period in which the
originally designated hedged transactions occur.

(22) SUBSEQUENT EVENTS

(a) ORION POWER HOLDINGS, INC.

In February 2002, Reliant Resources acquired all of the outstanding shares
of Orion Power for $26.80 per share in cash for an aggregate purchase price of
$2.9 billion. Reliant Resources funded the Orion Power acquisition with a term
loan supported by a $2.9 billion credit facility and $41 million of cash on
hand. Interest rates on the term loan are based on LIBOR plus a margin or a base
rate. The term loan must be repaid within one year from the date on which it was
funded. As a result of the acquisition, Reliant Resources' consolidated net debt
obligations also increased by the amount of Orion Power's net debt obligations.
As of February 19, 2002, Orion Power's debt obligations were $2.4 billion ($2.1
billion net of cash acquired some of which is restricted pursuant to debt
covenants). Orion Power is an independent electric power generating company
formed in March 1998 to acquire, develop, own and operate power-generating
facilities in certain deregulated wholesale markets throughout North America. As
of February 28, 2002, Orion Power had 81 power plants in operation with a total
generating capacity of 5,644 MW and an additional 804 MW in construction or in
various stages of development.

(b) FACTORING AGREEMENT

In the first quarter of 2002, RERC reduced its trade receivables facility
from $350 million to $150 million. Borrowings under the receivables facility
aggregating $196 million were repaid in January 2002 with proceeds from the
issuance of commercial paper under RERC's $350 million revolving credit facility
and from the liquidation of short-term investments.

210

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(c) INTEREST RATE SWAPS

In the first quarter of 2002, the Company entered into interest rate swaps
with an aggregate notional amount of $1.25 billion. Swaps with a notional amount
of $250 million were entered into for the purpose of fixing rates on short-term
debt subject to interest rate fluctuations and do not qualify as cash flow
hedges under SFAS No. 133. The swaps with a notional amount of $1 billion were
entered into to hedge the interest rate on a future offering of five-year fixed
rate notes. These swaps qualify as cash flow hedges under SFAS No. 133.

211

INDEPENDENT AUDITORS' REPORT

Reliant Energy, Incorporated:

We have audited the accompanying consolidated balance sheets of Reliant
Energy, Incorporated and its subsidiaries (the Company) as of December 31, 2000
and 2001, and the related statements of consolidated income, consolidated
comprehensive income, consolidated cash flows and consolidated stockholders'
equity for each of the three years in the period ended December 31, 2001. Our
audits also included the Company's financial statement schedule listed in Item
14(a)(2). These financial statements and the financial statement schedule are
the responsibility of the Company's management. Our responsibility is to express
an opinion on these financial statements and the financial statement schedule
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,
2000 and 2001, and the consolidated results of its operations and its 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 of America.
Also, in our opinion, such financial statement schedule, when considered in
relation to the basic consolidated financial statements taken as a whole,
presents fairly in all material respects the information set forth therein.

As discussed in Note 5 to the financial statements, the Company changed its
method of accounting for derivatives and hedging activities in 2001.

DELOITTE & TOUCHE LLP

Houston, Texas
March 28, 2002

212

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

The information called for by Item 10, to the extent not set forth in
"Executive Officers of Reliant Energy" in Item 1, is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2002 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders 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 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2002 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders 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

The information called for by Item 12 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2002 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders 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 is or will be set forth in the
definitive proxy statement relating to Reliant Energy's 2002 annual meeting of
shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders 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.

PART IV

ITEM 14. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) Financial Statements.
Statements of Consolidated Income for the Three Years Ended December
31, 2001........................................................... 132
Statements of Consolidated Comprehensive Income for the Three Years
Ended December 31, 2001............................................ 133
Consolidated Balance Sheets at December 31, 2001 and 2000........... 134
Statements of Consolidated Cash Flows for the Three Years Ended
December 31, 2001 135
Statements of Consolidated Stockholders' Equity for the Three Years
Ended December 31, 2001............................................ 136

Notes to Consolidated Financial Statements.......................... 137
Independent Auditors' Report........................................ 212
(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2001.
II -- Reserves...................................................... 215

213

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:

I, III, IV and V.

(a)(3) Exhibits.

See Index of Exhibits on page 217, which index also includes 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.

On December 18, 2001, we filed a Current Report on Form 8-K dated December
17, 2001 announcing shareholder approval of our corporate restructuring.

On January 11, 2002, we filed a Current Report on Form 8-K dated December
18, 2001 relating to the execution of a settlement agreement regarding European
stranded cost indemnification.

On February 5, 2002, we filed a Current Report on Form 8-K dated February
5, 2002 regarding a delay in the release of earnings and restatement of 2001
results.

On March 6, 2002, we filed a Current Report on Form 8-K dated February 19,
2002 regarding Reliant Resources' acquisition of Orion Power Holdings, Inc.

On March 15, 2002, we filed a Current Report on Form 8-K dated March 15,
2002 regarding our 2001 earnings and the effects of our restatement.

On April 5, 2002, we filed a Current Report on Form 8-K regarding an SEC
informal inquiry.

214

RELIANT ENERGY, INCORPORATED AND SUBSIDIARIES

SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2001

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

(1) Charged to Other Accounts represents obligations acquired through business
acquisitions.

(2) Deductions from reserves represent 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.

215

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the 15th day of April, 2002.

RELIANT ENERGY, INCORPORATED
(Registrant)

By: /s/ R. STEVE LETBETTER
------------------------------------
R. Steve Letbetter,
Chairman, President and Chief
Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on April 15, 2002.

216

RELIANT ENERGY, INCORPORATED

EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2001

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.

217

218

219

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, Reliant Energy has
not filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of securities authorized do
not exceed 10% of the total assets of Reliant Energy and its subsidiaries on a
consolidated basis. Reliant Energy hereby agrees to furnish a copy of any such
instrument to the SEC upon request.

220

221

222

223

224

225

226