TEXAS GENCO HOLDINGS 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, 2003

OR

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE TRANSITION PERIOD FROM TO

COMMISSION FILE NUMBER 1-31449

TEXAS GENCO HOLDINGS, INC.
(Exact name of registrant as specified in its charter)

TEXAS 76-0695920
(State or other jurisdiction of (I.R.S. Employer
incorporation or organization) Identification Number)

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

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 the registrant's 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. [X]

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

The aggregate market value of the voting stock held by non-affiliates of
the Company was $353,182,653 as of June 30, 2003, 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 February 29, 2004, the Company had 80,000,000 shares
of Common Stock outstanding.

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

TABLE OF CONTENTS

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," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," 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.

Some of the factors that could cause actual results to differ from those
expressed or implied by our forward-looking statements are described under "Risk
Factors" beginning on page 18 in Item 1 of this report.

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

PART I

ITEM 1. BUSINESS.

OUR BUSINESS

GENERAL

We are a wholesale electric power generating company that owns 60
generating units at 11 electric power generation facilities located in Texas. We
also own a 30.8% interest in the South Texas Project Electric Generating Station
(South Texas Project), a nuclear generating station with two 1,250 megawatt (MW)
nuclear generating units. As of December 31, 2003, the aggregate net generating
capacity of our portfolio of assets was 14,153 MW, of which 2,988 MW of
gas-fired capacity was mothballed. We sell electric generation capacity, energy
and ancillary services within the Electric Reliability Council of Texas, Inc.
(ERCOT) market. The ERCOT market consists of the majority of the population
centers in the State of Texas and facilitates reliable grid operations for
approximately 85% of the demand for power in the state.

In June 1999, the Texas legislature enacted legislation (Texas electric
restructuring law) which substantially amended the regulatory structure
governing electric utilities in Texas in order to encourage retail electric
competition. Under the Texas electric restructuring law, we ceased to be subject
to traditional cost-based regulation. Since January 1, 2002, we have been
selling generation capacity, energy and ancillary services to wholesale
purchasers at prices determined by the market. Accordingly, our historical
financial information and operating data, such as demand and fuel data, covering
periods prior to 2002 do not reflect what our financial position, results of
operations and cash flows would have been had our generation facilities been
operated during those periods under the current deregulated ERCOT market.

As a result of requirements under the Texas electric restructuring law and
agreements with our parent company, CenterPoint Energy, Inc. (CenterPoint
Energy), we were obligated to sell substantially all of our capacity and related
ancillary services through 2003 pursuant to capacity auctions. In these
auctions, we sell firm entitlements to capacity and ancillary services on a
forward basis dispatched within specified operational constraints. In our
capacity auctions held through February 2004, we sold entitlements to 85% and
24% of our available capacity for 2004 and 2005, respectively. For more
information regarding our auctions, please read "Capacity Auctions and
Opportunity Sales" below.

Texas Genco Holdings, Inc. (Texas Genco) is an indirect majority owned
subsidiary of CenterPoint Energy. Our portfolio of generation facilities was
formerly owned by the unincorporated electric utility division of Reliant
Energy, Incorporated (Reliant Energy), the predecessor of CenterPoint Energy
Houston Electric, LLC (CenterPoint Houston). CenterPoint Houston is an indirect
wholly owned subsidiary of CenterPoint Energy. Reliant Energy conveyed these
facilities to us in accordance with a business separation plan adopted in
response to the Texas electric restructuring law. For convenience, we describe
our business in this report as if we had owned and operated our generation
facilities prior to the date they were conveyed to us. On January 6, 2003,
CenterPoint Energy distributed approximately 19% of the 80 million outstanding
shares of Texas Genco's common stock to CenterPoint Energy's common
shareholders. CenterPoint Energy now indirectly owns approximately 81% of the
outstanding shares of Texas Genco's common stock. For more information, please
read "Background of the Distribution of Texas Genco Shares" below. CenterPoint
Energy expects to monetize its 81% interest in Texas Genco in 2004, which could
involve the sale of all or a portion of its equity interest in Texas Genco.
Pursuant to its plan, CenterPoint Energy has engaged a financial advisor and has
solicited indications of interest from a number of potential buyers.

CenterPoint Energy is a registered holding company under the Public Utility
Holding Company Act of 1935, as amended (1935 Act). The 1935 Act directs the
Securities and Exchange Commission (SEC) to regulate, among other things,
transactions among affiliates, sales or acquisitions of assets, issuances of
securities, distributions and permitted lines of business. In October 2003, the
Federal Energy Regulatory Commission (FERC) granted exempt wholesale generator
status to Texas Genco, LP, our wholly owned subsidiary that owns and operates
our electric generating plants. As a result, we are exempt from substantially
all provisions of the 1935 Act as long as we remain an exempt wholesale
generator.

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Texas Genco was incorporated in Texas in August 2001. Our executive offices
are located at 1111 Louisiana, Houston, Texas 77002, and our telephone number is
(713) 207-1111. The generating assets of Texas Genco are owned and operated by
Texas Genco, LP, its indirect wholly owned subsidiary. In this report, the terms
"we," "us" or similar terms mean Texas Genco and its subsidiaries, unless the
context indicates otherwise, while references to Texas Genco mean only the
parent company.

We make available free of charge on our Internet website our annual report
on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and
amendments to those reports filed or furnished pursuant to Section 13(a) or
15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable
after we electronically file such reports with, or furnish them to, the SEC.
Additionally, we make available free of charge on our Internet website:

- our Code of Ethics for our Chief Executive Officer and Senior Financial
Officers;

- our Ethics and Compliance Code;

- our Corporate Governance Guidelines; and

- the charters of our audit and compensation committees.

Any shareholder who so requests may obtain a printed copy of any of these
documents from us. Changes in or waivers of our Code of Ethics for our Chief
Executive Officer and Senior Financial Officers and waivers of our Ethics and
Compliance Code for directors or executive officers will be posted on our
Internet website within five business days and maintained for at least twelve
months or reported on Item 10 of our Forms 8-K. Our website address is
www.txgenco.com.

THE ERCOT MARKET

The ERCOT market consists of the State of Texas, other than a portion of
the panhandle, a portion of the eastern part of the state bordering on Louisiana
and the area in and around El Paso. The ERCOT market represents approximately
85% of the demand for power in Texas and is one of the nation's largest power
markets. The ERCOT market includes an aggregate net generating capacity of
approximately 78,000 MW. There are only limited direct current interconnections
between the ERCOT market and other power markets in the United States.

The ERCOT market operates under the reliability standards set by the North
American Electric Reliability Council. The Public Utility Commission of Texas
(Texas Utility Commission) has primary jurisdiction over the ERCOT market to
ensure the adequacy and reliability of electricity supply across the state's
main interconnected power transmission grid. 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 electricity production and delivery are accurately
accounted for among the generation resources and wholesale buyers and sellers.
Unlike independent systems operators in other regions of the country, the ERCOT
market 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
sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for
procuring ancillary services for those who elect not to provide their own
ancillary services.

The amount by which power generating capacity exceeded peak demand (reserve
margin) in the ERCOT market has exceeded 30% since 2001, and the Texas Utility
Commission and the ERCOT ISO have forecasted the reserve margin for 2004 to
continue to exceed 30%. The commencement of commercial operation of new
facilities in the ERCOT market will increase the competition within the
wholesale power market, which could have a material adverse effect on our
business, results of operations, financial condition and cash flows and the
market value of our assets. The demand for power in the ERCOT market is
seasonal, with higher demand occurring during the warmer months.

2

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 ERCOT
market at unregulated rates. Transmission capacity, which may be limited, is
needed to effect power sales. In the ERCOT market, buyers and sellers enter into
bilateral wholesale capacity, energy and ancillary services contracts or may
participate in the centralized ancillary services market, which the ERCOT ISO
administers. Also, companies whose power generation facilities were formerly
part of integrated utilities, like us, are required to auction entitlements to
15% of their capacity. For additional information regarding these auctions,
please read "Capacity Auctions and Opportunity Sales -- State-mandated Auctions"
below. Wholesale buyers and sellers may also engage in spot market transactions
in the ERCOT market.

The transmission capacity available in the ERCOT market affects power
sales. The power transfer from generators to meet demand across a transmission
line is limited by the transfer capability of the line. Therefore, power sales
or purchases from one location to another may be constrained by the power
transfer capability between locations. A transmission path with significant
power flow, the loss of which may cause system reliability problems, is
identified as a commercially significant constraint. When scheduled power
transfers across transmission facility elements exceed the transfer capability
of such elements, the transmission facility is constrained and transmission
congestion is declared by the ERCOT ISO. Transmission congestion is then
resolved through the use of ancillary services and unit specific deployments to
reduce the transfer across the constrained facility. With the addition of new
loads, generators and transmission facilities and the re-rating of older
facilities, the commercially significant constraints and transfer capabilities
can change. Under current protocol, the commercially significant constraints and
the transfer capabilities along these paths are reassessed every year. The
single control area of the ERCOT market for 2004 is organized into five
congestion zones. The reserve margins may vary by congestion zone. The ERCOT ISO
has also instituted direct assignment of congestion cost to those parties
causing the congestion. This has the potential to increase the power generator's
exposure to the congestion costs associated with transferring power between
zones. The Texas Utility Commission has initiated a rulemaking project that
proposes to replace the existing zonal wholesale market design with a nodal
market design that is based on locational marginal prices for power. One of the
stated purposes of the proposed market restructuring is to reduce local
(intra-zonal) transmission congestion costs. The market redesign project is
expected to take effect in late 2006 at the earliest. We expect that
implementation of any new market design will require modifications to our
procedures and systems, and will have a potential impact on our staffing. We do
not expect our competitive position in the ERCOT market will be adversely
affected by the proposed market restructuring.

CAPACITY AUCTIONS AND OPPORTUNITY SALES

STATE-MANDATED AUCTIONS

As a power generation company that has been unbundled from an integrated
electric utility, we are required by the Texas electric restructuring law to
sell at auction firm entitlements to 15% of our installed generation capacity on
a forward basis for varying terms of up to two years. We refer to the auctions
held to satisfy this requirement as "state-mandated auctions." Our obligation to
conduct state-mandated auctions will continue until January 1, 2007, unless
before that date the Texas Utility Commission determines that loads equal to or
exceeding 40% of the electric power consumed in 2000 before the onset of retail
competition in Texas by residential and small commercial customers in
CenterPoint Houston's service area are being served by retail electric providers
not affiliated or formerly affiliated with CenterPoint Energy. Reliant
Resources, Inc. (Reliant Resources) is deemed to be an affiliate of CenterPoint
Energy for purposes of this test. Reliant Resources is currently not permitted
under the Texas electric restructuring law to purchase capacity sold by us in
the state-mandated auctions.

The capacity entitlements we are required to offer in the state-mandated
auctions are determined by rules adopted by the Texas Utility Commission. Under
these rules, we are required to sell entitlements to 15% of our installed
generation capacity in blocks of 25 MW each. Texas Utility Commission rules
require 50% of the 25 MW blocks we sell in these auctions to consist of
one-month allocations, or "strips," 30% to consist of one-

3

year strips, and 20% to consist of two-year strips. Purchasers of our capacity
entitlements offered in the state-mandated auctions may resell them to third
parties, other than Reliant Resources. We only auction entitlements to capacity
dispatched within specified operational constraints to specific zonal delivery
points and the entitlements do not convey any right to have power dispatched
from a specific generating unit. This enables us to dispatch our commitments in
the most cost-effective manner available. This also exposes us to the potential
risk that in the event one of our low-cost base-load facilities is shut down, we
may be required to satisfy our commitments with the output of higher cost
facilities or with replacement power purchased from third parties in the open
market. Additionally, like other power generating companies within ERCOT, we are
required to purchase power from certain qualifying facilities under the Public
Utility Regulatory Policies Act of 1978 at avoided cost.

The types of capacity entitlements we offer in our state-mandated auctions
include:

- base-load entitlements, representing our solid fuel, nuclear powered and
certain gas-fired generation capacity, that provide energy at a
relatively low fixed price and include limited ancillary service
capabilities;

- intermediate entitlements, representing various gas-fired generation
capacity, that provide energy indexed to natural gas prices and at a
specified heat rate and include flexible ancillary service capabilities;

- cyclic entitlements, representing various other gas-fired generation
capacity, that provide energy indexed to natural gas prices and at a
specified heat rate and include flexible ancillary service capabilities;
and

- peaking entitlements, representing various smaller gas-fired generation
capacity, that provide energy indexed to natural gas prices and at a
specified heat rate and include limited ancillary service capabilities.

Each of these categories of capacity entitlements is generally designed to
have operating characteristics similar to the assumed underlying generating
units. For example, base-load entitlements can be started once a month, whereas
cyclic entitlements can be started up to 20 times a month.

CONTRACTUALLY-MANDATED AUCTIONS

Through 2003, we were contractually obligated under an agreement with
Reliant Resources to auction entitlements to substantially all of our capacity
(less operating reserves) available after our state-mandated auctions. We were
permitted to reduce the amount of capacity sold in the contractually-mandated
auctions by the amount of operating reserves required to back up our obligations
under our capacity auctions. We typically reserve 1,250 MW of our capacity,
including 750 MW of base-load capacity, as operating reserves, which can be sold
as interruptible power on a system-contingent basis.

Through 2003, Reliant Resources had the contractual right, but not the
obligation, to purchase 50% (but not less than 50%) of each type of capacity
entitlement we auctioned in the contractually-mandated auctions at the prices
established in the auctions. Upon determination of the prices for the capacity
entitlements, Reliant Resources was obligated to purchase the capacity it
elected to reserve from the auction process at the prices set during the auction
for that entitlement. In addition to its reservation of capacity, and whether or
not it had reserved capacity in the auction, Reliant Resources was entitled to
bid for entitlements in each contractually-mandated auction.

Since Reliant Resources chose not to exercise its option to purchase the
shares of Texas Genco's common stock owned by CenterPoint Energy in January
2004, we are no longer obligated to conduct any capacity auctions, other than as
required by the Texas Utility Commission's rules. We may continue to sell our
capacity in a manner similar to such contractually-mandated auctions as well as
seek sales under bilateral contracts for a portion of our capacity in the
future. As described below under "-- Auction Results," we have made significant
forward sales of our 2004 and 2005 capacity pursuant to our auctions.

4

AUCTION PRICING METHODOLOGY

Revenues derived from our capacity auctions come from two sources: capacity
payments and energy payments. Capacity payments are based on the final clearing
prices, in dollars per kilowatt-month, determined during the auctions. We bill
and collect for these capacity payments on a monthly basis just prior to the
month of the entitlement. Energy payments consist of a variety of charges
related to the fuel and ancillary services scheduled through our auctioned
capacity entitlements. Energy payments for base-load products are tied to fixed
prices specified in the auction products while energy payments for gas-based
products are recovered through heat rates specified for gas auction products
times an index based on the Houston Ship Channel Gas price. Additional charges,
referred to as "adders," are included in the energy payments to cover additional
costs we incur when we are required to operate our facilities at less efficient
operating ranges. We bill for these energy payments on a monthly basis in
arrears.

AUCTION RESULTS

We sold 91% of our available capacity for 2003 through state-mandated
auctions and contractually-mandated auctions. In our capacity auctions held
through February 2004, we have sold 85% and 24% of our available capacity for
2004 and 2005, respectively. As a result, we have contracted for approximately
$1 billion of total revenue with respect to our 2004 capacity and approximately
$533 million of total revenue with respect to our 2005 capacity. Our available
capacity equals our total net generating capacity less capacity withheld as
operating reserves and capacity that is subject to planned outages. Of the 2,988
MW of capacity that we have "mothballed", 2,062 MW were included in our
available capacity only for the months of May through September 2003. Reliant
Resources purchased 78% of our sold 2003 capacity and, through February 2004,
had purchased 79% and 68% of our sold 2004 and 2005 capacity, respectively. We
will hold additional auctions to sell our remaining available capacity for 2004
as well as capacity for subsequent years.

In 2003, the market-based prices established in our capacity auctions
continued to strengthen. Higher gas prices throughout 2003 positively influenced
the prices established in our recent capacity auctions. Generally, higher gas
prices increase the capacity prices for our base-load entitlements since natural
gas is the marginal fuel for facilities serving the ERCOT market during most
hours.

OPPORTUNITY SALES

In addition to our capacity auctions, from time to time we sell energy on a
short-term basis from the generating capacity we use as operating reserves. Any
significant unforeseen outage at our base-load or other facilities could
adversely impact revenues generated by these sales. We seek to maximize our
opportunity sales by seeking to optimize the dispatching of the various
facilities in our generating portfolio. For example, we can meet the gas-fired
auction products (intermediate, cyclic and peaking) with generation from our
lower cost base-load operating reserves when they are available, since
entitlements to our auction products convey no right to specific units. Thus,
the availability of our base-load capacity has a significant impact on the level
of these opportunity sales through the course of the year.

OUR GENERATION PORTFOLIO

OVERVIEW

We own 60 generating units at 11 electric power generation facilities
located in Texas. We also own a 30.8% interest in the South Texas Project, a
nuclear generating plant consisting of two 1,250 MW generating units. As of
December 31, 2003, the aggregate net generating capacity of our combined
portfolio of generation assets was 14,153 MW, which represents over 18% of the
total net generating capacity serving the ERCOT market.

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SUMMARY OF OUR GENERATION FACILITIES (AS OF DECEMBER 31, 2003)

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

(1) Net generating capacity equals gross maximum summer generating capability
less the electric energy consumed at the facility.

(2) Represents our 30.8% interest in the South Texas Project.

(3) All four units at P.H. Robinson are expected to be mothballed through April
2005.

(4) Webster Unit 3 (374 MW), T.H. Wharton Unit 2 (229 MW) and Deepwater Unit 7
(174 MW) are expected to be mothballed through at least April 2004.

MOTHBALLED FACILITIES

As of December 31, 2003, approximately 2,988 MW of our gas-fired generation
capacity was mothballed. We expect that 777 MW of this amount will remain
mothballed through April 2004 and the other 2,211 MW will remain mothballed
through April 2005. The decision to mothball these units was based on the lack
of demand for these types of units in our July and September 2003 capacity
auctions combined with high forecasted reserve margins in the ERCOT market.

BASE-LOAD AND INTERMEDIATE FACILITIES

W.A. Parish. Our W.A. Parish facility is the largest coal and gas-fired
power facility in the United States based on total MW of net generating
capacity. The facility consists of a coal-fired plant and a gas-fired plant each
located near Thompsons, Texas. The coal-fired plant includes four steam
generating units for base-load service with an aggregate net generating capacity
of 2,462 MW. Two of these units are 646 MW steam units that were placed in
commercial service in December 1977 and December 1978, respectively. The other
two units are 560 MW and 610 MW steam units that were placed in commercial
service in June 1980 and December 1982, respectively.

The gas-fired plant includes five generating units with an aggregate net
generating capacity of 1,191 MW. Two of these units are 174 MW steam units that
were placed in commercial service in June 1958 and December 1958, respectively.
These units were converted for daily cyclic operation and the life of the units
was extended in 1990 and 1991. The third unit at this plant is a 278 MW steam
unit that was placed in commercial service in March 1961. These three units
provide cyclic capacity. The fourth unit is a 552 MW steam unit for intermediate
service that was placed in service in June 1968. This plant also has a 13 MW gas

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turbine generator unit available for peaking and emergency start-up purposes
that was placed in service in July 1967.

Limestone. Our Limestone facility is a lignite-fired base-load facility
located approximately 120 miles northwest of Houston. This plant includes two
steam generating units with an aggregate net generating capacity of 1,602 MW.
The first unit is an 836 MW steam unit that was placed in commercial service in
December 1985. The second unit is a 766 MW steam unit that was placed in
commercial operation in December 1986.

Cedar Bayou. Our Cedar Bayou facility is a gas and oil-fired intermediate
facility located east of Baytown, Texas. This plant includes three generating
units with an aggregate net generating capacity of 2,258 MW. The units are 750
MW, 748 MW and 760 MW steam units that were placed in service in December 1970,
March 1972 and December 1974, respectively.

P.H. Robinson. Our P.H. Robinson facility is a gas-fired intermediate
facility located east of San Leon, Texas. This plant consists of four steam
generating units with an aggregate net generating capacity of 2,211 MW. Two of
the units are 461 MW units that were placed in service in June 1966 and April
1967, respectively. The third unit is a 552 MW unit that was placed in service
in December 1968. The fourth unit is a 737 MW unit that was placed in service in
December 1973. This plant is in mothball status through April 2005.

San Jacinto. Our San Jacinto facility is a 162 MW gas-fired intermediate
facility located in LaPorte, Texas that produces both steam and power. This
plant includes two cogeneration units and associated equipment. Both units began
commercial operation in April 1995. Each unit consists of a gas turbine that
drives an air-cooled generator with the exhaust from the gas turbine being sent
to a heat recovery steam generator.

CYCLIC AND PEAKING FACILITIES

T.H. Wharton. Our T. H. Wharton facility is a gas and oil-fired
intermediate, cyclic and peaking facility located in Houston. This plant
consists of 18 steam and gas turbine units with an aggregate net generating
capacity of 1,254 MW. This facility includes a 229 MW steam unit for cyclic
service that was placed in commercial operation in June 1960 and a 13 MW small
gas turbine unit for peaking service that was placed in commercial operation in
July 1967. In addition, six 57 MW gas turbines were placed in service at this
facility in July 1972. An additional two 57 MW gas turbines and two 104 MW steam
turbines were installed in August 1974 and were combined with the six gas
turbines already in service to develop two combined cycle units for intermediate
service. An additional six 58 MW gas turbines for peaking service were placed in
service in November 1975. The 229 MW steam unit is in mothball status through
April 2004.

S.R. Bertron. Our S.R. Bertron facility is a gas and oil-fired cyclic and
peaking facility located in Deer Park, Texas. This plant consists of four steam
electric generating units, one auxiliary boiler for cyclic operations, and two
gas turbine generators with an aggregate net generating capacity of 844 MW. The
first two units at this plant are 174 MW steam units for cyclic service that
commenced commercial operation in April 1956 and March 1958, respectively. Both
of these units underwent cyclic conversion and life extension in 1989 and 1990.
The third and fourth units at this plant are 230 MW steam units that commenced
commercial operation in April 1959 and March 1960, respectively. Both of these
units are capable of swinging from an overnight minimum of 40 MW to their rated
maximum capacity during peak load hours. This facility also has a 23 MW gas
turbine generator and a 13 MW gas turbine generator. Both of these units provide
peaking service and commenced commercial operation in July 1967.

Greens Bayou. Our Greens Bayou facility is a gas and oil-fired cyclic and
peaking facility located northeast of Houston. This plant consists of one 406 MW
steam turbine unit, three 54 MW gas turbine units and three 64 MW gas turbine
units and has an aggregate net generating capacity of 760 MW. The 406 MW steam
turbine unit provides cyclic service and was placed in commercial service in
June 1973. The six gas turbine units provide peaking service and were placed in
commercial service in December 1976.

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Webster. Our Webster facility is a gas-fired cyclic and peaking facility
located southeast of Houston between the towns of Webster and League City. This
plant has two units with an aggregate net generating capacity of 387 MW. One of
these units is a 374 MW steam unit for cyclic service that was placed in service
in May 1965 and the other is a 13 MW gas turbine for peaking service that was
placed in commercial operation in July 1967. The 374 MW steam unit is in
mothball status through April 2004.

Deepwater. Our Deepwater facility is a gas-fired cyclic facility located
in southeastern Harris County, Texas. This facility consists of a 174 MW steam
unit that commenced commercial operation in 1955 and underwent a life extension
and conversion for cyclic operation in 1992. This unit is in mothball status
through April 2004.

H.O. Clarke. Our H.O. Clarke facility is a gas-fired peaking facility
located in Houston that began operation in 1943. This plant currently consists
of six simple-cycle air-cooled gas turbine generating units with an aggregate
net generating capacity of 78 MW that were placed in service in June 1968.

SOUTH TEXAS PROJECT

General. The South Texas Project is one of the largest nuclear powered
generating facilities in the United States based on total MW of net generating
capacity. This facility is located near Bay City, Texas and consists of two
1,250 MW generating units, the first of which commenced operation in August 1988
and the second in June 1989. We own a 30.8% interest in the South Texas Project
and bear a corresponding 30.8% share of the capital and operating costs
associated with the project. The South Texas Project is owned as a tenancy in
common among us and three other co-owners. Each co-owner retains its undivided
ownership interest in the two nuclear-fueled generating units and the electrical
output from those units. We and the other three co-owners organized STP Nuclear
Operating Company (STPNOC) to operate and maintain the South Texas Project.
STPNOC is managed by a board of directors composed of one director appointed by
each of the co-owners, along with the chief executive officer of STPNOC.

The two South Texas Project generating units operate under licenses granted
by the Nuclear Regulatory Commission (NRC) that expire in 2027 and 2028. These
licenses could potentially be extended for additional twenty-year terms if the
project satisfies NRC requirements.

Right of First Refusal. In early March 2004, one of the other co-owners of
the South Texas Project announced it had entered into an agreement to sell its
25.2% ownership interest for approximately $332.6 million, subject to certain
closing adjustments. As a result, under the terms of the ownership arrangements
for the South Texas Project, we have the right of first refusal to purchase our
proportionate share of the interest being sold on the same terms as the third
party purchaser, but we must give notice of our election within ninety days.

Decommissioning Trusts. CenterPoint Houston has been authorized to collect
$2.9 million per year from customers using its transmission and distribution
services and is obligated to deposit the amount collected into external trusts
created to fund our 30.8% share of the decommissioning costs for the South Texas
Project. As of December 31, 2003, the fair market value of the investments in
the external trusts established to fund our 30.8% interest was $189 million.

In July 1999, an outside consultant estimated our 30.8% share of the
decommissioning costs to be approximately $363 million in 1998 dollars. The
consultant's calculation of decommissioning costs for financial planning
purposes used the "DECON" methodology, one of the three alternatives acceptable
to the NRC, and assumed deactivation of the project's two generating units upon
the expiration of their 40-year operating licenses. The DECON methodology
involves removal of all radioactive material from the site following permanent
shutdown. The facility operator may then have unrestricted use of the site with
no further requirement for a license. The consultant's calculation also assumed
that the remainder of the plant systems and structures on site, not previously
removed in support of license termination, are dismantled and the site restored.

The owners of the South Texas Project must provide a report on the status
of decommissioning funding to the NRC every two years. The report compares
external trust funding levels to minimum decommissioning
8

amounts calculated in accordance with NRC requirements. We first determine our
decommissioning cost estimate by escalating the NRC's estimated decommissioning
cost of $105 million per unit, expressed in 1986 dollars, for the effects of
inflation between 1986 and the recent year-end and then multiplying by 30.8% to
reflect our share of each unit of the South Texas Project. We then use this
estimate to determine the minimum required level of funding as of the most
recent year-end. The calculation of the NRC minimum funding level reflects that
funding of the external trusts occurs over the operating lives of the generating
units. Therefore, the minimum funding level is generally less than the estimated
decommissioning cost. The last report was submitted to the NRC in March 2003 and
showed that, as of December 31, 2002, the aggregate NRC minimum funding level
was $70.2 million. While the trusts' funding levels have historically exceeded
minimum NRC funding requirements, we cannot assure you that the amounts held in
trust will be adequate to cover the actual decommissioning costs of the South
Texas Project. These 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.

The investment of the funds in the external trusts is managed in accordance
with applicable laws and regulations and by a committee composed of our
representatives and representatives of CenterPoint Energy. Pursuant to the terms
of an agreement between Reliant Energy and Reliant Resources and the applicable
NRC regulations, the responsibility for the decommissioning trusts transferred
to us at the time of Reliant Energy's corporate restructuring. In the event that
funds from the trusts are inadequate to decommission the facilities, CenterPoint
Houston will be required to collect through rates or other authorized charges
all additional amounts required to fund our obligations relating to the
decommissioning of the South Texas Project. Following the completion of the
decommissioning, if surplus funds remain in the decommissioning trusts, the
excess will be refunded to the rate payers of CenterPoint Houston or its
successor.

TECHNICAL SERVICES AND SUPPORT FACILITIES

We have a central support facility that we use to support our generation
facilities that we refer to as our "EDC facility." This facility includes office
space, a maintenance shop, a chemical lab, a warehouse facility and a fleet
maintenance garage. Reliant Resources leases a portion of this facility from us.

Under a technical services agreement, Reliant Resources is obligated to
provide engineering and technical support services and certain environmental,
safety and industrial health services to support the operation and maintenance
of our facilities. We have notified Reliant Resources that its obligation to
provide these support services will be terminated effective May 31, 2004. Under
the agreement, Reliant Resources is also obligated to provide systems,
technical, programming and consulting support services and hardware maintenance,
excluding plant-specific hardware, necessary to provide generation system
planning, dispatch, and settlement and communication with the ERCOT ISO. A
project is currently underway to identify manpower requirements, evaluate
systems alternatives, define costs and develop time lines for replacement of
those services considered necessary under the current overall technical services
agreement with Reliant Resources. We paid Reliant Resources approximately $28.4
million for providing these services during 2003. The technical services
agreement will terminate upon the sale of CenterPoint Energy's interest in Texas
Genco.

FUEL SUPPLIES

We rely primarily on natural gas, coal, lignite and uranium to fuel our
generation facilities. The fuel mix of our generating portfolio, based on actual
fuel usage during 2003, was approximately 52% coal and lignite, 21% natural gas,
and 27% nuclear for the year 2003. As of December 31, 2003, the fuel mix of our
generating portfolio based on the capacity of our facilities including
mothballed capacity was approximately 66% natural gas, 29% coal and lignite and
5% nuclear. Based on our current assumptions regarding the cost and availability
of fuel, plant operation schedules, load growth, load management and the impact
of environmental regulations, we do not expect the mix of fuel used by our
generating portfolio will vary materially during 2004 from 2003. We
substantially collect the underlying cost of fuel through energy payments. As a
result of new air emissions

9

standards imposed by federal and state law, we anticipate having additional
costs for certain environmental equipment in 2004 and subsequent years.

NATURAL GAS

We have long-term natural gas supply contracts with several suppliers.
Substantially all of our long-term contracts contain pricing provisions based on
fluctuating spot market prices. In 2003, we purchased approximately 50% of our
natural gas requirements under these long-term contracts. We purchased the
remaining 50% of our natural gas requirements in 2003 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. Our
natural gas consumption and cost information for 2003 was as follows:

2003 average daily consumption.............................. 311 Bbtu(1)
2003 peak daily consumption................................. 942 Bbtu
2003 average cost of natural gas............................ $5.59 per MMBtu(2)

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

(1) Billion British thermal units, or "Bbtu."

(2) Compared to $3.32 per million British thermal units, or "MMBtu," in 2002 and
$4.28 per MMBtu in 2001.

We lease gas storage facilities capable of storing 6.3 billion cubic feet
of natural gas, of which 4.2 billion cubic feet is working capacity. We use
these storage facilities to assist us in:

- managing the volatility of the gas requirements of our generating
facilities;

- meeting the gas requirements of our generating facilities during periods
of inadequate gas supplies; and

- managing our gas-related costs.

Our natural gas requirements are generally more volatile than our other
fuel requirements because we use natural gas to fuel our intermediate, cyclic
and peaking facilities and other more economical fuels to fuel our base-load
facilities. Since our intermediate and peaking facilities are dispatched to meet
the variations of demand for electricity, our gas requirements are highly
variable, on both an hour-to-hour and day-to-day basis. Although natural gas
supplies have been sufficient in recent years to supply our generating
portfolio, 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.

COAL AND LIGNITE

In 2003, 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 scheduled to expire in 2010 and 2011.
The price for coal under the first contract was tied to spot market prices in
2003. The price for coal under the second contract was at a level approximately
three times greater than the spot market prices for coal as of December 31,
2003. The second contract does not contemplate future prices being tied to spot
market prices. The terms of this contract result from the market conditions in
effect during the 1970's when the contract was entered into, including shortages
of natural gas supplies, increased demand for low sulfur coal as a result of new
environmental regulations and uncertainty regarding the future availability of
long-term sources of coal supply. We purchase our remaining coal requirements
for our W.A. Parish facility under short-term contracts. We have long-term rail
transportation contracts with Burlington Northern Santa Fe Railroad and the
Union Pacific Railroad Company to transport coal to our W.A. Parish facility.
Despite the higher coal prices under these long-term contracts, our fuel costs
associated with producing energy from our coal-fired facilities are, based on
recent natural gas prices, significantly lower than the fuel costs associated
with producing energy from our gas-fired facilities.

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We obtain the lignite used to fuel the two generating units of our
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. Mining operations are conducted by the owner of the remaining lignite
reserves. In the past, we have obtained our lignite requirements under a
long-term contract on a cost-plus basis. Since July 2002, we have obtained our
lignite requirements under an amended long-term contract with the owner/operator
at a fixed price determined annually that is expected to result in a cost of
generation at the Limestone facility equivalent to the cost of generating with
low sulfur Western coal. We expect the lignite reserves will be sufficient to
provide all of the lignite requirements of this facility through 2015.

We used a blend of lignite and Wyoming coal to fuel our Limestone facility
in 2003 as a component of our oxides of nitrogen (NOx) control strategy. A fuel
unloading and handling system was installed at the Limestone facility to
accommodate the delivery of Wyoming coal. We expect that we will obtain Wyoming
coal through spot and long-term market priced contracts. Our Limestone facility
is connected with the Burlington Northern Santa Fe Railroad.

NUCLEAR

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
party to a number of contracts covering a portion of the fuel requirements 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, these contracts have varying expiration
dates, and most are short to medium term (less than seven years). We believe
that sufficient capacity for nuclear fuel supplies and processing exists to
permit normal operations of the South Texas Project's nuclear powered generating
units.

FUEL PIPELINE

We own a 90-mile fuel pipeline that can transport either fuel oil or
natural gas (86 miles oil or gas and 4 miles gas only). As part of our system,
we own over six million barrels of oil storage capacity that can supply fuel oil
to our Cedar Bayou, Greens Bayou, S.R. Bertron and T.H. Wharton plants. For
natural gas supply, our pipeline is connected to six of our generation
facilities and is interconnected with several of our suppliers. Our pipeline
provides us with added flexibility in managing the fuel supply requirements of
our generation facilities.

JOINT OPERATING AGREEMENT WITH CITY OF SAN ANTONIO

We have a joint operating agreement with the City Public Service Board of
San Antonio (CPS) to jointly dispatch our portfolio of generating units with
CPS' portfolio of 4,823 MW of generating capacity as a joint operating system to
meet our combined obligations. The combined system includes approximately 19,000
MW of generating capacity and provides us with added economies of scale and
production cost savings. A large portion of the benefit of joint operations is
due to San Antonio's significant amount of capacity at its coal-fired generation
facilities. We share the fuel cost savings realized under the agreement with the
City of San Antonio. We currently share the cost savings benefits equally with
CPS. The current agreement with CPS expires in 2009. Both parties are permitted
to sell their capacity outside of the joint operating system if it is
economically prudent to do so, in which case the parties would lose the
agreement's cost savings benefits with respect to those sales. The capacity of
CPS' generating facilities covered by the joint operating agreement is not
included in the capacity auctions described under "Capacity Auctions and
Opportunity Sales" above.

COMPETITION

The ERCOT market is highly competitive. We have approximately 80
competitors that include generation companies affiliated with Texas-based
utilities, independent power producers, municipal or co-operative generators and
wholesale power marketers. These competitors compete with each other and us by

11

buying and selling wholesale power in the ERCOT market, entering into bilateral
contracts and/or selling to aggregated retail customers.

As of December 31, 2003, our facilities provided over 18% of the aggregate
net generating capacity serving the ERCOT market. Our competition is based
primarily on price but we also may compete based on product flexibility. A
number of our competitors are building efficient, combined cycle power plants
that are generally not able to provide the operational flexibility, ancillary
services and fuel risk mitigation that our large diversified portfolio of
generating facilities can provide. In addition, we believe that there may be
significant excess generating capacity constructed in the ERCOT market over the
next several years. This overbuilding could result in lower prices for wholesale
power in the ERCOT market. For more information regarding this trend and other
competitive factors in the ERCOT market, please read "The ERCOT Market" above
and "Risk Factors -- Market Risks" below.

CUSTOMERS

Since January 1, 2002, we have sold power to wholesale purchasers,
including retail electric providers, at unregulated rates through our capacity
auctions. In addition to retail electric providers, our customers in the ERCOT
market include municipal utilities, electric co-operatives, power trading
organizations and other power generating companies. We are also a significant
provider to the ancillary services market operated by the ERCOT ISO. Sales to
subsidiaries of Reliant Resources represented approximately 71% of our total
revenues in 2003. We have been granted a security interest in accounts
receivable and/or securitization notes associated with the accounts receivable
of certain subsidiaries of Reliant Resources to secure up to $250 million in
purchase obligations.

INSURANCE

GENERAL

We carry insurance coverage consistent with companies engaged in similar
commercial operations with similar properties. Our insurance coverage includes:

- general liability insurance, covering liabilities to third parties for
bodily injury and property damage resulting from our operations;

- automobile liability insurance, for all owned, non-owned and hired
vehicles, covering liabilities to third parties for bodily injury and
property damage; and

- property insurance, subject to replacement cost of insured real and
personal property, including coverage for boiler and machinery
breakdowns, earthquake and flood damage, subject to certain sublimits.

We also maintain substantial excess liability insurance coverage above the
established primary limits for general liability and automobile liability
insurance. Limits and deductibles are comparable to those carried by other
electric generation companies of similar size. However, our insurance policies
are subject to certain limits and deductibles and do not include business
interruption coverage. Adequate insurance coverage in the future may be more
expensive or may not be available in the future on commercially reasonable
terms. Also, the insurance proceeds received for any loss of or any damage to
any of our generation facilities may not be sufficient to restore the loss or
damage without negative impact on our financial condition, results of operations
and cash flows.

NUCLEAR

We 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.

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Under the Price Anderson Act, the maximum liability to the public of owners
of nuclear power plants was $10.6 billion as of December 31, 2003. Owners are
required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. We and the other owners of the South Texas
Project currently maintain the required nuclear liability insurance and
participate in the industry retrospective rating plan under which the owners of
the South Texas Project are subject to maximum retrospective assessments in the
aggregate per incident of up to $100.6 million per reactor. The owners are
jointly and severally liable at a rate not to exceed $10 million per incident
per year. In addition, the security procedures at this facility have been
enhanced to provide additional protection against terrorist attacks.

We cannot assure you that all potential losses or liabilities associated
with the South Texas Project 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 adverse effect on our financial condition,
results of operations and cash flows.

BACKGROUND OF THE DISTRIBUTION OF TEXAS GENCO SHARES

Under the Texas electric restructuring law, transmission and distribution
utilities whose generation assets were "unbundled" pursuant to the law,
including CenterPoint Houston, are entitled to recover their "stranded costs"
associated with those assets. The Texas electric restructuring law defines
stranded costs as the positive excess of the regulatory net book value of the
utility's unbundled generation assets over the market value of those assets,
after taking specified factors into account. The law allows alternate methods
for establishing a market value for generation assets, including outright sale,
full or partial stock market valuation and asset exchanges. Under Reliant
Energy's business separation plan, Reliant Energy proposed that the fair market
value of our generating assets would be determined using the partial stock
market valuation method. CenterPoint Energy distributed 19% of Texas Genco's
outstanding shares of common stock to its shareholders in order to establish a
public market value for our shares that will be used in 2004 to calculate how
much CenterPoint Houston will be able to recover as stranded costs and to comply
with CenterPoint Energy's contractual obligations to Reliant Resources.

Beginning in January 2004, on a schedule established by the Texas Utility
Commission, investor-owned utilities in Texas may file to commence true-up
proceedings. CenterPoint Houston will make the filing to initiate its final
true-up proceeding on March 31, 2004. One of the purposes of the true-up
proceeding for CenterPoint Energy will be to quantify the amount of stranded
costs associated with our generation assets. In the proceeding, the regulatory
net book value of our generating assets will be compared to the market value
based on the partial stock valuation method. The resulting difference, if
positive, is stranded cost that will be recoverable by CenterPoint Houston
either through a transition charge, which is a non-bypassable charge, or through
a securitization of such cost. Texas Genco is not entitled to receive any
payment or other benefits in connection with CenterPoint Houston's true-up
proceeding. In the true-up proceeding, the market value of our assets will be
based on the average daily closing price of Texas Genco's common stock on The
New York Stock Exchange for the 30 consecutive trading days chosen by the Texas
Utility Commission out of the last 120 days immediately preceding the true-up
filing, plus a control premium, up to a maximum of 10%, to the extent included
in the valuation determination made by the Texas Utility Commission.

REGULATION

We are subject to regulation by various federal, state and local
governmental agencies, including the regulations described below and under "The
ERCOT Market," "Capacity Auctions and Opportunity Sales -- State-mandated
Auctions" and "Environmental Matters -- Regulation" below.

FEDERAL ENERGY REGULATORY COMMISSION

In October 2003, the FERC granted exempt wholesale generator status to
Texas Genco, LP, our wholly owned subsidiary that owns and operates our electric
generating plants. As a result, we are exempt from substantially all provisions
of the 1935 Act as long as we remain an exempt wholesale generator.

13

NUCLEAR REGULATORY COMMISSION

We are subject to regulation by the NRC with respect to the operation of
the South Texas Project. This regulation involves testing, evaluation and
modification of all aspects of plant operation in light of NRC safety and
environmental requirements. Continuous demonstrations to the NRC that plant
operations meet applicable requirements are also required. The NRC has the
ultimate authority to determine whether any nuclear powered generating unit may
operate.

We and the other owners of the South Texas Project are required by NRC
regulations to estimate from time to time the amounts required to decommission
that nuclear generating facility and are required to maintain funds to satisfy
that obligation when the plant ultimately is decommissioned. CenterPoint Houston
currently collects through its electric rates amounts calculated to provide
sufficient funds at the time of decommissioning to discharge these obligations.
Funds collected are deposited into nuclear decommissioning trusts. The
beneficial ownership of the decommissioning trusts is held by us, as a licensee
of the facility. While 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. In the event that funds from the trusts are inadequate to decommission
the facilities, CenterPoint Houston will be required to collect through rates or
other authorized charges additional amounts required to fund our obligations
relating to the decommissioning of the South Texas Project. For additional
information regarding the decommissioning trust, please read "Our Generation
Portfolio -- South Texas Project -- Decommissioning Trusts" above.

ENVIRONMENTAL MATTERS

REGULATION

We are subject to a number of federal, state and local laws and regulations
relating to the protection of the environment and the safety and health of
company personnel and the public. These requirements relate to a broad range of
our activities, including:

- the discharge of pollutants into the air, water and soil;

- the identification, generation, storage, handling, transportation,
disposal, record keeping, labeling and reporting of, and the emergency
response in connection with, hazardous and toxic materials and wastes,
including asbestos, associated with our operations;

- noise emissions from our facilities; and

- safety and health standards, practices and procedures that apply to the
workplace and the operation of our facilities.

In order to comply with these requirements, we may need to spend
substantial amounts and devote other resources from time to time to:

- construct or acquire new equipment;

- acquire permits and/or marketable allowance or other emission credits for
facility operations;

- modify or replace existing and proposed equipment; and

- clean up or decommission waste disposal areas, fuel storage and
management facilities, and other locations and facilities, including
generation facilities.

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.

14

Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (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.

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. In furtherance of the Act's requirements, standards for NOx
emissions, a product of the combustion process associated with power generation,
have been finalized by the Texas Commission on Environmental Quality ("TCEQ").
These TCEQ standards, as well as provisions of the Texas electric restructuring
law, require substantial reductions in NOx emissions from electric generating
units. We are currently installing cost-effective controls at our generating
plants to comply with these requirements. As of December 31, 2003, we have
invested $664 million for NOx emissions controls and are planning to make
additional expenditures of $131 million through 2007. Further revisions to these
NOx standards may result from the TCEQ's future rules, expected by 2007,
implementing more stringent federal eight-hour ozone standards.

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. In 2002, President Bush withdrew the United
States' support for the Kyoto Protocol while endorsing voluntary greenhouse gas
reduction measures. Congress has also explored a number of other alternatives
for regulating domestic greenhouse gas emissions. If the country re-enters and
the United States Senate ultimately ratifies the Kyoto Protocol and/or if the
United States Congress adopts other measures for the control of greenhouse
gases, any resulting limitations on power plant carbon dioxide emissions could
have a material adverse impact on all fossil fuel-fired electric generating
facilities, including those belonging to us.

In July 2002, the White House sent to the United States Congress a Bill
proposing the Clear Skies Act, which is designed to achieve long-term reductions
of multiple pollutants produced from fossil fuel-fired power plants. If enacted,
the Clear Skies Act would target reductions averaging 70% for sulfur dioxide
(SO(2)), NOx and mercury emissions and would create a gradually imposed
market-based compliance program that would come into effect initially in 2008
with full compliance required by 2018. Fossil fuel-fired power plants owned by
companies such as us would be affected by the adoption of this program, or other
legislation currently pending in Congress addressing similar issues. To comply
with such programs, we and other regulated entities could pursue a variety of
strategies, including the installation of pollution controls, purchase of
emission allowances, or the curtailment of operations. To date, Congress has not
enacted the Clear Skies Act.

In response to Congressional inaction on the proposed Clear Skies Act, the
Environmental Protection Agency (EPA) in December 2003 proposed the Interstate
Air Quality Rule, which would require reductions in NOx and SO(2) similar to
those found in the Clear Skies Act. However, in contrast to the Clear Skies Act,
the Interstate Air Quality Rule affects emissions in 29 states in the eastern
U.S., including Texas. As with the Clear Skies Act, emissions are reduced in two
phases, and the reduction targets are similar, but are effective in 2010 and
2015 for both NOx and SO(2). EPA has announced an intent to finalize these rules
in late 2004 or early 2005.

In December 2003, EPA proposed two alternatives for regulating emissions of
mercury from coal-fired power plants in the U.S. A final rulemaking is scheduled
to be adopted in December 2004. Under the first option, the EPA would set
Maximum Achievable Control Technology (MACT) standards under Section 112 of the
Clean Air Act, which would require mercury reductions on a facility-by-facility
basis regardless of cost. The MACT standard requires reductions to be achieved
by 2008, although it is possible that this compliance date will be delayed. The
second option would regulate coal-fired power plants under Section 111 of the
Clean

15

Air Act. Under this option, similar mercury reductions would be achieved on a
national scale through a cap-and-trade program, allowing reductions to be made
at the most economical locations, and not requiring reductions on a
facility-by-facility basis. The MACT standard would require a reduction of about
30% from coal-fired facilities, which will require the installation of control
equipment. The cap-and-trade rule would require deeper reductions, but may be
more economical because it allows trading of emissions among facilities. The
mercury cap-and-trade rule would be accomplished in two phases, in 2010 and
2015, with reduction levels set at approximately 50% and 70%, respectively. The
cost of complying with the final rules is not yet known but is likely to be
material.

In addition to mercury control from coal-fired boilers, the MACT rule, if
adopted, would require the control of nickel emissions from oil-fired
facilities. At this point, the impact of this proposal is uncertain, but is not
expected to significantly affect our operations.

The EPA has also issued MACT standards for sources other than boilers used
for power generation. The MACT rule for combustion turbines was issued in August
2003 and there is no impact on our existing facilities. The MACT rulemaking for
engines and industrial boilers was issued in February 2004. These rules are not
expected to have a significant impact on Texas Genco's operations.

WATER

On February 16, 2004, the EPA signed final rules under Section 316(b) of
the Clean Water Act relating to the design and operation of existing cooling
water intake structures. The requirements to achieve compliance with this rule
are subject to various factors, including the results of anticipated litigation,
but we currently do not expect any capital expenditures required for compliance
to be material.

The EPA and State of Texas periodically modify water quality standards and,
where necessary, initiate total maximum daily load allocations for water bodies
not meeting those standards. Such actions could cause our facilities to incur
significant costs to comply with revised discharge permit limitations.

NUCLEAR WASTE

Under the U.S. Nuclear Waste Policy Act of 1982, the federal government was
to create a federal repository for spent nuclear fuel produced by nuclear plants
like the South Texas Project. Also pursuant to that legislation a special
assessment has been imposed on those nuclear plants to pay for the facility.
Consistent with the Act, owners of nuclear facilities, including us and the
other owners of the South Texas Project, entered into contracts setting out the
obligations of the owners and U.S. Department of Energy (DOE). Since 1998, DOE
has been in default on its obligations to begin moving spent nuclear fuel from
reactors to the federal repository (which still is not completed). On January
28, 2004, we and the other owners of the South Texas Project, along with owners
of other nuclear plants, filed a breach of contract suit against DOE in order to
protect against the running of a statute of limitations.

ASBESTOS

As a result of their age, many of our facilities contain significant
amounts of asbestos insulation, other asbestos-containing materials and
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.

Our facilities are the subject of 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 third
party workers who participated in construction of various industrial facilities,
including power plants, and some of the claimants have worked at locations owned
by us. We anticipate that additional claims

16

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.

EMPLOYEES

As of December 31, 2003, we employed 1,511 people. Of these employees,
1,030 were covered by a collective bargaining agreement with the International
Brotherhood of Electrical Workers Local 66 that expired in September 2003. Our
bargaining unit employees have continued to work without interruption and we
have not had any work interruptions since 1976. We continue to have a good
relationship with the bargaining unit and we are actively negotiating to obtain
a new agreement in 2004.

EXECUTIVE OFFICERS
(AS OF MARCH 1, 2004)

DAVID M. MCCLANAHAN is the Chairman of our board of directors. Mr.
McClanahan has also served on the board of directors and as the President and
Chief Executive Officer of CenterPoint Energy since September 2002. He served as
the Vice Chairman of Reliant Energy from October 2000 to September 2002 and as
President and Chief Operating Officer of Reliant Energy's Delivery Group since
1999. He also served as the President and Chief Operating Officer of Reliant
Energy HL&P from 1997 to 1999. He has served in various other executive
capacities with CenterPoint Energy since 1986. He previously served as Chairman
of the Board of Directors of ERCOT and Chairman of the Board of the University
of St. Thomas. He currently serves on the boards of the Edison Electric
Institute and the American Gas Association.

DAVID G. TEES is our President and Chief Executive Officer and a member of
our board of directors. He served as Senior Vice President, Generation
Operations of Reliant Energy from 1998 through August 2002. He also served as
Vice President of Energy Production of Reliant Energy HL&P from 1986 through
1998. Mr. Tees has also served on the executive committee of the Edison Electric
Institute Energy Supply Subcommittee and presently represents CenterPoint Energy
as a Research Advisory Committee Member of the Electric Power Research Institute
and is the Chairman of the Board of the STP Nuclear Operating Company.

SCOTT E. ROZZELL is our Executive Vice President, General Counsel and
Corporate Secretary and a member of our board of directors. Mr. Rozzell has also
served as the Executive Vice President, General Counsel and Corporate Secretary
of CenterPoint Energy since September 2002. He served as Executive Vice
President and General Counsel of the Delivery Group of Reliant Energy from March
2001 to September 2002. Prior to joining Reliant Energy, Mr. Rozzell was a
senior partner in the law firm of Baker Botts L.L.P.

GARY L. WHITLOCK is our Executive Vice President and Chief Financial
Officer and a member of our board of directors. Mr. Whitlock has also served as
the Executive Vice President and Chief Financial Officer of CenterPoint Energy
since September 2002. He served as Executive Vice President and Chief Financial
Officer of the Delivery Group of Reliant Energy from July 2001 to September
2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial
Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company from 1998
to 2001.

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JAMES S. BRIAN is our Senior Vice President and Chief Accounting Officer.
Mr. Brian has also served as the Senior Vice President and Chief Accounting
Officer of CenterPoint Energy since August 2002. He served as Senior Vice
President, Finance and Administration of the Delivery Group of Reliant Energy
from 1999 to August 2002, and as Vice President and Chief Financial Officer of
Reliant Energy HL&P from 1997 to 1999. He has served in various executive
capacities with Reliant Energy since 1983.

JOSEPH B. MCGOLDRICK is our Corporate Vice President, Strategic Planning.
Mr. McGoldrick has also served as Corporate Vice President, Strategic Planning
of CenterPoint Energy since September 2002. He served as Corporate Vice
President, Strategic Planning of the Delivery Group of Reliant Energy from
November 2001 to August 2002. He served as Senior Vice President, Finance &
Administration for Reliant Energy Retail from 2000 to 2001. He has served in
various executive capacities with Reliant Energy since 1993.

RISK FACTORS

MARKET RISKS

OUR REVENUES AND RESULTS OF OPERATIONS ARE IMPACTED BY MARKET RISKS THAT ARE
BEYOND OUR CONTROL.

We sell electric generation capacity, energy and ancillary services in the
ERCOT market. Under the Texas electric restructuring law, we and other power
generators in Texas are not subject to traditional cost-based regulation and
therefore may sell electric generation capacity, energy and ancillary services
to wholesale purchasers at prices determined by the market. As a result, we are
not guaranteed any rate of return on our capital investments through mandated
rates, and our revenues and results of operations depend, in large part, upon
prevailing market prices for electricity in the ERCOT market. Market prices for
electricity, generation capacity, energy and ancillary services may fluctuate
substantially. Our gross margins are primarily derived from the sale of capacity
entitlements associated with our large, solid fuel base-load generating units,
including our Limestone and W. A. Parish facilities and our interest in the
South Texas Project. The gross margins generated from payments associated with
the capacity of these units are directly impacted by natural gas prices. Since
the fuel costs for our base-load units are largely fixed under long-term
contracts, they are generally not subject to significant daily and monthly
fluctuations. Because natural gas is the marginal fuel for facilities serving
the ERCOT market during most hours, gas prices have a significant influence on
the price of electric power. As a result, the price customers are willing to pay
for entitlements to our solid fuel-fired base-load capacity generally rises and
falls with natural gas prices.

Market prices in the ERCOT market may also fluctuate substantially due to
other factors. Such fluctuations may occur over relatively short periods of
time. Volatility in market prices may result from:

- oversupply or undersupply of generation capacity;

- power transmission or fuel transportation constraints or inefficiencies;

- weather conditions;

- seasonality;

- availability and market prices for natural gas, crude oil and refined
products, coal, lignite, enriched uranium and uranium fuels;

- changes in electricity usage;

- additional supplies of electricity from existing competitors or new
market entrants as a result of the development of new generation
facilities or additional transmission capacity;

- illiquidity in the ERCOT market;

- availability of competitively priced alternative energy sources;

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

- federal and state energy and environmental regulation and legislation.

THERE IS CURRENTLY A SURPLUS OF GENERATING CAPACITY IN THE ERCOT MARKET AND WE
EXPECT THE MARKET FOR WHOLESALE POWER TO BE HIGHLY COMPETITIVE.

The reserve margin in the ERCOT market has exceeded 30% since 2001, and the
Texas Utility Commission and the ERCOT ISO have forecasted the reserve margin
for 2004 to continue to exceed 30%. The commencement of commercial operation of
new facilities in the ERCOT market has increased and will continue to increase
the competitiveness of the wholesale power market, which could have a material
adverse effect on our business, results of operations, financial condition and
cash flows and the market value of our assets.

Our competitors include generation companies affiliated with Texas-based
utilities, independent power producers, municipal and co-operative generators
and wholesale power marketers. The unbundling of vertically integrated utilities
into separate generation, transmission and distribution and retail businesses
pursuant to the Texas electric restructuring law could result in a significant
number of additional competitors participating in the ERCOT market. Some of our
competitors may have greater financial resources, lower cost structures, more
effective risk management policies and procedures, greater ability to incur
losses, greater potential for profitability from ancillary services, or greater
flexibility in the timing of their sale of generating capacity and ancillary
services than we do.

WE ARE SUBJECT TO OPERATIONAL AND MARKET RISKS ASSOCIATED WITH OUR CAPACITY
AUCTIONS.

We have sold entitlements to a significant portion of our available 2004
and 2005 generating capacity in our capacity auctions held to date. Although our
obligation to conduct contractually-mandated auctions terminated in January
2004, we currently remain obligated to sell 15% of our installed generation
capacity and related ancillary services pursuant to state-mandated auctions and
we expect to conduct future capacity auctions with respect to all or a part of
our remaining capacity from time to time. In these auctions, we sell firm
entitlements on a forward basis to capacity and ancillary services dispatched
within specified operational constraints. Although we have reserved a portion of
our aggregate net generation capacity from our capacity auctions for planned or
forced outages at our facilities, unanticipated plant outages or other problems
with our generation facilities could result in our firm capacity and ancillary
services commitments exceeding our available generation capacity. As a result,
an unexpected outage at one of our lower cost facilities could require us to run
one of our higher cost plants or obtain replacement power from third parties in
the open market in order to satisfy our obligations even though the energy
payments for the dispatched power are based on the cost of our lower-cost
facilities.

OPERATING RISKS

THE OPERATION OF OUR POWER GENERATION FACILITIES INVOLVES RISKS THAT COULD
ADVERSELY AFFECT OUR REVENUES, COSTS, RESULTS OF OPERATIONS AND CASH FLOWS.

General. We are subject to various risks associated with operating our
power generation facilities, any of which could adversely affect our revenues,
costs, results of operations, financial condition and cash flows. These risks
include:

- operating performance below expected levels of output or efficiency;

- breakdown or failure of equipment or processes;

- disruptions in the transmission of electricity;

- shortages of equipment, material or labor;

- labor disputes;

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- fuel supply interruptions;

- limitations that may be imposed by regulatory requirements, including,
among others, environmental standards;

- limitations imposed by the ERCOT ISO;

- violations of permit limitations;

- operator error; and

- catastrophic events such as fires, hurricanes, explosions, floods,
terrorist attacks or other similar occurrences.

A significant portion of our facilities was constructed many years ago.
Older generation equipment, even if maintained in accordance with good
engineering practices, may require significant capital expenditures to keep it
operating at high efficiency and to meet regulatory requirements. This equipment
is also likely to require periodic upgrading and improvement. Any unexpected
failure to produce power, including failure caused by breakdown or forced
outage, could result in reduced earnings.

The cost of repairing damage to our facilities due to storms, natural
disasters, wars, terrorist acts and other catastrophic events may adversely
impact our results of operations, financial condition and cash flows. The
occurrence or risk of occurrence of future terrorist activity may impact our
results of operations and financial condition in unpredictable ways. These
actions could also result in adverse changes in the insurance markets and
disruptions of power and fuel markets. In addition, our power generation
facilities and fuel supply 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 and margins and limit our
future growth prospects. Also, these risks could cause instability in the
financial markets and adversely affect our ability to access capital.

We employ experienced personnel to maintain and operate our facilities and
carry insurance to mitigate the effects of some of the operating risks described
above. Our insurance policies, however, are subject to certain limits and
deductibles and do not include business interruption coverage. Should one or
more of the events described above occur, revenues from our operations may be
significantly reduced or our costs of operations may significantly increase.

In December 2003, one of the three auxiliary standby diesel generators for
Unit 2 at the South Texas Project failed during a routine test. The NRC allowed
continued operation of Unit 2 while repairs to the generator were made. Repairs
are expected to be completed before the end of a scheduled refueling outage on
the unit in the spring of 2004. Should Unit 2 experience an unplanned shutdown
prior to its scheduled outage, there is a risk that the NRC would not permit
restarting the unit until the diesel generator was fully repaired. Our share of
the ultimate cost of repairs to the diesel generator is estimated to be
approximately $5 million and is expected to be substantially covered by
insurance.

WE RELY ON POWER TRANSMISSION FACILITIES THAT WE DO NOT OWN OR CONTROL AND ARE
SUBJECT TO TRANSMISSION CONSTRAINTS WITHIN THE ERCOT MARKET. IF THESE
FACILITIES FAIL TO PROVIDE US WITH ADEQUATE TRANSMISSION CAPACITY, WE MAY NOT
BE ABLE TO DELIVER WHOLESALE ELECTRIC POWER TO OUR CUSTOMERS AND WE MAY INCUR
ADDITIONAL COSTS.

We depend on transmission and distribution facilities owned and operated by
our affiliate, CenterPoint Houston, and on transmission and distribution systems
owned by others to deliver the wholesale electric power we sell from our power
generation facilities to our customers, who in turn deliver power to the end
users. If transmission is disrupted, or if transmission capacity infrastructure
is inadequate, our ability to sell and deliver wholesale electric energy may be
adversely impacted.

The single control area of the ERCOT market for 2004 is organized into five
congestion zones, referred to as the North, Northeast, South, West and Houston
zones. These congestion zones are determined by physical

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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. All but two of our facilities are
located in the Houston congestion zone. Our Limestone facility is located in the
North congestion zone and the South Texas Project is located in the South
congestion zone. We sell a portion of the entitlements offered in our
state-mandated auctions to customers located in congestion zones other than the
Houston zone. Transmission congestion between these zones could impair our
ability to schedule power for transmission across zonal boundaries, which are
defined by the ERCOT ISO, thereby inhibiting our efforts to match our facility
scheduled outputs with our customer scheduled requirements.

The ERCOT ISO has instituted rules that directly assign congestion costs to
the parties causing the congestion. Therefore, power generators participating in
the ERCOT market could be liable for the congestion costs associated with
transferring power between zones. We schedule our anticipated requirements based
on our own forecasted needs, which rely in part on demand forecasts made by our
customers. These forecasts may prove to be inaccurate. We could be deemed
responsible for congestion costs if we schedule delivery of power between
congestion zones during times when the ERCOT ISO expects congestion to occur
between the zones. If we are liable for congestion costs, our financial results
could be adversely affected. For more information about the ERCOT market, please
read "Our Business -- The ERCOT Market" above.

OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE
ADVERSELY IMPACTED BY A DISRUPTION OF OUR FUEL SUPPLIES.

We rely primarily on natural gas, coal, lignite and uranium to fuel our
generation facilities. We purchase our fuel from a number of different suppliers
under long-term contracts and on the spot market. We sell firm entitlements to
capacity and ancillary services. Therefore, any disruption in the delivery of
fuel could prevent us from operating our facilities to meet our auction
commitments, which could adversely affect our results of operations, financial
condition and cash flows.

Delivery of natural gas to each of our natural gas-fired facilities
typically depends on the natural gas pipelines or distributors for that
location. As a result, we are subject to the risk that a natural gas pipeline or
distributor may suffer disruptions or curtailments in our ability to deliver
natural gas to it or that the amounts of natural gas we request are curtailed.
These disruptions or curtailments could adversely affect our ability to operate
our natural gas-fired generating facilities. We lease gas storage facilities
capable of storing approximately 6.3 billion cubic feet of natural gas, of which
4.2 billion cubic feet is working capacity.

We purchase coal from a limited number of suppliers. Generally, we seek to
maintain average coal reserves sufficient to operate our coal-fired facilities
for 30 days. We also have long-term rail transportation contracts with two rail
transportation companies to transport coal to our coal-fired facilities. Any
extended disruption in our coal supply, including those caused by transportation
disruptions, adverse weather conditions, labor relations or environmental
regulations affecting our coal suppliers, could adversely affect our ability to
operate our coal-fired facilities. We are also exposed to the risk that
suppliers that have agreed to provide us with fuel could breach their
obligations. Should these suppliers fail to perform, we may be forced to enter
into alternative arrangements at then-current market prices. As a result, our
results of operations, financial condition and cash flows could be adversely
affected.

TO DATE, WE HAVE SOLD A SUBSTANTIAL PORTION OF OUR AUCTIONED CAPACITY
ENTITLEMENTS TO SUBSIDIARIES OF RELIANT RESOURCES. ACCORDINGLY, OUR RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY AFFECTED IF
RELIANT RESOURCES CEASES TO BE A MAJOR CUSTOMER OR FAILS TO MEET ITS
OBLIGATIONS.

By participating in our contractually-mandated auctions, subsidiaries of
Reliant Resources have purchased entitlements to 79% of our sold 2004 capacity
and 68% of our sold 2005 capacity. Reliant Resources has made these purchases
either through the exercise of its contractual rights to purchase 50% of the
entitlements we auctioned in our prior contractually-mandated auctions or
through the submission of bids. In the event Reliant Resources ceases to be a
major customer or fails to meet its obligations to us, our results of
operations, financial condition and cash flows could be adversely affected. As
of December 31, 2003, Reliant Resources' securities ratings are below investment
grade. We have been granted a security interest in accounts

21

receivable and/or securitization notes associated with the accounts receivable
of certain subsidiaries of Reliant Resources to secure up to $250 million in
purchase obligations.

WE MAY INCUR SUBSTANTIAL COSTS AND LIABILITIES AS A RESULT OF OUR OWNERSHIP OF
NUCLEAR FACILITIES.

We own a 30.8% interest in the South Texas Project, a nuclear powered
generation facility. As a result, we are subject to the risks associated with
the ownership and operation of nuclear facilities. These risks include:

- liabilities associated with the potential harmful effects on the
environment and human health resulting from the operation of nuclear
facilities and the storage, handling and disposal of radioactive
materials;

- limitations on the amounts and types of insurance commercially available
to cover losses that might arise in connection with nuclear operations;
and

- uncertainties with respect to the technological and financial aspects of
decommissioning nuclear plants at the end of their licensed lives.

The NRC has broad authority under federal law to impose licensing and
safety-related requirements for the operation of nuclear generation facilities.
In the event of non-compliance, the NRC has the authority to impose fines, shut
down a unit, or both, depending upon our assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate substantial capital expenditures at nuclear plants.
In addition, although we have no reason to anticipate a serious nuclear incident
at the South Texas Project, if an incident were to occur, it could have a
material adverse effect on our results of operations, financial condition and
cash flows.

OTHER RISKS

OUR HISTORICAL FINANCIAL RESULTS COVERING PERIODS PRIOR TO 2002 REPRESENT OUR
RESULTS AS PART OF AN INTEGRATED UTILITY OPERATING IN A REGULATED MARKET AND
ARE NOT REPRESENTATIVE OF OUR RESULTS AS A SEPARATE COMPANY OPERATING IN THE
DEREGULATED ERCOT MARKET. CONSEQUENTLY, OUR FUTURE FINANCIAL CONDITION AND
RESULTS OF OPERATIONS ARE LIKELY TO VARY MATERIALLY FROM THE FINANCIAL
CONDITION AND RESULTS OF OPERATIONS PRESENTED IN THE HISTORICAL FINANCIAL
INFORMATION INCLUDED HEREIN COVERING PERIODS PRIOR TO 2002.

We have limited experience operating as a stand-alone wholesale electric
power generation company in a deregulated market. Our generation facilities were
formerly owned by Reliant Energy, which conveyed these facilities to us in
accordance with a business separation plan adopted in response to the Texas
electric restructuring law.

The historical financial information covering periods prior to 2002 does
not reflect what our financial position, results of operations and cash flows
would have been had our generation facilities been operated under the current
deregulated ERCOT market. Although our generation facilities had a significant
operating history at the time they were conveyed to us, the historical financial
information relating to the operation of these facilities during periods prior
to 2002 reflects the sale of the power generated by the facilities as part of an
integrated utility at regulated rates. We currently sell the power generated by
these facilities at market-based prices, and our revenues currently depend, in
large part, upon prevailing market prices for electricity in the ERCOT market.
To date, our capacity auctions have been consummated at market-based prices that
have resulted in returns substantially below the historical regulated return on
our facilities.

The historical financial information we have included herein also does not
reflect what our financial position, results of operations and cash flows would
have been had we been a separate entity during the periods presented. Our
historical costs and expenses included in our financial statements reflect
charges from Reliant Energy for centralized corporate services and operating
infrastructure costs as well as allocated costs of capital. These allocations
have been determined based on what we and Reliant Energy considered to be
reasonable reflections of the utilization of services provided to us or for the
benefits received by us. We may experience significant changes in our cost
structure, capitalization and operations as a result of our separation from

22

Reliant Energy, including increased costs associated with reduced economies of
scale and with being a publicly traded company.

WE MAY NOT HAVE ACCESS TO SUFFICIENT CAPITAL IN THE AMOUNTS AND AT THE TIMES
NEEDED TO FINANCE OUR BUSINESS.

To date, our capital has been provided by internally generated cash flows
and borrowings from the CenterPoint Energy money pool. As a result of our
certification by the FERC as an "exempt wholesale generator" under the 1935 Act,
we can no longer participate in this money pool. CenterPoint Energy has
established a second money pool in which Texas Genco and certain other
unregulated subsidiaries of CenterPoint Energy can participate. In December
2003, we entered into a $75 million revolving credit facility. It is anticipated
that we will meet our cash needs with a combination of funds from operations and
borrowings under our revolving credit facility. Except in an emergency situation
(in which CenterPoint Energy could provide funding pursuant to applicable SEC
rules), CenterPoint Energy would be required to obtain approval from the SEC to
issue and sell securities for purposes of funding our operations or for
CenterPoint Energy to guarantee our securities. There is no assurance that
CenterPoint Energy will have sufficient funds to meet our cash needs.

CenterPoint Energy's $2.3 billion bank facility limits our incurrence of
indebtedness for borrowed money to an aggregate principal amount not to exceed
$250 million outstanding at any time and requires that proceeds from the sale of
any material portion of our assets, proportionate to CenterPoint Energy's
ownership interest in us and subject to certain other requirements, be used to
prepay indebtedness under such credit facility. Our new credit facility also
limits our incurrence of additional secured indebtedness for borrowed money to a
maximum of $175 million aggregate principal amount. Although we are not
contractually bound by the limitations in CenterPoint Energy's bank facility, it
is expected that CenterPoint Energy would likely cause its representatives on
our board of directors to direct our business so as not to breach the terms of
its facility.

We can give no assurances that our current and future capital structure,
operating performance, financial condition and cash flows will permit us to
access the capital markets or to obtain other financing as needed to meet our
working capital requirements and projected future capital expenditures on
favorable terms. The amount of any debt issuance by us is expected to be
affected by the market's perception of our creditworthiness, market conditions
and factors affecting our industry. Our projected future capital expenditures
are substantial. Our ability to secure third party credit lines or other debt
financing may be adversely impacted by the factors described in this section,
including the nature of our business, which may lead to volatility in our
financial results and cash flows. Please read "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Future Sources and Uses of Cash," in Item 7 of this report.

We are an 81% owned subsidiary of CenterPoint Energy. As a result of this
relationship, the financial condition of CenterPoint Energy could affect our
access to capital, our credit standing and our financial condition.

OUR OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION, INCLUDING ENVIRONMENTAL
REGULATION. IF WE FAIL TO COMPLY WITH APPLICABLE REGULATIONS OR OBTAIN OR
MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR APPROVAL, WE MAY BE SUBJECT TO
CIVIL, ADMINISTRATIVE AND/OR CRIMINAL PENALTIES THAT COULD ADVERSELY IMPACT
OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

Our operations are subject to complex and stringent energy, environmental
and other governmental laws and regulations. The acquisition, ownership and
operation of power generation facilities require numerous permits, approvals and
certificates from federal, state and local governmental agencies. These
facilities are subject to regulation by the Texas Utility Commission regarding
non-rate matters. Existing regulations may be revised or reinterpreted, new laws
and regulations may be adopted or become applicable to us or any of our
generation facilities or future changes in laws and regulations may have a
detrimental effect on our business.

23

Operation of the South Texas Project is subject to regulation by the NRC.
This regulation involves testing, evaluation and modification of all aspects of
plant operation in light of NRC safety and environmental requirements.
Continuous demonstrations to the NRC that plant operations meet applicable
requirements are also required. The NRC has the ultimate authority to determine
whether any nuclear powered generating unit may operate.

Water for certain of our facilities is obtained from public water
authorities. New or revised interpretations of existing agreements by those
authorities or changes in price or availability of water may have a detrimental
effect on our business.

Our business is 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 or with
any other regulatory requirements that apply to our operations, we could be
subject to administrative, civil and/or criminal liability and fines, and
regulatory agencies could take other actions seeking to curtail our operations.
These liabilities or actions could adversely impact our results of operations,
financial condition and cash flows.

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 occurs, our business, results of
operations, financial condition and cash flows 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, we may not be able to operate our facilities or we may be required to
incur additional costs. We are generally responsible for all on-site liabilities
associated with the environmental condition of our power generation facilities,
regardless of when the liabilities arose and whether the liabilities are known
or unknown. These liabilities may be substantial.

OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE
AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

We have insurance covering certain of our facilities, including property
damage insurance, commercial general liability insurance, boiler and machinery
coverage and available replacement capacity in amounts that we consider
appropriate. However, our insurance policies are subject to certain limits and
deductibles and do not include business interruption coverage. We cannot assure
you that insurance coverage will be available in the future at current costs or
on commercially reasonable terms or that the insurance proceeds received for any
loss of or any damage to any of our generation facilities will be sufficient to
restore the loss or damage without negative impact on our results of operations,
financial condition and cash flows.

We 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.
Under the federal Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $10.6 billion as of December 31, 2003. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. We and the other owners of the South Texas
Project currently maintain the required nuclear liability insurance and
participate in the industry retrospective rating plan. In addition, the security
procedures at this facility have recently been enhanced to provide additional
protection against terrorist attacks. All potential losses or liabilities
associated with the South Texas Project may not be insurable, and the amount of
insurance may not be sufficient to cover them.

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OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

The demand for power in the ERCOT market is seasonal, with higher demand
occurring during the warmer months. Accordingly, our customers are generally
willing to pay higher prices for entitlements to our capacity during warmer
months. As a result, our revenues and results of operations are subject to
seasonality, with revenues being higher during the warmer months.

RISKS RELATED TO OUR RELATIONSHIPS WITH CENTERPOINT ENERGY

CENTERPOINT ENERGY'S PLAN TO MONETIZE ITS INTEREST IN US MAY ADVERSELY IMPACT
OUR OPERATIONS AND FINANCIAL CONDITION, AND THE TRADING PRICE OF TEXAS GENCO'S
COMMON STOCK.

CenterPoint Energy expects to monetize its 81% interest in Texas Genco in
2004 and has engaged a financial advisor to assist them in that pursuit.
CenterPoint Energy plans to fully evaluate this option before seeking another
alternative. CenterPoint Energy and Reliant Resources currently provide a
variety of services to us pursuant to the agreements described under
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- Related Party Transactions -- Our Relationships with CenterPoint
Energy" and "-- Technical Services Agreement with Reliant Resources" in Item 7
of this report. These services agreements will terminate upon the sale of
CenterPoint Energy's interest in Texas Genco. In such an event, we may be
required to replace the services currently provided under arrangements with less
favorable terms. Also, under the terms of our $75 million 365-day revolving
credit facility, if CenterPoint Energy ceases to own, directly or indirectly, at
least a 50% voting and economic interest in our wholly owned subsidiary Texas
Genco, LP, an event of default will occur and any borrowings thereunder may
become immediately due and payable. In addition, depending on the nature of any
monetization transaction, the trading price of Texas Genco's common stock could
be adversely affected.

WE WILL BE CONTROLLED BY CENTERPOINT ENERGY AS LONG AS IT OWNS A MAJORITY OF
TEXAS GENCO'S COMMON STOCK, AND OUR MINORITY SHAREHOLDERS WILL BE UNABLE TO
AFFECT THE OUTCOME OF SHAREHOLDER VOTING DURING THAT TIME.

As a result of the January 6, 2003 distribution, CenterPoint Energy
indirectly owns approximately 81% of Texas Genco's outstanding common stock. As
long as CenterPoint Energy owns a majority of our outstanding common stock, it
will continue to be able to elect our entire board of directors, and our public
shareholders, by themselves, will not be able to affect the outcome of any
shareholder vote. In addition, CenterPoint Energy has stated that it is pursuing
strategic alternatives for its ownership interest in us, including a possible
sale, which could result in a third party becoming our majority shareholder. Our
majority shareholder, subject to any fiduciary duty owed to our minority
shareholders under Texas law, will be able to control all matters affecting us.
In addition, our majority shareholder may enter into credit agreements,
indentures or other contracts that limit the activities of its subsidiaries.
While we would not likely be contractually bound by these limitations, our
majority shareholder would likely cause its representatives on our board to
direct our business so as not to breach any of these agreements.

WE MAY HAVE POTENTIAL BUSINESS CONFLICTS OF INTEREST WITH CENTERPOINT ENERGY
WITH RESPECT TO OUR PAST AND ONGOING RELATIONSHIPS, AND BECAUSE OF CENTERPOINT
ENERGY'S CONTROLLING OWNERSHIP INTEREST, WE MAY NOT BE ABLE TO RESOLVE THESE
CONFLICTS ON TERMS POSSIBLE IN ARM'S LENGTH TRANSACTIONS.

Conflicts of interest may arise between CenterPoint Energy and us in a
number of areas relating to our past and ongoing relationships, including
proceedings, actions and decisions of legislative bodies and administrative
agencies, and our dividend policy. The agreements we have entered into with
CenterPoint Energy may be amended in the future upon agreement of the parties.
While we are controlled by CenterPoint Energy, CenterPoint Energy may be able to
require us to amend these agreements. We may not be able to resolve any
potential conflicts with CenterPoint Energy, and even if we do, the resolution
may be less favorable than if we were dealing with an unaffiliated party.

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ITEM 2. PROPERTIES.

Our central support facility includes office space, a maintenance shop, a
chemical lab, a warehouse facility and a fleet maintenance garage. This facility
includes a total of approximately 521,000 square feet of space, of which
approximately 407,000 square feet is occupied by us and approximately 114,000
square feet is leased to Reliant Resources. We also lease approximately 7,100
square feet at CenterPoint Energy's principal office building.

In addition, we lease or own various real property and facilities relating
to our generation assets and other vacant real property unrelated to our
generation assets. We have described our principal generation and support
facilities under "Our Generation Portfolio" in Item 1 of this report, which
description is incorporated herein by reference. We believe we have satisfactory
title to our facilities in accordance with standards generally accepted in the
electric power industry, subject to exceptions that, in our opinion, would not
have a material adverse effect on the use or value of the facilities.

All of our real and tangible properties, subject to certain exclusions, are
currently subject to the lien of a First Mortgage Indenture (the Mortgage) dated
December 23, 2003 between JPMorgan Chase Bank, as trustee, and our wholly owned
subsidiary, Texas Genco, LP. As of December 31, 2003, we had issued $75 million
aggregate principal amount of first mortgage bonds under the Mortgage as
collateral to secure our obligations under our $75 million 364-day revolving
credit facility.

ITEM 3. LEGAL PROCEEDINGS.

We are, from time to time, a party to litigation arising in the normal
course of our business, most of which involves contract disputes or claims for
personal injury and property damage incurred in connection with our operations.
We are not currently involved in any litigation that we expect will have a
material adverse effect on our financial condition, results of operations and
cash flows. For a description of a number of lawsuits involving claims of
asbestos exposure at properties owned by us, please read "Environmental
Matters -- Asbestos" in Item 1 of this report, which description is incorporated
herein by reference.

During 2003, we and CenterPoint Energy were engaged in a dispute with
Northwestern Resources Co. (NWR), the supplier of fuel to the Limestone electric
generation facility, over the terms and pricing at which NWR supplies fuel to
that facility under a 1999 settlement agreement between the parties and under
ancillary obligations. Both sides to the dispute initiated lawsuits, but in
January 2004, we reached a settlement with NWR under which we agreed to dismiss
those lawsuits and under which NWR would continue to provide certain quantities
of lignite at specified