CENTERPOINT ENERGY INC - 10-K Annual Report

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

(Mark One)
[X] ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE
SECURITIES EXCHANGE ACT OF 1934

FOR THE FISCAL YEAR ENDED DECEMBER 31, 2002

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 1-31447
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CENTERPOINT ENERGY, INC.
(Exact name of registrant as specified in its charter)

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

1111 LOUISIANA (713) 207-1111
HOUSTON, TEXAS 77002 (Registrant's telephone number, including area
(Address and zip code of principal executive code)
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 each of the registrants' knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [ ]

The aggregate market value of the voting stock held by non-affiliates of
CenterPoint Energy, Inc. (Company) was $5,027,126,669 as of June 28, 2002, using
the definition of beneficial ownership contained in Rule 13d-3 promulgated
pursuant to the Securities Exchange Act of 1934 and excluding shares held by
directors and executive officers. As of February 25, 2003, the Company had
305,204,724 shares of Common Stock outstanding, including 4,452,404 ESOP shares
not deemed outstanding for financial statement purposes. Excluded from the
number of shares of Common Stock outstanding are 166 shares held by the Company
as treasury stock.

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

Portions of the definitive proxy statement relating to the 2003 Annual
Meeting of Shareholders of the Company, which will be filed with the Securities
and Exchange Commission within 120 days of December 31, 2002, are incorporated
by reference in Item 10, Item 11, Item 12 and Item 13 of Part III of this Form
10-K.
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TABLE OF CONTENTS

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 26 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

COMMONLY USED TERMS

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

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

AOL TW........................ AOL Time Warner Inc.

AOL TW Common................. AOL TW common stock

Arkla......................... CenterPoint Energy Arkla, a division of CERC
Corp.

Bcf........................... Billion cubic feet

Business separation plan...... Reliant Energy's amended business separation
plan providing for the separation of its
generation, transmission and distribution, and
retail operations into three different
companies and for the separation of its
regulated and unregulated businesses into two
publicly traded companies, as filed with the
Texas Utility Commission

CenterPoint Energy............ CenterPoint Energy, Inc.

CenterPoint Houston........... CenterPoint Energy Houston Electric, LLC, the
transmission and distribution business of
CenterPoint Energy after the Restructuring

CERC.......................... CenterPoint Energy Resources Corp. and
subsidiaries

CERC Corp..................... CenterPoint Energy Resources Corp.

ECOM.......................... The Texas Utility Commission's Excess Cost Over
Market computer model used to estimate stranded
costs related to generation plant assets

ECOM true-up.................. A reconciliation, to be part of the 2004
true-up proceeding to be conducted by the Texas
Utility Commission, of any difference between
the actual market power prices received in
state mandated generation capacity auctions and
the Texas Utility Commission's earlier
estimates of those market prices during the
period from January 1, 2002 through December
31, 2003

Entex......................... CenterPoint Energy Entex, a division of CERC
Corp.

EPA........................... Environmental Protection Agency

ERCOT......................... Electric Reliability Council of Texas, Inc.

ERCOT ISO..................... The ERCOT independent system operator

ERCOT market.................. 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

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

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

General Mortgage.............. The General Mortgage dated October 10, 2002, as
supplemented, between CenterPoint Houston and
JPMorgan Chase Bank, as trustee, which creates
a lien which is junior to the lien of the
Mortgage

GWh........................... Gigawatt hour, a million kwh

iii

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

Kyoto Protocol................ United Nations Framework Convention on Climate
Change

Laclede....................... Laclede Gas Company

MACT.......................... Maximum achievable control technology

Minnegasco.................... CenterPoint Energy Minnegasco, a division of
CERC Corp.

MMcf.......................... Million cubic feet

Mortgage...................... The Mortgage and Deed of Trust dated November
1, 1944, as supplemented, between our
predecessor in interest, Houston Lighting &
Power Company, and JPMorgan Chase Bank
(successor to South Texas Commercial National
Bank of Houston), as trustee

MW............................ Megawatt

Non-bypassable................ An element of a transmission and distribution
utility's rates that must be paid by
essentially all customers and that cannot,
except in limited circumstances, be avoided by
switching to self-generation

NOx........................... Oxides of nitrogen

NRC........................... United States Nuclear Regulatory Commission

October 3, 2001 Order......... Order from the Texas Utility Commission dated
October 3, 2001 that established the
transmission and distribution rates that became
effective January 1, 2002

price to beat................. The price, as set by the Texas Utility
Commission, that retail electric providers
affiliated with a former integrated utility
charge residential and small commercial
customers within their affiliated electric
utility's service area

Railroad Commission........... The Railroad Commission of Texas

REGT.......................... Reliant Energy Gas Transmission Company

Reliant Energy................ Reliant Energy, Incorporated

Reliant Energy HL&P........... An unincorporated division of Reliant Energy,
formerly an integrated electric utility

Reliant Energy Services....... Reliant Energy Services, Inc., a subsidiary of
Reliant Resources

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

Reliant Resources
Distribution.................. The distribution of CenterPoint Energy's
remaining equity interest in the common stock
of Reliant Resources, Inc. to our shareholders
that occurred on September 30, 2002

Reliant Resources Offering.... The May 2001 initial public offering of
approximately 20% of the common stock of
Reliant Resources

REPG.......................... Reliant Energy Power Generation, Inc.

REPS.......................... Reliant Energy Pipeline Services, Inc.

iv

Restructuring................. The transactions through which CenterPoint
Energy became the holding company for Reliant
Energy and its subsidiaries, Reliant Energy and
its subsidiaries became subsidiaries of
CenterPoint Energy, each share of Reliant
Energy common stock was converted into one
share of CenterPoint Energy common stock and
Reliant Energy's electric generation assets
were transferred to Texas Genco

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

Separation.................... The transactions that include the transfers of
substantially all of our unregulated businesses
to Reliant Resources, the Reliant Resources
Offering, the Restructuring and the Reliant
Resources Distribution

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

South Texas Project........... South Texas Project Electric Generating Station

TCR........................... Transmission Congestion Rights

Texas electric restructuring
law........................... Texas Electric Choice Plan, Texas Utility Code
sec. 39.001, et seq.

Texas Genco................... Texas Genco Holdings, Inc. and the intermediate
subsidiaries through which interests in Texas
Genco, LP are held

Texas Genco Option............ Option granted to Reliant Resources to purchase
all of the shares of capital stock of Texas
Genco owned by CenterPoint Energy

Texas generation business..... The generating facilities and operations
transferred to Texas Genco in the Restructuring

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

TMDL.......................... Total Maximum Daily Load program of the Clean
Water Act

We, us, our or similar
terms......................... Reliant Energy and its subsidiaries prior to
the Restructuring and CenterPoint Energy and
its Subsidiaries after the Restructuring,
unless the context states or implies otherwise

v

PART I

ITEM 1. BUSINESS

OUR BUSINESS

OVERVIEW

We are a public utility holding company that became the parent of Reliant
Energy, Incorporated (Reliant Energy) and its subsidiaries on August 31, 2002 as
part of a corporate restructuring of Reliant Energy (the Restructuring). Prior
to the Restructuring, Reliant Energy was an operating integrated electric
utility, a utility holding company for local gas distribution companies and the
parent company of a group of companies providing energy and energy services on a
non-utility basis primarily in North America and Western Europe. Reliant
Energy's non-utility wholesale and retail energy operations were conducted
principally through Reliant Resources, Inc. (Reliant Resources) and its
subsidiaries. On September 30, 2002, we distributed to our shareholders the
approximately 83% ownership interest we held in our subsidiary, Reliant
Resources, effectively divesting our ownership of our unregulated businesses
(Reliant Resources Distribution). The Restructuring implemented certain
requirements of the Texas electric restructuring law described below. We are the
successor to Reliant Energy for financial reporting purposes under the
Securities Exchange Act of 1934. Our indirect wholly owned operating
subsidiaries own and operate electric transmission and distribution facilities,
natural gas distribution facilities and natural gas pipelines. Our publicly
traded subsidiary, Texas Genco Holdings, Inc. (Texas Genco), operates electric
generation plants. Our indirect wholly owned subsidiaries include:

- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in Reliant Energy's former electric transmission and distribution
business in a 5,000-square mile area of the Texas Gulf Coast that
includes Houston; and

- CenterPoint Energy Resources Corp. (CERC Corp. and, together with its
subsidiaries, CERC), which owns gas distribution systems that together
form one of the United States' largest natural gas distribution
operations in terms of the number of customers served. Through wholly
owned subsidiaries, CERC also owns two interstate natural gas pipelines
and gas gathering systems and provides various ancillary services.

We also have an approximately 81% ownership interest in Texas Genco, which
owns and operates the Texas generating plants that were formerly part of the
integrated electric utility that was part of Reliant Energy. We distributed
approximately 19% of the outstanding common stock of Texas Genco to our
shareholders on January 6, 2003.

We are a registered holding company, subject to regulation, with our
subsidiaries, under the Public Utility Holding Company Act of 1935 (1935 Act).
The 1935 Act directs the SEC to regulate, among other things, transactions among
affiliates, sales or acquisitions of assets, issuance of securities,
distributions and permitted lines of business.

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

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. Our
web site address is http://www.centerpointenergy.com.

In June 1999, the Texas legislature enacted a law that substantially
amended the regulatory structure governing electric utilities in Texas in order
to allow retail electric competition. We refer to this legislation as the "Texas
electric restructuring law." Under this law, integrated electric utilities were
required to restructure their businesses to separate their generation,
transmission and distribution and retail functions into separate units, and
sales by power generators such as Texas Genco and retail sales of electricity
(which are now

1

conducted by subsidiaries of Reliant Resources and not by us) ceased to be
subject to traditional cost-based regulation as of January 1, 2002. Also under
this law, our transmission and distribution subsidiary, CenterPoint Houston,
remains subject to cost-based rate regulation and recovers the cost of its
service through an energy delivery charge approved by the Public Utility
Commission of Texas (Texas Utility Commission) and not as a component of the
prior bundled rate. Texas Genco sells its available generation capacity, energy
and ancillary services at prices determined by the market. None of our
businesses sell electricity and related services to end users of electricity.
Accordingly, we no longer operate under the bundled regulated rates in effect
prior to 2002, so there are no meaningful comparisons for these business
segments against prior periods.

RECENT DEVELOPMENT

On February 28, 2003, we reached agreement with a syndicate of banks on a
second amendment to our existing $3.85 billion bank facility. Under the second
amendment, the maturity date of the bank facility was extended from October 2003
to June 30, 2005, and the $1.2 billion in mandatory prepayments that would have
been required this year (including $600 million due on February 28, 2003) were
eliminated. As part of the consideration for the extension, we agreed to grant
the banks (i) a security interest in our 81% stock ownership of Texas Genco and
(ii) warrants to purchase up to 10%, on a fully diluted basis, of our common
stock, both of which require SEC approval under the 1935 Act. If we are not able
to obtain SEC approval by May 28, 2003, in the case of the Texas Genco stock
pledge, the interest rate under the facility will increase by 25 basis points
and, in the case of the warrants, we will become obligated to provide the banks
equivalent cash compensation. If issued, the exercise price of the warrants will
be the greater of $6.56 per share or 110% of the closing price on the New York
Stock Exchange on the date of issuance, they will become exercisable one year
following that date and they will expire four years after becoming exercisable.
We have the right to cause some or all of the warrants (or the related rights to
equivalent cash compensation) to be extinguished by making certain prepayments
under the facility during 2003. Also as part of the consideration for the
extension, we agreed to restrictions on the level of cash dividends on our
common stock until specified repayment milestones are met. These restrictions
limit our quarterly dividend to the lesser of 10 cents per share, or beginning
in 2004, 50% of earnings under certain circumstances. For additional
information, please read "Market for Common Stock and Related Stockholder
Matters" in Item 5 of this report and "Management's Discussion and Analysis of
Financial Condition and Results of Operations -- "Liquidity and Capital
Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of
this report.

THE TEXAS ELECTRIC RESTRUCTURING LAW

The Texas electric restructuring law substantially amended the regulatory
structure governing electric utilities in Texas in order to allow retail
electric competition for all customers. Retail pilot projects, allowing
competition for up to 5% of each utility's energy demand, or "load," in all
customer classes, began in August 2001 and retail electric competition for all
other customers began in January 2002. Under the Texas electric restructuring
law:

- integrated electric utilities in Texas have restructured their businesses
in order to separate power generation, transmission and distribution and
retail electric provider activities into separate business units;

- since January 2002, most Texas retail customers that, prior to that date,
were customers of investor-owned electric utilities in Texas have been
entitled to purchase their electricity from any of several "retail
electric providers" that have been certified by the Texas Utility
Commission;

- retail electric providers, who may not themselves own any generation
assets, obtain their electricity from power generation companies such as
Texas Genco, exempt wholesale generators and other generating entities
and provide services at generally unregulated rates;

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

2

- transmission and distribution utilities in Texas whose generation assets
were "unbundled" pursuant to the Texas electric restructuring law, may
recover, following a regulatory proceeding to be held in 2004:

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

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

(iii) the ECOM True-Up, Fuel Over/Under Recovery and Price to Beat
Clawback components as further discussed in " -- Electric Transmission &
Distribution -- Stranded Costs and Regulatory Assets Recovery" below.

The Texas electric restructuring law permits transmission and distribution
utilities to recover regulatory assets and stranded costs through non-bypassable
charges authorized by the Texas Utility Commission to the extent that such
assets and costs are established in certain regulatory proceedings. The law also
authorizes the Texas Utility Commission to permit these utilities to issue
securitization bonds based on the securitization of the revenue associated with
that charge. For more information, please read "Our Business -- Electric
Transmission & Distribution -- Stranded Costs and Regulatory Assets Recovery"
below.

For additional information regarding the Texas electric restructuring law,
retail competition in Texas and its application to our operations and structure,
please read "Regulation -- State and Local Regulation -- Electric
Operations -- The Texas Electric Restructuring Law" below.

ERCOT MARKET FRAMEWORK

CenterPoint Houston is a member of the Electric Reliability Council of
Texas, Inc. (ERCOT), an intrastate network of retail customers, investor and
municipally owned electric utilities, rural electric co-operatives, river
authorities, independent generators, power marketers and retail electric
providers, which serves as the regional reliability coordinating council for
member electric power systems in Texas. Texas Genco sells electric generation
capacity, energy and ancillary services in 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 70,000
megawatts (MW), approximately 14,000 MW of which are owned by Texas Genco. 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 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 system 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.

CenterPoint Houston's electric transmission business supports the operation
of the ERCOT ISO and all ERCOT members. The transmission business has planning,
design, construction, operation and maintenance responsibility for the
transmission grid and for the load serving substations. The transmission
business is participating with the ERCOT ISO and other ERCOT utilities to plan,
design, obtain regulatory approval for and construct new transmission lines
necessary to increase bulk power transfer capability and to remove existing
limitations on the ERCOT transmission grid.
3

ELECTRIC TRANSMISSION & DISTRIBUTION

SERVICE AREA

CenterPoint Houston's service area consists of a 5,000-square-mile area
located along the Texas Gulf Coast, with a population of approximately 4.7
million people. Electric transmission and distribution service is provided to
approximately 1.8 million metered customers in this area, which includes the
City of Houston and surrounding cities such as Galveston, Pasadena, Baytown,
Bellaire, Freeport, Humble, Katy and Sugar Land. With the exception of Texas
City, CenterPoint Houston serves nearly all of the Houston/Galveston
metropolitan area. Effective January 2002, all former electricity customers of
Reliant Energy HL&P whose service was regulated became free to choose to
purchase their electricity from retail electric providers who compete for their
business. The competing retail electric providers are now CenterPoint Houston's
primary customers. See "-- Customers" below.

ELECTRIC TRANSMISSION

CenterPoint Houston transports electricity from power plants to substations
and from one substation to another and to retail customers taking power above 69
kilovolts (kV). Transmission services are provided under tariffs approved by the
Texas Utility Commission. Transmission service offers the use of the
transmission system for delivery of power over facilities operating at 69 kV and
above.

ELECTRIC DISTRIBUTION

CenterPoint Houston distributes electricity for retail electric providers
in its certificated service area by carrying lower-voltage power from the
substation to the retail electric customer. CenterPoint Houston's distribution
network consists of primary distribution lines, transformers, secondary
distribution lines and service wires. Operations include construction and
maintenance of facilities, metering services, outage response services and other
call center operations. As part of the Texas electric restructuring law,
metering service was to be provided on a competitive basis for commercial and
industrial customers beginning January 1, 2004 and for residential customers in
each service area on the later of September 1, 2005, or the date when 40% of the
residential retail electric customers in that service area are taking service
from unaffiliated or not formerly affiliated retail electric providers. However,
the Texas Utility Commission has determined that the market is not yet ready for
all metering services to be made competitive and has begun a rulemaking
proceeding to decide when and what type of metering services will be opened to
competition.

CenterPoint Houston's distribution network receives electricity from the
transmission grid through power distribution substations and distributes
electricity to end users through CenterPoint Houston's distribution feeders.

Distribution services are provided under tariffs approved by the Texas
Utility Commission. New Texas Utility Commission rules and market protocols
govern the commercial retail operations of distribution companies and other
market participants.

STRANDED COSTS AND REGULATORY ASSETS RECOVERY

The Texas electric restructuring law provides us an opportunity to recover
our "regulatory assets" and "stranded costs." "Stranded costs" include the
positive excess of the regulatory net book value of generation assets over the
market value of the generation assets. The Texas electric restructuring law
allows alternative methods of third party valuation of the market value of
generation assets, including outright sale, full and partial stock valuation and
asset exchanges. Reliant Energy agreed in the business separation plan approved
by the Texas Utility Commission that the market value of Texas Genco's
generating assets would be determined using the partial stock valuation method.
Accordingly, on January 6, 2003, we distributed to our shareholders
approximately 19% of the outstanding common stock of Texas Genco. As the
surviving regulated utility following the Restructuring, CenterPoint Houston
will be allowed to recover these stranded costs in 2004 following the
determination by the Texas Utility Commission of the amount of such costs. The
market prices of the publicly traded common stock will be used to determine the
market value of Texas Genco. For more

4

information regarding the market value determination, please read "-- Final
True-Up -- Stranded Cost Component" below.

The Texas electric restructuring law also provides specific regulatory
remedies to reduce or mitigate a utility's stranded cost exposure. For example,
during a base rate freeze period from 1999 through 2001, earnings above the
utility's authorized rate of return formula were required to be applied in a
manner to accelerate depreciation of generation-related plant assets for
regulatory purposes if the utility was expected to have stranded costs. In
addition, depreciation expense for transmission and distribution related assets
could be redirected to generation assets for regulatory purposes during that
period if the utility was expected to have stranded costs. Reliant Energy
undertook both of these remedies provided in the Texas electric restructuring
law.

Under the Texas electric restructuring law, "regulatory assets" consist of
the Texas jurisdictional amount reported by an electric utility as regulatory
assets and liabilities (offset and adjusted by specified amounts) in its audited
financial statements for 1998. The Texas electric restructuring law permits
utilities to recover regulatory assets through non-bypassable transition charges
on retail electric customers' bills, to the extent that such assets and costs
are established in regulatory proceedings as discussed below. CenterPoint Energy
recovered a portion of its regulatory assets in 2001 through the issuance of
transition bonds.

The Texas electric restructuring law also permits CenterPoint Houston to
issue securitization bonds for the recovery of generation-related regulatory
assets and stranded costs. Please read "-- Securitization Financing" below for a
more complete discussion of the issuance of securitization bonds. Any stranded
costs not recovered through the sale of securitization bonds may be recovered
through a separate non-bypassable transition charge to transmission and
distribution customers.

Mitigation. In October 2001, the Texas Utility Commission ruled that
Reliant Energy had overmitigated its stranded costs by redirecting transmission
and distribution depreciation and by accelerating depreciation of generation
assets as provided under its transition plan and the Texas electric
restructuring law. In December 2001, Reliant Energy recorded a regulatory
liability of $1.1 billion to reflect the prospective refund of accelerated
depreciation, removed its previously recorded embedded regulatory asset of $841
million that had resulted from redirected depreciation and recorded a regulatory
asset of $2.0 billion based upon then current projections of the market value of
Reliant Energy's Texas generation assets to be recovered by the 2004 true-up
proceeding described below. These regulatory assets and liabilities are recorded
by CenterPoint Houston. Reliant Energy began refunding the excess mitigation
credits in January 2002, and CenterPoint Houston will continue to do so over a
seven-year period. If events occur that make the recovery of all or a portion of
the regulatory assets no longer probable, we will write off the corresponding
balance of these assets as a charge against earnings. We appealed the Texas
Utility Commission's true-up rule on the basis that there are no negative
stranded costs, that we should be allowed to collect interest on stranded costs,
and that the premium on the partial stock valuation applies to only the equity
of Texas Genco, not equity plus debt. The Texas court of appeals issued a
decision on February 6, 2003 upholding the rule in part and reversing in part.
The court ruled that there are no negative stranded costs and that the premium
on the partial stock valuation applies only to equity. The court upheld the
Texas Utility Commission's rule that interest on stranded costs begins upon the
date of the final true-up order. On February 21, 2003, we filed a motion for
rehearing on the issue that interest on amounts determined in the true-up
proceeding should accrue from an earlier date. We have not accrued interest in
our consolidated financial statements, but estimate that interest could be
material. If the court of appeals denies our motion, then we will have 45 days
to appeal to the Texas Supreme Court. We have not decided what action, if any,
we will take if the motion for rehearing is denied.

Final True-Up. Beginning in January 2004, the Texas Utility Commission
will conduct true-up proceedings for each investor-owned utility. The purpose of
the true-up proceeding is to quantify and reconcile the amount of stranded
costs, the difference in the price of power obtained through capacity auctions
conducted by Texas Genco and the power costs used in the Excess Cost Over Market
(ECOM) model, any fuel costs over- or under-recovery, the "price to beat"
clawback and other regulatory assets associated with the generating assets that
were not previously securitized as described below under "-- Securitization
Financing."

5

The true-up proceeding will result in either additional charges being assessed
on, or credits being issued to, retail electric customers taking delivery from
CenterPoint Houston.

Stranded Cost Component. The regulatory net book value of generating
assets will be compared to the market value of those assets using the partial
stock valuation method. The resulting difference, if positive, represents
stranded costs that will be recovered through a transition charge, which is a
non-bypassable charge assessed to customers taking delivery service from
CenterPoint Houston. Stranded costs may be securitized. Please read
"-- Securitization Financing" below for a more complete discussion of the
securitization.

The publicly traded common stock of Texas Genco will be used to determine
the market value of the generating assets of Texas Genco pursuant to the partial
stock valuation method for determining stranded costs. The market value will be
equal to the average daily closing price on The New York Stock Exchange for
publicly held shares of Texas Genco common stock for the 30 consecutive trading
days chosen by the Texas Utility Commission out of the last 120 trading 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. The regulatory net book value of generating plant
assets is the balance as of December 31, 2001 plus certain costs incurred for
reductions in emissions of oxides of nitrogen (NOx) and any above-market
purchased power contracts.

ECOM True-Up Component. The Texas Utility Commission used a computer model
or projection, called an ECOM model, to estimate stranded costs related to
generation plant assets. Accordingly, the Texas Utility Commission estimated the
market power prices that would be received in the generation capacity auctions
mandated by the Texas electric restructuring law during the period from January
1, 2002 through December 31, 2003. Any difference between the actual market
power prices received in those auctions and the Texas Utility Commission's
earlier estimates of those market prices will be a component of the 2004 true-up
proceeding.

Fuel Over/Under Recovery Component. CenterPoint Houston and Texas Genco
filed their joint application to reconcile fuel revenues and expenses with the
Texas Utility Commission on July 1, 2002. This final fuel reconciliation filing
covers reconcilable fuel revenue, fuel expense and interest of approximately
$8.5 billion incurred from August 1, 1997 through January 30, 2002. Also
included in this amount is an under-recovery of $94 million, which was the
balance at July 31, 1997 as approved in CenterPoint Houston's last fuel
reconciliation. On January 28, 2003, a settlement agreement was reached under
which it was agreed that certain items totaling $24 million were written off
during the fourth quarter of 2002 and items totaling $203 million will be
carried forward for resolution by the Texas Utility Commission in late 2003 or
early 2004.

"Price to Beat" Clawback Component. In connection with the implementation
of the Texas electric restructuring law, the Texas Utility Commission has set a
"price to beat" that retail electric providers affiliated or formerly affiliated
with a former integrated utility must charge residential and small commercial
customers within their affiliated electric utility's service area. The true-up
provides for a clawback of "price to beat" in excess of the market price of
electricity if 40% of the "price to beat" load is not served by a non-affiliated
retail electric provider by January 1, 2004. Pursuant to the Texas electric
restructuring law and the master separation agreement between Reliant Energy and
Reliant Resources, Reliant Resources is obligated to pay CenterPoint Houston for
the clawback component of the true-up. The clawback may not exceed $150 times
the number of customers served by the affiliated retail electric provider in the
transmission and distribution utility's service territory, less the number of
customers served by the affiliated retail electric provider outside the
transmission and distribution utility's service territory, on January 1, 2004.
We expect the clawback, if any, will reduce any stranded cost recovery to which
CenterPoint Houston is entitled or, if no stranded costs are recoverable, will
be refunded to retail electric customers.

Securitization Financing. The Texas electric restructuring law provides
for the use of special purpose entities to issue securitization bonds for the
economic value of generation-related regulatory assets and stranded costs. These
securitization bonds will be amortized over a period not to exceed 15 years
through non-bypassable transition charges to customers taking delivery service
from CenterPoint Houston. Any stranded costs not recovered through the
securitization bonds will be recovered through a non-bypassable competition
transition charge assessed to customers taking delivery service from CenterPoint
Houston.
6

In October 2001, one of our subsidiaries issued $749 million of transition
bonds to securitize generation-related regulatory assets. These transition bonds
have a final maturity date of September 15, 2015 and are non-recourse to us or
our subsidiaries other than to the special purpose issuer. Payments on the
transition bonds are made out of funds from non-bypassable transition charges
assessed to customers taking delivery service from CenterPoint Houston.

We expect that CenterPoint Houston will seek to securitize the true-up
balance upon completion of the 2004 true-up proceeding. The securitization bonds
may have a maximum maturity of 15 years. Payments on these securitization bonds
would also be made out of funds from non-bypassable transition charges assessed
to customers taking delivery service from CenterPoint Houston.

PROPERTIES

All of CenterPoint Houston's properties are located in the State of Texas.
CenterPoint Houston's transmission system carries electricity from power plants
to substations and from one substation to another. These substations serve to
connect power plants, the high voltage transmission lines and the lower voltage
distribution lines. Unlike the transmission system, which carries high voltage
electricity over long distances, distribution lines carry lower voltage power
from the substation to the retail electric customers. The distribution system
consists primarily of distribution lines, transformers, secondary distribution
lines and service wires. Most of CenterPoint Houston's transmission and
distribution lines have been constructed over lands of others pursuant to
easements or along public highways and streets as permitted by law.

All real and tangible properties of CenterPoint Houston, subject to certain
exclusions, are currently subject to:

- the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1,
1944, as supplemented, between our predecessor in interest, Houston
Lighting & Power Company, and JPMorgan Chase Bank (successor to South
Texas Commercial National Bank of Houston), as trustee; and

- the lien of a General Mortgage (the General Mortgage) dated October 10,
2002, as supplemented, between CenterPoint Houston and JPMorgan Chase
Bank, as trustee, which is junior to the lien of the Mortgage.

CenterPoint Houston has issued approximately $1.2 billion aggregate
principal amount of first mortgage bonds under the Mortgage, including
approximately $547 million to secure certain medium-term notes and pollution
control bonds for which CenterPoint Energy is obligated. Additionally, under the
General Mortgage, CenterPoint Houston has issued approximately $527 million
aggregate principal amount of general mortgage bonds to secure certain
additional pollution control bonds for which CenterPoint Energy is obligated and
approximately $1.3 billion aggregate principal amount of general mortgage bonds
to secure the borrowings under a collateralized term loan due in 2005. For more
information, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- "Liquidity and Capital
Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of
this report.

Electric Lines -- Overhead. As of December 31, 2002, CenterPoint Houston
owned 26,346 pole miles of overhead distribution lines and 3,599 circuit miles
of overhead transmission lines, including 444 circuit miles operated at 69,000
volts, 2,078 circuit miles operated at 138,000 volts and 1,077 circuit miles
operated at 345,000 volts.

Electric Lines -- Underground. As of December 31, 2002, CenterPoint
Houston owned 13,364 circuit miles of underground distribution lines and 16.6
circuit miles of underground transmission lines, including 4.5 circuit miles
operated at 69,000 volts and 12.1 circuit miles operated at 138,000 volts.

Substations. As of December 31, 2002, CenterPoint Houston owned 224 major
substation sites having total installed rated transformer capacity of 44,163
megavolt amperes.

Service Centers. CenterPoint Houston operates 20 regional service centers
located on a total of 405 acres of land. These service centers consist of office
buildings, warehouses and repair facilities that are used in the business of
transmitting and distributing electricity.
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Franchises. CenterPoint Houston has franchise contracts with 89 of the 90
cities in its service area. The remaining city has enacted an ordinance that
governs the placement of utility facilities in its streets. These franchises and
this ordinance give CenterPoint Houston the right to construct, operate and
maintain its electrical transmission and distribution systems within city
streets, alleys and rights-of-ways in exchange for payment of a fee.

Fiber Optic System. CenterPoint Houston owns a fiber optic system to
provide communications among its service center facilities and office
operations. CenterPoint Houston owns approximately 284 miles of single-mode
fiber in Harris, Fort Bend and Galveston counties located in Texas. This fiber
is buried in transmission line rights-of-way or strung on overhead electrical
distribution or transmission facilities.

CUSTOMERS

CenterPoint Houston's customers consist of municipalities, electric
cooperatives, other distribution companies and approximately 31 retail electric
providers in its certificated service area. Each retail electric provider is
licensed by the Texas Utility Commission and must meet creditworthiness criteria
established by the Texas Utility Commission. Two of these retail electric
providers are subsidiaries of Reliant Resources. CenterPoint Houston's
receivables balance from retail electric providers as of December 31, 2002, was
$85 million. Approximately 72% of this amount was owed by subsidiaries of
Reliant Resources. Sales to Reliant Resources represented approximately 83% of
CenterPoint Houston's transmission and distribution revenues since deregulation
began in 2002. CenterPoint Houston provides services under tariffs approved by
the Texas Utility Commission. It does not have long-term contracts with any of
its customers. CenterPoint Houston operates on a continuous billing cycle, with
meter readings being conducted and invoices being distributed to retail electric
providers each business day.

COMPETITION

There are no other transmission and distribution utilities in CenterPoint
Houston's service area. In order for another provider of transmission and
distribution services to provide such services in CenterPoint Houston's
territory, it would be required to obtain a certificate of convenience and
necessity in proceedings before the Texas Utility Commission and, depending on
the location of the facilities, may also be required to obtain franchises from
one or more municipalities. We know of no other party intending to enter this
business in CenterPoint Houston's service area at this time.

ELECTRIC GENERATION

Texas Genco acquired Reliant Energy's portfolio of electric generation
facilities located in Texas and related business effective August 31, 2002
through a transfer of assets between entities under common control. From January
1, 2002 until August 31, 2002, however, the electric generation assets were
operated as a separate division within Reliant Energy. For convenience, we
describe Texas Genco's business in this Form 10-K as if Texas Genco had owned
and operated its generation assets prior to the date those assets were actually
conveyed to Texas Genco.

Texas Genco is one of the largest wholesale electric power generating
companies in the United States. Texas Genco owns and operates 60 generating
units at 11 power generation facilities. Texas Genco also owns a 30.8% interest
in the South Texas Project Electric Generating Station (South Texas Project), a
nuclear generating station with two 1,250 MW nuclear generating units. As of
December 31, 2002, the aggregate net generating capacity of Texas Genco's
combined portfolio of generating assets was 14,175 MW. Texas Genco sells
electric generation capacity, energy and ancillary services in the ERCOT market,
which is the largest power market in the State of Texas. Collectively, Texas
Genco's facilities provide approximately 20% of the aggregate net generating
capacity serving the ERCOT market.

Under the Texas electric restructuring law, Texas Genco and other power
generators in Texas ceased to be subject to traditional cost-based regulation.
Since January 1, 2002, Texas Genco has been selling generation capacity, energy
and ancillary services to wholesale purchasers at prices determined by the
market.

8

Because of this change, historical financial information and operating data for
periods prior to January 1, 2002, including demand and fuel data, is not
indicative of how this business may be expected to perform in subsequent
periods.

As a result of requirements under the Texas electric restructuring law, as
well as an agreement between Reliant Resources and us, Texas Genco is obligated
to sell substantially all of its available capacity and related ancillary
services through 2003 pursuant to capacity auctions, subject to permitted
operating reserves. In these auctions, Texas Genco sells firm entitlements to
capacity and ancillary services on a forward basis dispatched within specified
operational constraints. For more information regarding these auctions, please
read "-- Operations and Capacity Auctions" below.

FACILITIES

Texas Genco's generation facilities as of December 31, 2002 are described
in the table below.

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

(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) In October 2002, Texas Genco announced its plan to mothball all 2,213 MW of
capacity at its P.H. Robinson facility, 229 MW of capacity at its T.H.
Wharton facility, 406 MW of capacity at its Greens Bayou facility, 374 MW of
capacity at its Webster facility and all 174 MW of capacity at its Deepwater
facility through at least May 2003.

Beginning in September 2002, an outage was commenced for one of the
generating units at the South Texas Project to replace its steam generators with
a model that is less susceptible to tube cracking. We expect this change will
restore the design life of the unit and increase the potential for an extension
of the South Texas Project's license. This unit was briefly returned to service
in December 2002. However, as a result of certain non-safety-related mechanical
failures, the unit was removed from service in December 2002 and is expected to
return to service in the first quarter of 2003. The steam generators in the
other generating unit at the plant were replaced in the spring of 2000.

9

MARKET FRAMEWORK

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 that ERCOT administers.

OPERATIONS AND CAPACITY AUCTIONS

Since January 1, 2002, Texas Genco has operated its generation business
solely in the wholesale market. It is required by the Texas electric
restructuring law to auction 15% of its available generation capacity (state
mandated auctions) and will sell 85% of its available generation capacity in the
auctions mandated by an agreement with Reliant Resources (contractually mandated
auctions). Texas Genco's auction products are only entitlements to capacity
dispatched to specific zonal delivery points from base, intermediate, cyclic or
peaking units and do not convey a right to receive power from a particular unit.
This enables Texas Genco to dispatch its commitments in the most cost-effective
manner, but also exposes it to the risk that, depending upon the availability of
its units, it could be required to supply energy from a higher cost unit, such
as an intermediate unit, to meet an obligation for lower cost generation, such
as base-load generation, or to obtain the energy on the open market at a market
price higher than its contracted price. Additionally, Texas Genco, like other
power generating companies within ERCOT, is required to purchase power from
qualifying facilities under the Public Utility Regulatory Policies Act of 1978
at avoided cost.

Revenues from 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. Texas Genco bills
and collects 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 the auctioned
capacity entitlements. Energy payments for base-load products are tied to fixed
prices specified in the auction products while gas payments are recovered
through heat rates specified for gas auction products times an index based on
the Houston Ship Channel Gas price. Texas Genco invoices for these energy
payments on a monthly basis in arrears.

STATE MANDATED CAPACITY AUCTIONS

The obligation to conduct state mandated auctions of 15% of Texas Genco's
available generation capacity will continue until January 1, 2007, unless before
that date the Texas Utility Commission determines that an amount equal to at
least 40% of the electric power consumed before the onset of competition by
residential and small commercial customers in CenterPoint Houston's service area
is being served by retail electric providers not affiliated or formerly
affiliated with us. Reliant Resources is deemed to be our affiliate for purposes
of this test. Reliant Resources currently is not permitted under the Texas
electric restructuring law to purchase capacity sold by Texas Genco in the state
mandated auctions.

CONTRACTUALLY MANDATED CAPACITY AUCTIONS

Texas Genco is contractually obligated to auction entitlements to
substantially all of its available capacity and related ancillary services
available after the state-mandated auctions until the date on which the Texas
Genco Option, described below, either is exercised or expires. Texas Genco is
permitted to reduce the amount of capacity sold in the contractually mandated
auctions by the amount of operating reserves required to back up its obligations
under its capacity auctions. Since Texas Genco sells the majority of its
available capacity as firm entitlements, it typically reserves 1,250 MW of its
capacity as operating reserves, which can be sold as interruptible power on a
system-contingent basis.

Through 2003, Reliant Resources has the contractual right, but not the
obligation, to purchase 50% (but not less than 50%) of each type of capacity
entitlement Texas Genco auctions in the contractually mandated auctions at the
prices established in the auctions. To exercise this right, Reliant Resources is
required to notify
10

Texas Genco whether it elects to purchase 50% of the capacity auctioned no later
than three business days prior to the date of the auction. Texas Genco excludes
the amount of capacity specified in Reliant Resources' notice from the auction.
Texas Genco auctions any portion of the capacity that Reliant Resources does not
reserve through its notice in the contractually mandated auctions.

Upon determination of the prices for the capacity entitlements Texas Genco
auctions, Reliant Resources is obligated to purchase the capacity it elected to
reserve from the auction process at the prices set during the auction for that
entitlement. If Texas Genco auctions capacity and ancillary services separately,
Reliant Resources is entitled to participate in 50% of the offered capacity of
each. In addition to its reservation of capacity, and whether or not it has
reserved capacity in the auction, Reliant Resources is entitled to participate
in each contractually mandated auction. If Reliant Resources exercises its
option to purchase the shares of Texas Genco common stock owned by us in January
2004 (Texas Genco Option), Texas Genco will not conduct any capacity auctions,
other than as required by Texas Utility Commission's rules, between the option
exercise date and the option closing date without obtaining Reliant Resources'
consent, which it may not unreasonably withhold. If Reliant Resources does not
exercise the Texas Genco Option, Texas Genco will no longer be required to
conduct contractually mandated auctions following the expiration of that option.

Auction Results. Texas Genco conducted its initial state mandated auctions
and contractually mandated auctions from September 2001 through January 2003.
Thirty-one companies, including Reliant Resources, registered and qualified to
participate in these auctions. As a result, Texas Genco sold 91% of its
available capacity for 2002 and has sold 74% of its available capacity for 2003.
Texas Genco's available capacity equals its total net generating capacity less
capacity withheld as operating reserves and capacity that is subject to planned
outages. The 3,400 MW of capacity that we have "mothballed" as described below
under "-- Competition" is included in our available capacity only for the months
of June through September 2003. Reliant Resources purchased 63% of Texas Genco's
available 2002 capacity and, through January 2003, has purchased 58% of Texas
Genco's available 2003 capacity. Texas Genco intends to hold auctions to sell
its remaining available capacity for 2003 in March and July 2003.

To date, the market-based prices established in Texas Genco's capacity
auctions have provided returns on its facilities substantially below historical
regulated returns. Higher gas prices in the latter part of 2002 and early 2003
have positively influenced the prices established in its recent capacity
auctions. Generally, higher gas prices increase the capacity prices for its
base-load entitlements since prospective purchasers face higher-cost and more
volatile-priced gas-fired generation alternatives.

TEXAS GENCO OPTION

Reliant Resources has an option that may be exercised between January 10,
2004 and January 24, 2004 to purchase all of the approximately 81% of the
outstanding shares of Texas Genco common stock that we currently own. The per
share exercise price under the Texas Genco Option will equal the average daily
closing price of Texas Genco common stock on The New York Stock Exchange over
the 30 consecutive trading days out of the last 120 trading days ending January
9, 2004 which result in the highest average closing price. In addition, a
control premium, up to a maximum of 10%, will be added to the price to the
extent a control premium is included in the valuation determination made by the
Texas Utility Commission relating to the market value of Texas Genco. If the
option closing has not occurred within sixteen months of the option exercise,
rights under the option agreement will terminate.

The exercise price formula is based upon the generation asset valuation
methodology in the Texas electric restructuring law that we will use to
calculate the market value of Texas Genco. This market value will be used to
determine the amount CenterPoint Houston will be allowed to recover as
generation related "stranded costs" under the Texas electric restructuring law.
The exercise price is also subject to adjustment based on the difference between
the per share dividends Texas Genco pays to us during the period through the
option closing date and Texas Genco's actual per share earnings during that
period. To the extent Texas Genco's per share dividends are less than its actual
per share earnings during that period, the per share option price will be
increased. To the extent its per share dividends exceed its actual per share
earnings, the per share option price will be reduced.

11

Reliant Resources has agreed that if it exercises its option, it will
purchase from us all notes and other payables owed by Texas Genco to us as of
the option closing date, at their principal amount plus accrued interest.
Similarly, if there are notes or payables owed to Texas Genco by us as of the
option closing date, Reliant Resources will assume those obligations in exchange
for a payment from us of an amount equal to the principal plus accrued interest.

In the event Reliant Resources exercises its option, Reliant Resources and
CenterPoint Energy have agreed to make an election under Section 338(h)(10) of
the Internal Revenue Code with respect to the purchase. As a result of the
Section 338(h)(10) election, CenterPoint Energy will recognize no gain or loss
from the sale of the Texas Genco stock for income tax purposes. Instead, at the
closing of the sale, Texas Genco would be deemed, for income tax purposes, to
have sold all of its assets for an amount generally equal to the value of the
equity of Texas Genco, based upon the purchase price, plus the principal amount
of Texas Genco's indebtedness at the time of the purchase.

Under an agreement with Reliant Resources, we have agreed to maintain
ownership of our approximate 81% interest in Texas Genco following the
distribution until exercise or expiration of the Texas Genco Option. In
addition, Texas Genco has agreed with us that it will not issue additional
equity securities. We have agreed to lend funds to Texas Genco for operating
needs upon request from time to time following the distribution. Texas Genco may
also obtain third-party financing if it so desires. CenterPoint Energy's
separation agreement with Texas Genco, as amended, contains covenants
restricting Texas Genco's ability to:

- merge or consolidate with another entity;

- sell assets;

- enter into long-term agreements and commitments for the purchase of fuel
or the purchase or sale of power outside the ordinary course of business;

- engage in other businesses;

- construct or acquire new generation plants or capacity;

- engage in hedging transactions;

- encumber its assets;

- issue additional equity securities;

- pay special dividends; and

- make certain loans, investments or advances to, or engage in certain
transactions with, its affiliates.

Exercise of the option will be subject to various regulatory approvals,
including Hart-Scott-Rodino antitrust clearance and United States Nuclear
Regulatory Commission (NRC) license transfer approval. In certain circumstances
involving a change in control of us, the time at which the Texas Genco Option
may be exercised and the period over which the exercise price is determined are
accelerated, with corresponding changes to the time and manner of payment of the
exercise price.

FUEL SUPPLIES

Texas Genco relies primarily on natural gas, coal, lignite and uranium to
fuel its generation facilities. The fuel mix of Texas Genco's generating
portfolio, based on actual fuel usage during 2002, was approximately 60% coal
and lignite, 28% natural gas and 12% nuclear. As of December 31, 2002, the fuel
mix of its generating portfolio based on the capacity of its facilities was
approximately 66% natural gas, 29% coal and lignite and 5% nuclear. Based on
Texas Genco's current assumptions regarding the cost and availability of fuel,
plant operation schedules, load growth, load management and the impact of
environmental regulations, it does not expect the mix of fuel used by its
generating portfolio will vary materially during 2003 from prior levels. As a
result of new air emissions standards imposed by federal and state law, Texas
Genco anticipates having higher levels of plant maintenance in 2003 and
subsequent years associated with the installation of environmental equipment.
These factors could affect the mix of its future fuel usage.
12

As a result of the Texas electric restructuring law, most of Texas Genco's
capacity and energy sales are now based on the generation capacity entitlement
auctions described above. Successful bidders in these auctions are able to
dispatch energy from their entitlements within specified operational
constraints. Under the terms of the capacity auctions, successful bidders are
required to make energy payments to cover a variety of charges related to the
fuel and ancillary services scheduled through the auctioned entitlements.

Natural Gas. Texas Genco has long-term natural gas supply contracts with
several suppliers. Substantially all of its long-term natural gas supply
contracts contain pricing provisions based on fluctuating spot market prices. In
2002, 60% of Texas Genco's natural gas requirements were purchased under these
long-term contracts. Texas Genco purchased the remaining 40% of its natural gas
requirements in 2002 on the spot market. Based on current market conditions,
Texas Genco believes it will be able to replace the supplies of natural gas
covered under its long-term contracts when they expire with gas purchased on the
spot market or under new long-term or short-term contracts.

Texas Genco's natural gas requirements are generally more volatile than its
other fuel requirements because it uses natural gas to fuel intermediate, cyclic
and peaking facilities and other more economical fuels to fuel base-load
facilities. Since its intermediate and peaking facilities are dispatched to meet
the variations of demand for electricity, its 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, 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. Although its long-term supply
contracts provide some of the flexibility needed to accommodate variations in
demands for natural gas, Texas Genco relies on its 6.3 billion cubic feet of
leased gas storage facilities, of which 4.2 billion cubic feet is working
capacity, to provide additional flexibility.

Coal and Lignite. In 2002, Texas Genco purchased approximately 80% of the
fuel requirements for its four coal-fired generating units at its W.A. Parish
facility under two fixed-quantity, long-term supply contracts scheduled to
expire in 2010 and 2011. The price for coal was fixed under the first contract
through the end of 2002, after which the price is tied to spot market prices.
The price for coal under the second contract was approximately three times
greater than the spot market prices for coal as of December 31, 2002. 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. The energy payments Texas Genco collects for
capacity entitlements with underlying coal-fired capacity are based on a
pre-established price based on the Texas Utility Commission's forecasted fuel
costs, which incorporate Texas Genco's expected fuel costs under these long-term
coal supply contracts. Texas Genco purchases its remaining coal requirements for
the W.A. Parish facility under short-term contracts. It has long-term rail
transportation contracts with Burlington Northern Santa Fe Railroad and the
Union Pacific Railroad Company to transport coal to the W.A. Parish facility.

Texas Genco obtains the lignite used to fuel the two generating units of
the Limestone facility from a surface mine adjacent to the facility. It owns 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, Texas Genco has obtained its lignite requirements under a
long-term contract on a cost-plus basis. Since July 2002, Texas Genco has
obtained its lignite requirements under an amended long-term contract with the
owner/operator of the mine 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-sulphur Western coal. Texas Genco expects the
lignite reserves will be sufficient to provide all of the lignite requirements
of this facility through 2015. The energy payments Texas Genco collects for
capacity entitlements with underlying lignite-fired capacity are based on a
pre-established price based on the Texas Utility Commission's forecasted fuel
costs, which incorporate Texas Genco's expected costs under its lignite supply
contract.

13

During 2002, Texas Genco conducted a successful test burn of Wyoming coal
at the Limestone facility. Texas Genco anticipates using a blend of lignite and
Wyoming coal to fuel its Limestone facility beginning in 2003 as a component of
its NOx control strategy. A fuel unloading and handling system was installed at
the Limestone facility to accommodate the delivery of Wyoming coal. Texas Genco
expects that it will obtain Wyoming coal through spot and long-term market
priced contracts. Texas Genco's 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. Texas Genco is a 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). Management believes that sufficient capacity for
nuclear fuel supplies and processing exists to permit normal operations of the
South Texas Project nuclear generating units. The energy payments Texas Genco
collects for capacity entitlements with underlying nuclear capacity are based on
a pre-established price based on the Texas Utility Commission's forecasted
costs, which incorporate Texas Genco's expected costs under these contracts.

Fuel Pipeline. Texas Genco owns an 87-mile fuel pipeline that can
transport either fuel oil or gas. As part of its system, it owns over five
million barrels of oil storage capacity that can supply fuel oil to its Cedar
Bayou, Greens Bayou, S.R. Bertron and T.H. Wharton plants. For natural gas
supply, its pipeline is connected to six of its generation facilities and is
interconnected with several of its suppliers. Texas Genco's pipeline provides it
with added flexibility in managing the fuel supply requirements of its
generation facilities.

CUSTOMERS

Since January 1, 2002, Texas Genco has sold power to wholesale purchasers,
including retail electric providers, at unregulated rates through its capacity
auctions. In addition to retail electric providers, Texas Genco's customers in
the ERCOT market include municipal utilities, electric co-operatives, power
trading organizations and other power generating companies. Texas Genco is also
a significant provider to the ancillary services market operated by the ERCOT
ISO. Texas Genco expects its mix of customers and the mix of participants will
change significantly as the ERCOT market evolves from one dominated by
vertically integrated electric utilities to one with utility-affiliated retail
electric providers, new-entrant retail electric providers, greater participation
by unregulated energy merchants, and more generation capacity from independent
generation companies. Sales to Reliant Resources represented approximately 66%
of Texas Genco's total revenues in 2002.

COMPETITION

The ERCOT market is highly competitive. Texas Genco has approximately 80
competitors, which include generation companies affiliated with Texas-based
utilities, independent power producers, municipal or co-operative generators and
wholesale power marketers. These competitors will compete with Texas Genco and
each other by buying and selling wholesale power in the ERCOT market, entering
into bilateral contracts and/or selling to aggregated retail customers. At
December 31, 2002, Texas Genco's facilities provided approximately 20% of the
aggregate net generating capacity serving the ERCOT market. Texas Genco's
competition is based primarily on price but it also may compete based on product
flexibility. A number of Texas Genco's 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 Texas
Genco's large diversified portfolio of generating facilities can provide. Texas
Genco believes 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. There is
currently a surplus of generating capacity in the ERCOT market, and we expect
the market for wholesale power to be highly competitive. For more information on
competition in the ERCOT market, please read "Risk Factors -- Risk Factors
Affecting the Results of Our Electric Generation Business" below.

14

In October 2002, Texas Genco announced its plan to remove temporarily from
service, or mothball, approximately 3,400 MW of its gas-fired generating units
through at least May 2003. Texas Genco decided to mothball these units because
of unfavorable market conditions within the ERCOT market, including a surplus of
generating capacity and a lack of bids for the output of these units in its
previous capacity auctions. The ERCOT ISO has determined that the mothballed
units are not required to remain in service for reliability reasons through May
2003. Based upon the results of Texas Genco's recent capacity auctions, we will
return some or all of the mothballed facilities to service during the summer of
2003.

NATURAL GAS DISTRIBUTION

Through CERC, we engage in intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers in
Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas and some
non-rate regulated retail gas marketing operations. CERC currently conducts
intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers through three unincorporated
divisions: CenterPoint Energy Arkla (Arkla), CenterPoint Energy Entex (Entex)
and CenterPoint Energy Minnegasco (Minnegasco). These operations are regulated
as natural gas utility operations in the jurisdictions served by these
divisions.

- Arkla. Arkla provides natural gas distribution services in over 245
communities in Arkansas, Louisiana, Oklahoma and Texas. The largest
metropolitan areas served by Arkla are Little Rock, Arkansas and
Shreveport, Louisiana. In 2002, approximately 65% of Arkla's total
throughput was attributable to retail sales of natural gas and
approximately 35% was attributable to transportation services.

- Entex. Entex provides natural gas distribution services in over 500
communities in Louisiana, Mississippi and Texas. The largest metropolitan
area served by Entex is Houston. In 2002, approximately 95% of Entex's
total throughput was attributable to retail sales of natural gas and
approximately 5% was attributable to transportation services.

- Minnegasco. Minnegasco provides natural gas distribution services in
over 240 communities in Minnesota. The largest metropolitan area served
by Minnegasco is Minneapolis. In 2002, approximately 93% of Minnegasco's
total throughput was attributable to retail sales of natural gas and
approximately 7% was attributable to transportation services.
Additionally, Minnegasco provides heating, ventilating and air
conditioning (HVAC) equipment and appliance repair services, HVAC and
hearth equipment sales and home security monitoring which are unregulated
services.

The demand for intrastate natural gas sales to, and natural gas
transportation for, residential, commercial and industrial customers is
seasonal. In 2002, approximately 60% of the total throughput of CERC's natural
gas distribution business occurred in the first and fourth quarters. These
patterns reflect the higher demand for natural gas for heating purposes during
those periods.

COMMERCIAL AND INDUSTRIAL SALES

CERC's commercial and industrial sales group (C&I group) provides
comprehensive natural gas products and services to commercial and industrial
customers in the Gulf Coast and Midwestern regions of the United States. Most
services provided by the C&I group are not subject to rate regulation.
Subsidiaries making up the C&I group typically enter into fixed-volume forward
sales commitments with customers with contract lengths typically ranging from
one day to three years. Such sales are generally made on a monthly index price
basis, but are also made on daily index and fixed price bases. In the case of
fixed price commitments for delivery in future periods, the C&I group is exposed
to risks resulting from changes in market prices of natural gas during the term
of the contract. The C&I group engages in hedging activities with unaffiliated
third parties in order to mitigate this risk. In 2002, approximately 94% of the
C&I group's total throughput was attributable to natural gas sales; the
remainder was attributable to transportation services that the C&I group
provides for affiliates and third parties. For more information on the C&I
group's derivative instruments and hedging activities, please read "Quantitative
and Qualitative Disclosures About Market

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Risk -- Commodity Price Risk From Non-Trading Activities" in Item 7A of this
report and Note 5 to our consolidated financial statements.

SUPPLY AND TRANSPORTATION

Arkla. In 2002, Arkla purchased approximately 56% of its natural gas
supply pursuant to third-party term contracts with terms ranging from three
months to one year, 29% of its natural gas supply from Reliant Energy Services,
Inc. (Reliant Energy Services), a subsidiary of Reliant Resources and our former
affiliate, under a contract expiring in March 2003 and 15% on the spot market.
Arkla's major third-party natural gas suppliers in 2002 included Oneok Gas
Marketing Company, BP Energy Company, Aquila Energy Marketing and Cross Timbers
Energy Services. Arkla transports substantially all of its natural gas supplies
under contracts with our pipeline subsidiaries.

Entex. In 2002, Entex purchased virtually all of its natural gas supply
pursuant to term contracts, with terms varying from one to five years. Entex's
major third-party natural gas suppliers in 2002 included AEP Gas Marketing,
Kinder Morgan Texas Pipeline, L.P., Gulf Energy Marketing, Island Fuel Trading
and Entergy Koch Trading. Entex transports its natural gas supplies on both
interstate and intrastate pipelines under long-term contracts with terms varying
from one to five years.

Minnegasco. In 2002, Minnegasco purchased approximately 74% of its natural
gas supply pursuant to term contracts, with terms varying from five months to
ten years, with more than 20 different suppliers. Minnegasco purchased the
remaining 26% on the daily or spot market. Most of the natural gas volumes under
long-term contracts are committed under terms providing for delivery during the
winter heating season, which extends from November through March. Minnegasco
purchased approximately 60% of its natural gas requirements from three
third-party suppliers in 2002: Tenaska Marketing Ventures, BP Canada Energy
Marketing and Mirant Americas Energy Marketing. Purchases from Reliant Energy
Services represented 10% of Minnegasco's total natural gas purchases in 2002.
Minnegasco transports its natural gas supplies through various interstate
pipelines under long-term contracts with terms varying from one to five years.

Generally, the regulations of the states in which CERC's natural gas
distribution business operates allow it to pass through changes in the costs of
natural gas to its customers through purchased gas adjustment provisions in its
tariffs. There is, however, a timing difference between CERC's purchases of
natural gas and the ultimate recovery of these costs. Consequently, CERC may
incur carrying costs as a result of this timing difference that are not
recoverable from its customers.

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

Minnegasco owns and operates an underground storage facility with a
capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.1 Bcf
available for use during a normal heating season and a maximum daily withdrawal
rate of 50 million cubic feet (MMcf). Minnegasco also owns nine propane-air
plants with a total capacity of 204 MMcf per day and on-site storage facilities
for 12 million gallons of propane (1.0 Bcf gas equivalent). Minnegasco owns a
liquefied natural gas facility with a 12 million-gallon liquefied natural gas
storage tank (1.0 Bcf gas equivalent) and a send-out capability of 72 MMcf per
day.

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

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ASSETS

As of December 31, 2002, CERC owned approximately 61,000 linear miles of
gas distribution mains, varying in size from one-half inch to 24 inches in
diameter. Generally, in each of the cities, towns and rural areas served by
CERC, it owns the underground gas mains and service lines, metering and
regulating equipment located on customers' premises and the district regulating
equipment necessary for pressure maintenance. With a few exceptions, the
measuring stations at which CERC receives gas are owned, operated and maintained
by others, and its distribution facilities begin at the outlet of the measuring
equipment. These facilities, including odorizing equipment, are usually located
on the land owned by suppliers.

COMPETITION

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

PIPELINES AND GATHERING

Our Pipelines and Gathering business segment operates two interstate
natural gas pipelines as well as gas gathering facilities and also provides
pipeline services. Our pipeline operations are primarily conducted by two wholly
owned interstate pipeline subsidiaries which provide gas transportation and
storage services primarily to industrial customers and local distribution
companies. Our gathering and pipeline services operations are conducted by a
wholly owned gas gathering subsidiary and a wholly owned pipeline services
subsidiary. Through our gas gathering subsidiary, we provide natural gas
gathering and related services, including related liquids extraction and other
well operating services. Through our pipeline services subsidiary, we provide
pipeline project management and facility operation services to affiliates and
third parties.

In 2002, approximately 27% of our total operating revenues from pipelines
and gathering was attributable to services provided to Arkla, and approximately
11% was attributable to services to Laclede Gas Company (Laclede), an
unaffiliated distribution company that provides natural gas utility service to
the greater St. Louis metropolitan area in Illinois and Missouri. An additional
8% of our operating revenues from pipelines and gathering was attributable to
the transportation of gas marketed by Reliant Energy Services. Services to Arkla
and Laclede are provided under several long-term firm storage and transportation
agreements. Contracts for firm transportation in Arkla's major service areas are
currently scheduled to expire in 2005. An agreement to extend the existing
service relationship with Laclede for a five-year period was entered into in
February 2002.

Our pipelines and gathering business operations may be affected by changes
in the demand for natural gas, the available supply and relative price of
natural gas in the Midcontinent and Gulf Coast natural gas supply regions and
general economic conditions.

ASSETS

We own and operate approximately 8,200 miles of gas transmission lines
primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and
Texas. We also own and operate six natural gas storage fields with a combined
daily deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 64.3 Bcf. We also own a 10% interest, with Gulf South
Pipeline Company, LP, in the Bistineau storage facility with 73.8 Bcf of working
gas capacity and approximately 1.1 Bcf per day of deliverability. Our storage
capacity in the Bistineau facility is 8 Bcf of working gas with 100 MMcf per day
of deliverability. Most of our storage operations are in north Louisiana and
Oklahoma. We also own and operate approximately 4,300 miles of gathering
pipelines that collect gas from more than 300 separate systems located in major
producing fields in Arkansas, Louisiana, Oklahoma and Texas.

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COMPETITION

Our pipelines and gathering business competes with other interstate and
intrastate pipelines and gathering companies in the transportation and storage
of natural gas. The principal elements of competition among pipelines are rates,
terms of service, and flexibility and reliability of service. Our pipelines and
gathering business competes indirectly with other forms of energy available to
its customers, including electricity, coal and fuel oils. The primary
competitive factor is price. Changes in the availability of energy and pipeline
capacity, the level of business activity, conservation and governmental
regulations, the capability to convert to alternative fuels, and other factors,
including weather, affect the demand for natural gas in areas we serve and the
level of competition for transportation and storage services. In addition,
competition for our gathering operations is impacted by commodity pricing levels
because of their influence on the level of drilling activity.

OTHER OPERATIONS

Our Other Operations business segment includes our Latin America
operations, office buildings and other real estate used in our business
operations, district cooling in the central business district in downtown
Houston, energy management services and other corporate operations which support
all of our business operations.

In February 2003, we sold our interest in Argener, a cogeneration facility
in Argentina, for $23.1 million. The carrying value of this investment was
approximately $11 million as of December 31, 2002.

REGULATION

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

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

We are a registered public utility holding company under the 1935 Act.
Prior to the Restructuring, Reliant Energy was a public utility holding company
that was exempt from registration under the 1935 Act. After the Restructuring,
an exemption was no longer available for the resulting corporate structure.

As a registered public utility holding company, we and our subsidiaries are
subject to a comprehensive regulatory scheme imposed by the SEC in order to
protect customers, investors and the public interest. Although the SEC does not
regulate rates and charges under the 1935 Act, it does regulate the structure,
financing, lines of business and internal transactions of public utility holding
companies and their system companies. In order to obtain financing, acquire
additional public utility assets or stock, or engage in other significant
transactions, we are generally required to obtain approval from the SEC under
the 1935 Act.

Prior to the Restructuring, we and Reliant Energy obtained an order from
the SEC that authorized the Restructuring transactions, including the Reliant
Resources Distribution, and granted us certain authority with respect to system
financing, dividends and other matters. The financing authority granted by that
order will expire on June 30, 2003, and we must obtain a further order from the
SEC under the 1935 Act, related, among other things, to the financing activities
of us and our subsidiaries subsequent to June 30, 2003.

In a July 2002 order, the SEC limited the aggregate amount of external
borrowings of Texas Genco, CenterPoint Houston and CERC to $500 million, $3.55
billion and $2.7 billion, respectively. The ability of each of Texas Genco,
CenterPoint Houston and CERC to pay dividends is restricted by the SEC's
requirement that common equity as a percentage of total capitalization must be
at least 30% after the payment of any dividend. In addition, the order restricts
our ability to pay dividends out of capital accounts to the extent current or
retained earnings are insufficient for those dividends. Under these
restrictions, we, Texas Genco, CenterPoint Houston and CERC are permitted to pay
dividends in excess of the respective current or retained earnings in an amount
up to $200 million, $100 million, $200 million and $100 million, respectively.

18

In 2002 CERC obtained authority from each state in which such authority was
required to restructure CERC in a manner that would allow us to claim an
exemption from registration under the 1935 Act. We have concluded that
restructuring CERC would not be beneficial to us and have elected to remain a
registered holding company under the 1935 Act. Based on that conclusion, we
believe we will be required to form a service company to provide centralized
services to our various operating subsidiaries, and we must obtain SEC approval
for the formation of that company. Service companies typically are required for
registered public utility holding companies, but the SEC granted us a temporary
exemption from that requirement in its July 2002 order.

FEDERAL ENERGY REGULATORY COMMISSION

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

Our natural gas pipeline subsidiaries may periodically file applications
with the FERC for changes in their generally available maximum rates and charges
designed to allow them to recover their costs of providing service to customers
(to the extent allowed by prevailing market conditions), including a reasonable
rate of return. These rates are normally allowed to become effective after a
suspension period and, in some cases, are subject to refund under applicable law
until such time as the FERC issues an order on the allowable level of rates.

In February 2000, the FERC issued Order No. 637, which introduced several
measures to increase competition for interstate pipeline transportation
services. Order No. 637 authorizes interstate pipelines to propose
term-differentiated and peak/off-peak rates, and requires pipelines to make
tariff filings to expand pipeline service options for customers. Both natural
gas pipeline subsidiaries made two Order No. 637 compliance filings in 2000, and
both obtained uncontested settlements filed with the FERC in 2001. In 2002, the
FERC issued orders accepting both settlements, subject to certain modifications.
The FERC has denied requests for rehearing and clarification of the orders and
has accepted, with modification, the compliance tariff filed under one of the
orders and ordered additional revised tariff sheets to be filed under the other
order.

CenterPoint Houston is not a "public utility" under the Federal Power Act
and therefore is not generally regulated by the FERC, except in limited
circumstances. Texas Genco is not a "public utility" under the Federal Power Act
and its sales are all within ERCOT; Texas Genco therefore is not regulated by
the FERC.

STATE AND LOCAL REGULATION

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

CenterPoint Houston conducts its operations pursuant to a certificate of
convenience and necessity issued by the Texas Utility Commission that covers its
present service area and facilities. In addition, CenterPoint Houston holds
non-exclusive franchises from the incorporated municipalities in its service
territory. These franchises give CenterPoint Houston the right to operate its
transmission and distribution system within the streets and public ways of these
municipalities for the purpose of delivering electric service to the
municipality, its residents and businesses. None of these franchises expires
before 2007.

Historically, Reliant Energy paid the incorporated municipalities in its
service territory a franchise fee based on a formula that was usually a
percentage of gross receipts received from electricity sales for consumption
within each municipality. CenterPoint Houston has become responsible for Reliant
Energy's

19

obligations under these franchise arrangements although the method for
calculating such fees was changed by the Texas electric restructuring law
effective January 1, 2002. We expect the franchise fees payable to remain
consistent with the historical fees paid by Reliant Energy.

For additional information regarding the Texas electric restructuring law,
retail competition in Texas and its application to our operations and structure,
please read "Our Business -- Overview -- The Texas Electric Restructuring Law"
and "Our Business -- Electric Generation" above.

Transmission and Distribution Rates. All retail electric providers in
CenterPoint Houston's service area pay the same rates and other charges for
transmission and distribution services.

CenterPoint Houston's distribution rates charged to retail electric
providers are generally based on amounts of energy delivered. Transmission rates
charged to other distribution companies are based on amounts of energy
transmitted under "postage stamp" rates that do not vary with the distance the
energy is being transmitted. All distribution companies in ERCOT pay CenterPoint
Houston the same rates and other charges for transmission services. The current
transmission and distribution rates for CenterPoint Houston have been in effect
since January 1, 2002, when electric competition began. This regulated delivery
charge includes the transmission and distribution rate (which includes costs for
nuclear decommissioning and municipal franchise fees), a system benefit fund fee
imposed by the Texas electric restructuring law, a transition charge associated
with securitization of regulatory assets and an excess mitigation credit imposed
by the Texas Utility Commission.

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

Substantially all of CERC's retail natural gas sales are subject to
traditional cost-of-service regulation at rates regulated by the relevant state
public service commissions and, in Texas, by the Railroad Commission of Texas
(Railroad Commission) and municipalities CERC serves.

Arkansas Rate Case. In November 2001, Arkla filed a rate request in
Arkansas seeking rates to yield approximately $47 million in additional annual
gross revenue. In August 2002, a settlement was approved by the Arkansas Public
Service Commission (APSC) which is expected to result in an increase in base
rates of approximately $32 million annually. In addition, the APSC approved a
gas main replacement surcharge which is expected to provide $2 million of
additional gross revenue in 2003 and additional amounts in subsequent years. The
new rates included in the final settlement were effective with all bills
rendered on and after September 21, 2002.

Oklahoma Rate Case. In May 2002, Arkla filed a request in Oklahoma to
increase its base rates by $13.7 million annually. In December 2002, a
settlement was approved by the Oklahoma Corporation Commission which is expected
to result in an increase in base rates of approximately $7.3 million annually.
The new rates included in the final settlement were effective with all bills
rendered on and after December 29, 2002.

City of Tyler, Texas, Gas Costs Review. By letter to Entex dated July 31,
2002, the City of Tyler, Texas, forwarded various computations of what it
believes to be excessive costs ranging from $2.8 million to $39.2 million for
gas purchased by Entex for resale to residential and small commercial customers
in that city under supply agreements in effect since 1992. Entex's gas costs for
its Tyler system are recovered from customers pursuant to tariffs approved by
the city and filed with both the city and the Railroad Commission. Pursuant to
an agreement, on January 29, 2003, Entex and the city filed a Joint Petition for
Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission.
The Joint Petition requests that the Railroad Commission determine whether Entex
has properly and lawfully charged and collected for gas service to its
residential and commercial customers in its Tyler distribution system for the
period beginning November 1, 1992, and ending October 31, 2002. The Company
believes that all costs for Entex's Tyler distribution system

20

have been properly included and recovered from customers pursuant to Entex's
filed tariffs and that the city has no legal or factual support for the
statements made in its letter.

NUCLEAR REGULATORY COMMISSION

Texas Genco is 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.

Texas Genco 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 a nuclear
decommissioning trust. The beneficial ownership in the nuclear decommissioning
trust is held by Texas Genco, as the 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 trust 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 Texas Genco's obligations relating to
the decommissioning of the South Texas Project. We are contractually obligated
to indemnify Texas Genco from and against any obligations relating to the
decommissioning not otherwise satisfied through collections by CenterPoint
Houston.

DEPARTMENT OF TRANSPORTATION

In December 2002, Congress enacted the Pipeline Safety Improvement Act of
2002. This legislation applies to our interstate pipelines as well as our
intra-state pipelines and local distribution companies. The legislation imposes
several requirements related to ensuring pipeline safety and integrity. It
requires companies to assess the integrity of their pipeline transmission and
distribution facilities in areas of high population concentration and further
requires companies to perform remediation activities in accordance with the
requirements of the legislation, over a 10-year period.

In January 2003, the U.S. Department of Transportation published a notice
of proposed rulemaking to implement provisions of the legislation. The
Department of Transportation is expected to issue final rules by the end of
2003.

While we anticipate that increased capital and operating expenses will be
required to comply with the legislation, we will not be able to quantify the
level of spending required until the Department of Transportation's final rules
are issued.

ENVIRONMENTAL MATTERS

GENERAL ENVIRONMENTAL ISSUES

We are subject to numerous federal, state and local requirements relating
to the protection of the environment and the safety and health of personnel and
the public. These requirements relate to a broad range of our activities,
including the discharge of pollutants into air, water, and soil; the proper
handling of solid, hazardous and toxic materials; and waste, noise, and safety
and health standards applicable to the workplace. In order to comply with these
requirements, we will spend substantial amounts from time to time to construct,
modify and retrofit equipment, acquire air emission allowances for operation of
our facilities, and to clean up or decommission disposal or fuel storage areas
and other locations as necessary.

21

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.

Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980, or CERCLA, owners and operators of facilities from which
there has been a release or threatened release of hazardous substances, together
with those who have transported or arranged for the disposal of those
substances, are liable for:

- the costs of responding to that release or threatened release; and

- the restoration of natural resources damaged by any such release.

We are not aware of any liabilities under CERCLA that would have a material
adverse effect on us, our financial position, results of operations or cash
flows.

AIR EMISSIONS

As part of the 1990 amendments to the Federal Clean Air Act, requirements
and schedules for compliance were developed for attainment of health-based
standards. As part of this process, standards for NOx emissions, a product of
the combustion process associated with power generation and natural gas
compression, are being developed or have been finalized. The Texas Commission on
Environmental Quality standards require reduction of emissions from Texas
Genco's power generating units and some of our natural gas compression
facilities. As of December 31, 2002, Texas Genco had invested $551 million for
NOx emission controls, and it is planning to make expenditures of at least $131
million in the years 2003 through 2005, with possible additional expenditures
after 2005. NOx control estimates for 2006 and 2007 have not been finalized. The
Texas Utility Commission has initially approved Texas Genco's NOx emission
reduction plan in the amount of $699 million as the most cost-effective
alternative in achieving compliance with applicable air quality standards for
these generation facilities. Texas Genco is required to fund NOx reduction
projects for pipelines in East Texas at a cost of $16.2 million, which is
included in the amounts described above.

The Environmental Protection Agency (EPA) has announced its determination
to regulate hazardous air pollutants, including mercury, from coal-fired and
oil-fired steam electric generating units under Section 112 of the Clean Air
Act. The EPA plans to develop Maximum Achievable Control Technology (MACT)
standards for these types of units as well as for turbines, engines and
industrial boilers. The rulemaking for coal and oil-fired steam electric
generating units must be completed by December 2004. Compliance with the rules
will be required within three years thereafter. The MACT standards that will be
applicable to the Texas Genco units cannot be predicted at this time and may
adversely impact Texas Genco's operations. The rulemaking for turbines is
expected to be complete in August 2003, and for engines and industrial boilers
in early February 2004. Based on the rules currently proposed, management does
not anticipate a materially adverse impact in interstate pipeline operations or
Texas Genco's operations.

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. Since this withdrawal, Congress has
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
Texas Genco.

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

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

In July 2002, the White House sent to Congress a bill proposing the Clear
Skies Act of 2002. The Act is designed to achieve long-term reductions of
multiple pollutants produced from fossil fuel-fired power plants. The Act
targets reductions averaging 70% for sulfur dioxide, NOx and mercury emissions.
If approved by the United States Congress, the Act 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 like Texas Genco would be affected by the adoption of this program,
or other legislation currently pending in the United States Congress addressing
similar issues. To comply with such programs, Texas Genco and other regulated
entities could pursue a variety of strategies including the installation of
pollution controls, the purchase of emission allowances or the curtailment of
operations.

WATER ISSUES

In July 2000, the EPA issued final rules for the implementation of the
total maximum daily load (TMDL) program. The goal of the TMDL program is to
restore waters designated as impaired by identifying and restricting the loading
of pollutants contributing to the impairment. While we are not aware of any of
our facilities being directly affected by the current TMDL developments, there
is the potential that the establishment of TMDLs may eventually result in more
stringent discharge limits in our plant discharge permits. Such limits could
require our facilities to install additional water treatment facilities or
equipment, modify operational practices or implement other water quality
improvement measures. In October 2001, the EPA signed a final rule delaying the
effective date of the TMDL rule until April 30, 2003. In December 2002, the EPA
published a proposed rulemaking that would withdraw the July 2000 rule.

In April 2002, the EPA proposed rules under Section 316(b) of the Clean
Water Act relating to the design and operation of cooling water intake
structures. This proposal is the second of three current phases of rulemaking
dealing with Section 316(b) and generally would affect existing facilities that
use significant quantities of cooling water. Under the amended court deadline,
the EPA is to issue final rules for these Phase II facilities by February 2004.
While the requirements of the final rule cannot be predicted at this time,
significant capital expenditures by Texas Genco could be required. We anticipate
that substantial comments and, if necessary, litigation will be filed by
affected parties to attempt to achieve an acceptable final regulation.

The EPA and the State of Texas periodically update water quality standards
in response to new toxicological data and the development of enhanced analytical
techniques that allow lower detection levels. The lowering of water quality
criteria for parameters such as arsenic, mercury and selenium could affect
generating facility discharge limitations and require our facilities to install
additional treatment equipment.

LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION

Asbestos and Other. 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

23

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.

We have been named, along with numerous others, as a defendant in a number
of lawsuits filed by a large number of individuals who claim injury due to
exposure to asbestos while working at sites along the Texas Gulf Coast. Most of
these claimants have been 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 like those received may be asserted in the future, and we intend to
continue our practice of vigorously contesting claims that we do not consider to
have merit. Although their ultimate outcome cannot be predicted at this time, we
do not believe, based on our experience to date, that these matters, either
individually or in the aggregate, will have a material adverse effect on our
financial position, results of operations or cash flows.

Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, remediation has been
completed on two sites, other than ongoing monitoring and water treatment. There
are five remaining sites in CERC's Minnesota service territory, two of which
CERC believes it neither owned or operated, and for which CERC believes it has
no liability.

At December 31, 2002, CERC had accrued $19 million for remediation of the
Minnesota sites. At December 31, 2002, the estimated range of possible
remediation costs was $8 million to $44 million based on remediation continuing
for 30 to 50 years. The cost estimates are based on studies of a site or
industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. CERC has an environmental expense tracker
mechanism in its rates in Minnesota. CERC has collected $12 million at December
31, 2002 to be used for future environmental remediation.

CERC has received notices from the United States Environmental Protection
Agency and others regarding its status as a PRP for other sites. Based on
current information, the Company has not been able to quantify a range of
environmental expenditures for potential remediation expenditures with respect
to other MGP sites.

Hydrocarbon Contamination. In August 2001, a number of Louisiana residents
who live near the Wilcox Aquifer filed suit in the 1st Judicial District Court,
Caddo Parish, Louisiana against CERC and others. The suit alleges that CERC and
the other defendants allowed or caused hydrocarbon or chemical contamination of
the Wilcox Aquifer, which lies beneath property owned or leased by the
defendants and is the sole or primary drinking water aquifer in the area. The
monetary damages sought are unspecified. In April 2002, a separate suit with
identical allegations against the same parties was filed in the same court.
Additionally, in January 2003, a third suit with similar allegations was filed
against the same parties in the 26th Judicial District Court, Bossier Parish,
Louisiana.

Mercury Contamination. Like similar companies, our pipeline and natural
gas distribution operations have in the past employed elemental mercury in
measuring and regulating equipment. It is possible that small amounts of mercury
may have been spilled in the course of normal maintenance and replacement
operations and that these spills may have contaminated the immediate area around
the meters with elemental mercury. We have found this type of contamination in
the past, and we have conducted remediation at sites found to be contaminated.
Although we are not aware of additional specific sites, it is possible that
other contaminated sites may exist and that remediation costs may be incurred
for these sites. Although the total amount of these costs cannot be known at
this time, based on our experience and that of others in the natural gas
industry to date and on the current regulations regarding remediation of these
sites, we believe that the cost of any remediation of these sites will not be
material to our financial position, results of operations or cash flows.

24

EMPLOYEES

As of December 31, 2002, we had 12,019 full-time employees. The following
table sets forth the number of our employees by business segment:

The number of our employees who were represented by unions or other
collective bargaining groups as of December 31, 2002 include (i) Electric
Transmission & Distribution, 1,549; (ii) Electric Generation, 1,102; (iii)
Natural Gas Distribution, 1,552; and (iv) Other Operations, 314. Collective
bargaining agreements covering the Electric Transmission & Distribution,
Electric Generation and some Natural Gas Distribution employees expire in 2003.

EXECUTIVE OFFICERS
(AS OF MARCH 1, 2003)

DAVID M. MCCLANAHAN has been President and Chief Executive Officer and a
director of CenterPoint Energy since September 2002. He served as Vice Chairman
of Reliant Energy from October 2000 to September 2002 and as President and Chief
Operating Office of Reliant Energy's Delivery Group from April 1999 until
October 2000. He also served as the President and Chief Operating Officer of
Reliant Energy HL&P, the electric utility division of Reliant Energy, from 1997
to 1999. He has served in various executive capacities with Reliant 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, American Gas Association and
Interstate Natural Gas Association of America.

SCOTT E. ROZZELL has served as 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. Before joining Reliant Energy in 2001,
Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P.

STEPHEN C. SCHAEFFER has served as Executive Vice President and Group
President, Gas Distribution Sales and Service, since December 2002. From
September 2002 to December 2002, he served as Executive

25

Vice President-Government and Regulatory Affairs of CenterPoint Energy. Prior to
this position, Mr. Schaeffer served as Senior Vice President-Regulatory of
Reliant Energy beginning in 1999. From 1997 to 1998, he served as Executive Vice
President-Retail Energy Regulation of Reliant Energy's Retail Energy Group. He
has served in various executive capacities with Reliant Energy since 1989.

GARY L. WHITLOCK has served as 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.

JAMES S. BRIAN has served as 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. Mr. Brian has served in various executive
capacities with Reliant Energy since 1983.

THOMAS R. STANDISH has served as President and Chief Operating Officer of
CenterPoint Houston since August 2002. He served as President and Chief
Operating Officer for both electricity and natural gas for Reliant Energy's
Houston area from 1999 until August 2002, and as Senior Vice President of
Distribution Customer Service for Reliant Energy HL&P from 1997 to 1999. Mr.
Standish has served in various executive capacities with Reliant Energy since
1993.

DAVID G. TEES has served as President and Chief Executive Officer of Texas
Genco since August 2002. 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 to 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 a director of the South Texas Project Nuclear Operating Company.

RISK FACTORS

RISK FACTORS ASSOCIATED WITH FINANCIAL CONDITION AND OTHER RISKS

IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY
TO FUND FUTURE CAPITAL EXPENDITURES AND REFINANCE EXISTING INDEBTEDNESS COULD
BE LIMITED.

As a result of several events occurring in 2001 and 2002, including the
September 11, 2001 terrorist attacks, the bankruptcy of Enron Corp., the
downgrading of our credit ratings and the credit ratings of several energy
companies, the general downturn in the utility industry and the unusual
volatility in the U.S. financial markets, the availability and cost of capital
for our business have been adversely affected. If we are unable to obtain
external financing to meet our future capital requirements on terms that are
acceptable to us, our financial condition and future results of operations could
be materially adversely affected. As of December 31, 2002, we had $11.1 billion
of outstanding indebtedness and trust preferred securities, including $1.0
billion of debt that must be refinanced in 2003, after giving effect to the
amendment and extension of our $3.85 billion credit facility in February 2003.
In addition, the capital constraints currently impacting our businesses may
require our future indebtedness to include terms that are more restrictive or
burdensome than those of our current indebtedness. These terms may negatively
impact our ability to operate our business or severely restrict or prohibit
distributions from our subsidiaries. The success of our future financing efforts
may depend, at least in part, on:

- general economic and capital market conditions;

- credit availability from financial institutions and other lenders;

- investor confidence in us and the market in which we operate;

26

- maintenance of acceptable credit ratings;

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

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

- our exposure to Reliant Resources in connection with its indemnification
obligations arising in connection with its separation from us;

- provisions of relevant tax and securities laws; and

- our ability to obtain approval of specific financing transactions under
the 1935 Act.

As of December 31, 2002, our CenterPoint Houston subsidiary had $1.8
billion of general mortgage bonds outstanding. It may issue additional general
mortgage bonds on the basis of retired bonds, 70% of property additions or cash
deposited with the trustee. Although approximately $900 million of additional
general mortgage bonds could be issued on the basis of property additions as of
December 31, 2002, CenterPoint Houston has agreed contractually to limit
incremental secured debt to $300 million. In addition, we are contractually
prohibited, subject to certain exceptions, from issuing additional first
mortgage bonds.

Our current credit ratings are discussed in "Management's Discussion and
Analysis of Financial Condition and Results of Operations -- Liquidity and
Capital Resources -- Future Sources and Uses of Cash -- Impact on Liquidity of a
Downgrade in Credit Ratings" in Item 7 of this report. We cannot assure you that
these credit ratings will remain in effect for any given period of time or that
one or more of these ratings will not be lowered or withdrawn entirely by a
rating agency. We note that these credit ratings are not recommendations to buy,
sell or hold our securities. Each rating should be evaluated independently of
any other rating. Any future reduction or withdrawal of one or more of our
credit ratings could have a material adverse impact on our ability to access
capital on acceptable terms.

AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON
DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MAKE PAYMENTS ON ANY OF OUR DEBT
SECURITIES, AND PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD
LIMIT THE AMOUNT OF THOSE DISTRIBUTIONS.

We derive substantially all our operating income from, and hold
substantially all our assets through, our subsidiaries. As a result, we will
depend on distributions from our subsidiaries in order to meet our payment
obligations under any debt securities and our other obligations. In general,
these subsidiaries are separate and distinct legal entities and will have no
obligation to pay any amounts due on our debt securities or to provide us with
funds for our payment obligations, whether by dividends, distributions, loans or
otherwise. In the case of medium-term notes, which are in the aggregate
principal amount of $150 million and mature in April 2003, if we were to become
the subject of a voluntary or involuntary bankruptcy proceeding, the trustee for
the medium-term notes could seek the payment of an amount equal to the principal
amount of the medium-term notes from CenterPoint Houston under the first
mortgage bonds that CenterPoint Houston issued as collateral for the medium-term
notes. In addition, provisions of applicable law, such as those limiting the
legal sources of dividends and those under the 1935 Act, limit their ability to
make payments or other distributions to us, and they could agree to contractual
restrictions on their ability to make distributions. For a discussion of
restrictions under the 1935 Act, please read "Regulation -- Public Utility
Holding Company Act of 1935" below.

Our right to receive any assets of any subsidiary, and therefore the right
of our creditors to participate in those assets, will be effectively
subordinated to the claims of that subsidiary's creditors, including trade
creditors. In addition, even if we were a creditor of any subsidiary, our rights
as a creditor would be subordinated to any security interest in the assets of
that subsidiary and any indebtedness of the subsidiary senior to that held by
us.

27

THE ISSUANCE OF WARRANTS PURSUANT TO THE TERMS OF OUR AMENDED BANK FACILITY
COULD RESULT IN SUBSTANTIAL DILUTION TO OUR SHAREHOLDERS.

Subject to SEC approval under the 1935 Act, we have agreed to provide the
bank syndicate for our $3.85 billion bank credit facility warrants to purchase
up to 10% of our common stock. The exercise price of these warrants will be the
greater of $6.56 per share or 110% of the closing price on the New York Stock
Exchange on the date the warrants are issued. The exercise of these warrants
could cause substantial dilution to our shareholders. The warrants would not be
exercisable for a year after issuance but would remain outstanding for four
years. We have the right to cause some or all of the warrants to be extinguished
by making certain prepayments under the bank facility during 2003. To the extent
that we reduce the bank facility by up to $400 million on or before May 28,
2003, up to half of the warrants will be extinguished on a basis proportionate
to the reduction in the credit facility. To the extent such warrants are not
extinguished on or before May 28, 2003, they will vest and become exercisable in
accordance with their terms. Whether or not we are able to extinguish warrants
on or before May 28, 2003, the remaining 50% of the warrants will be
extinguished, again on a proportionate basis, if we reduce the bank facility by
up to $400 million by the end of 2003. Because of current financial market
conditions and uncertainties regarding such conditions over the balance of the
year, there can be no assurance that we will be able to fund the $800 million
prepayments in 2003 in order to extinguish the warrants or to do so on favorable
terms. If SEC approval of our issuance of the warrants is not obtained by May
28, 2003, we will become obligated to provide the banks with equivalent cash
compensation over the term that the warrants would have been exercisable to the
extent they are not otherwise extinguished. For more information, please read
"Management's Discussion and Analysis of Financial Condition and Results of
Operations -- "Liquidity and Capital Resources -- Future Sources and Uses of
Cash -- Long-Term Debt" in Item 7 of this report.

OUR AMENDED BANK FACILITY IMPOSES RESTRICTIONS ON OUR ABILITY TO PAY
DIVIDENDS.

Under the terms of our bank facility as amended in February 2003, we agreed
that our quarterly common stock dividend will not exceed $0.10 per share. If we
have not reduced the bank facility by a total of at least $400 million by the
end of 2003, of which at least $200 million has come from the issuance of
capital stock or securities linked to capital stock (such as convertible debt),
the maximum dividend payable during 2004 and for the balance of the term of the
facility is subject to an additional test. Under that test the maximum permitted
quarterly dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of
our net income per share for the 12 months ended on the last day of the previous
quarter. There can be no assurance that we will be able to fund the $400 million
in 2003 in order avoid the further limitation on our common stock dividends. For
more information, please read "Management's Discussion and Analysis of Financial
Condition and Results of Operations -- "Liquidity and Capital
Resources -- Future Sources and Uses of Cash -- Long-Term Debt" in Item 7 of
this report.

IF WE ARE UNABLE TO OBTAIN AN EXTENSION OF OUR FINANCING ORDER UNDER THE 1935
ACT, WE WILL NOT BE ABLE TO ENGAGE IN FINANCING TRANSACTIONS AFTER JUNE 30,
2003.

In connection with our registration as a public utility holding company
under the 1935 Act, the SEC issued a financing order which authorizes us to
enter into a wide range of financing transactions. This financing order expires
on June 30, 2003. If we are unable to obtain an extension of the financing
order, we would generally be unable to engage in any financing transactions,
including the refinancing of existing obligations after June 30, 2003.

WE COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS OF RELIANT
RESOURCES.

In connection with the organization and capitalization of Reliant
Resources, Reliant Resources and its subsidiaries assumed liabilities associated
with various assets and businesses Reliant Energy transferred to them. Reliant
Resources also agreed to indemnify and cause the applicable transferee
subsidiaries to indemnify CenterPoint Energy and its subsidiaries, including
CenterPoint Houston and CERC, with respect to liabilities associated with the
transferred assets and businesses. The indemnity provisions were intended to
place sole financial responsibility on Reliant Resources and its subsidiaries
for all liabilities associated with the
28

current and historical business and operations of Reliant Resources, regardless
of the time those liabilities arose. If Reliant Resources is unable to satisfy a
liability that has been so assumed and in circumstances in which we were not
released from the liability in connection with the transfer, we could be
responsible for satisfying the liability.

Reliant Resources has reported that it is facing large maturities of debt
over the next several months, and its securities ratings are now below
investment grade. If Reliant Resources is unable to meet its obligations, it
would need to consider, among various options, restructuring under the
bankruptcy laws, in which event Reliant Resources might not honor its
indemnification obligations, and claims by Reliant Resources' creditors might be
made against us as its former owner.

As described in Note 13(c) to our consolidated financial statements,
Reliant Energy and Reliant Resources are named as defendants in a number of
lawsuits arising out of power sales in California and other West Coast markets
and financial reporting matters. Although these matters relate to the business
and operations of Reliant Resources, claims against Reliant Energy have been
made on grounds that include the effect of Reliant Resources' financial results
on Reliant Energy's historical financial statements and Reliant Energy's
liability as a controlling shareholder of Reliant Resources. We could incur
liability if claims in one or more of these lawsuits were successfully asserted
against us and indemnification from Reliant Resources were determined to be
unavailable or if Reliant Resources were unable to satisfy indemnification
obligations owed to us with respect to those claims.

OUR HISTORICAL FINANCIAL RESULTS ARE NOT NECESSARILY REPRESENTATIVE OF OUR
EXPECTED FUTURE RESULTS.

We have limited experience operating in a deregulated electricity market in
which our transmission and distribution business is subject to rate regulation
while our generation business is not. The financial information we have included
in this report does not necessarily reflect what our financial position, results
of operations and cash flows would have been prior to 2002 had we conducted
those businesses separately rather than as an integrated electric utility during
the periods presented.

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 and public liability insurance in amounts that we consider
appropriate. Where we have such insurance policies in place, they 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 on commercially reasonable terms or that the insurance proceeds received
for any loss of or any damage to any of our facilities will be sufficient to
restore the loss or damage without negative impact on our results of operations,
financial condition and cash flows. The costs of our insurance coverage have
increased significantly in recent months and may continue to increase in the
future.

Texas Genco 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 $9.3 billion as of December 31, 2002. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. Texas Genco 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.

In common with other companies in its line of business that serve coastal
regions, CenterPoint Houston does not have insurance covering its transmission
and distribution system because CenterPoint Houston
29

believes it to be cost prohibitive. If CenterPoint Houston were to sustain any
loss of or damage to its transmission and distribution properties, it would be
entitled to seek to recover such loss or damage through a change in its
regulated rates, although there is no assurance that CenterPoint Houston
ultimately would obtain any such rate recovery or that any such rate recovery
would be timely granted. Therefore, we cannot assure you that CenterPoint
Houston will be able to restore any loss of or damage to its transmission and
distribution properties without negative impact on our results of operations,
financial condition and cash flows.

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

As of December 31, 2002, we had $5.6 billion of outstanding floating-rate
debt. Because of capital constraints impacting our business at the time some of
this floating-rate debt was entered into, the interest rates are substantially
above our historical borrowing rates. In addition, any floating-rate debt issued
by us in the future could be at interest rates substantially above our
historical borrowing rates. While we may seek to use interest rate swaps in
order to hedge portions of our floating-rate debt, we may not be successful in
obtaining hedges on acceptable terms. Any increase in short-term interest rates
would result in higher interest costs and could adversely affect our results of
operations, financial condition and cash flows.

OUR REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO RISKS THAT ARE BEYOND OUR
CONTROL, INCLUDING BUT NOT LIMITED TO FUTURE TERRORIST ATTACKS OR RELATED ACTS
OF WAR.

The cost of repairing damage to our operating subsidiaries' facilities due
to storms, natural disasters, wars, terrorist acts and other catastrophic
events, in excess of reserves established for such repairs, 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, financial condition and cash flows 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 electric transmission
and distribution, electric generation, natural gas distribution and pipeline and
gathering facilities 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.

RISK FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC TRANSMISSION & DISTRIBUTION
BUSINESS

CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN RECOVERING THE FULL VALUE OF ITS
STRANDED COSTS AND REGULATORY ASSETS RELATED TO GENERATION.

CenterPoint Houston is entitled to recover its stranded costs (the excess
of regulatory net book value of generation assets, as defined by the Texas
electric restructuring law, over the market value of those assets) and its
regulatory assets related to generation. CenterPoint Houston expects to make a
filing in January 2004 in a true-up proceeding provided for by the Texas
electric restructuring law. The purpose of this proceeding will be to quantify
and reconcile:

- the amount of stranded costs;

- differences in the prices achieved in the state mandated auctions of
Texas Genco's generation capacity and Texas Utility Commission estimates;

- fuel over- or under-recovery;

- the "price to beat" clawback; and

- other regulatory assets associated with our generation business that were
not previously recovered through the issuance of securitization bonds by
a subsidiary.

CenterPoint Houston will be required to establish and support the amounts
of these costs in order to recover them. CenterPoint Houston expects these costs
to be substantial. We cannot assure you that
30

CenterPoint Houston will be able to successfully establish and support its
estimates of the value of these costs. For more information about the true-up
proceeding, please read "Our Business -- Electric Transmission &
Distribution -- Stranded Costs and Regulatory Assets Recovery" above and Note
4(a) to our consolidated financial statements.

In addition, CenterPoint Houston's $1.3 billion collateralized term loan
matures on November 11, 2005 and is expected to be repaid or refinanced with the
proceeds from the recovery of these costs. To the extent CenterPoint Houston has
not received the proceeds by November 11, 2005, CenterPoint Houston's ability to
repay or refinance its $1.3 billion term loan will be adversely affected.

CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL
ELECTRIC PROVIDERS.

CenterPoint Houston's receivables from the distribution of electricity are
collected from retail electric providers that supply the electricity CenterPoint
Houston distributes to their customers. Currently, CenterPoint Houston does
business with approximately 31 retail electric providers. Adverse economic
conditions, structural problems in the new ERCOT market or financial
difficulties of one or more retail electric providers could impair the ability
of these retail providers to pay for CenterPoint Houston's services or could
cause them to delay such payments. CenterPoint Houston depends on these retail
electric providers to remit payments timely to it. Any delay or default in
payment could adversely affect CenterPoint Houston's cash flows, financial
condition and results of operations. CenterPoint Houston's receivables balance
from retail electric providers at December 31, 2002 was $85 million.
Approximately 72% of CenterPoint Houston's receivables from retail electric
providers at December 31, 2002 was owed by subsidiaries of Reliant Resources.
Our financial condition may be adversely affected if Reliant Resources is unable
to meet its obligations to CenterPoint Houston.

Reliant Resources, through its subsidiaries, is CenterPoint Houston's
largest customer. Pursuant to the Texas electric restructuring law, Reliant
Resources may be obligated to make a large "price to beat" clawback payment to
CenterPoint Houston in 2004. CenterPoint Houston expects the clawback, if any,
to be applied against any stranded cost recovery to which CenterPoint Houston is
entitled or, if no stranded costs are recoverable, to be refunded to retail
electric providers. Also, as discussed in "Risk Factors Associated with
Financial Condition and Other Risks," Reliant Resources is obligated to
indemnify CenterPoint Houston for other potential liabilities. Reliant Resources
has reported that it is facing large maturities of its debt over the next year
and thus its ability to satisfy its obligations to CenterPoint Houston cannot be
assured.

RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY CENTERPOINT
HOUSTON'S FULL RECOVERY OF ITS COSTS.

CenterPoint Houston's rates are regulated by certain municipalities and the
Texas Utility Commission based on an analysis of its invested capital and its
expenses incurred in a test year. Thus, the rates CenterPoint Houston is allowed
to charge may not match its expenses at any given time. While rate regulation in
Texas is premised on providing a reasonable opportunity to recover reasonable
and necessary operating expenses and to earn a reasonable return on its invested
capital, there can be no assurance that the Texas Utility Commission will judge
all of CenterPoint Houston's costs to be reasonable or necessary or that the
regulatory process in which rates are determined will always result in rates
that will produce full recovery of CenterPoint Houston's costs.

CENTERPOINT HOUSTON IS OPERATING IN A RELATIVELY NEW MARKET ENVIRONMENT IN
WHICH IT AND OTHERS HAVE LITTLE OPERATING EXPERIENCE.

The competitive electric market in Texas became fully operational in
January 2002. Neither CenterPoint Houston nor any of the Texas Utility
Commission, ERCOT or other market participants has any significant operating
history under the market framework created by the Texas electric restructuring
law. Some operational difficulties were encountered in the pilot program
conducted in 2001 and continue to be experienced now. These difficulties include
delays in the switching of some customers from one retail electric provider to
another. These difficulties create uncertainty as to the amount of transmission
and distribution

31

charges owed by each retail electric provider, which may cause payment of those
amounts to be delayed. While to date these difficulties have not been material,
these operating difficulties could become material or structural changes adopted
to address these difficulties could materially adversely affect its results of
operations, financial condition and cash flows.

DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD
INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION
SERVICES.

CenterPoint Houston depends on power generation facilities owned by third
parties to provide retail electric providers with electric power which it
transmits and distributes to their customers. CenterPoint Houston does not own
or operate any power generation facilities. If power generation is disrupted or
if power generation capacity is inadequate, CenterPoint Houston's transmission
and distribution services may be interrupted, and its results of operations,
financial condition and cash flows may be adversely affected.

CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

A portion of CenterPoint Houston's revenues is derived from rates that it
collects from each retail electric provider based on the amount of electricity
it distributes on behalf of each retail electric provider. Thus, CenterPoint
Houston's revenues and results of operations are subject to seasonality, weather
conditions and other changes in electricity usage, with revenues being higher
during the warmer months.

TECHNOLOGICAL CHANGE MAY MAKE ALTERNATIVE ENERGY SOURCES MORE ATTRACTIVE AND
MAY ADVERSELY AFFECT CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS.

The continuous process of technological development may result in the
introduction to retail customers of economically attractive alternatives to
purchasing electricity through CenterPoint Houston's distribution facilities.
Manufacturers of self-generation facilities continue to develop smaller-scale,
more-fuel-efficient generating units that can be cost-effective options for some
retail customers with smaller electric energy requirements. Any reduction in the
amount of electric energy CenterPoint Houston distributes as a result of these
technologies may have an adverse impact on its results of operations, financial
condition and cash flows in the future.

RISK FACTORS AFFECTING THE RESULTS OF OUR ELECTRIC GENERATION BUSINESS

TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE IMPACTED BY MARKET RISKS
THAT ARE BEYOND ITS CONTROL.

Texas Genco sells electric generation capacity, energy and ancillary
services in the ERCOT market. The ERCOT market consists of the majority of the
population centers in the State of Texas and represents approximately 85% of the
demand for power in the state. Under the Texas electric restructuring law, Texas
Genco 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, Texas Genco is not guaranteed any rate of return on its
capital investments through mandated rates, and its 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. Texas Genco's gross margins
are primarily derived from the sale of capacity entitlements associated with its
large, solid fuel base-load generating units, including its Limestone and W. A.
Parish facilities and its 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 Texas Genco's base-load
units are largely fixed under long-term contracts, they are generally not
subject to significant daily and monthly fluctuations. However, the market price
for power in the ERCOT market is directly affected by the price of natural gas.
Because natural gas is the marginal fuel for facilities serving the ERCOT market
during most hours, its price has a significant influence on the price of
electric power. As a result, the price customers are willing to pay for
entitlements to Texas Genco's solid fuel-fired base-load capacity generally
rises and falls with natural gas prices.

32

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, 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;

- 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 amount by which power generating capacity exceeded peak demand (reserve
margin) in the ERCOT market has exceeded 20% since 2001, and the Texas Utility
Commission and the ERCOT ISO have forecasted the reserve margin for 2003 to
continue to exceed 20%. A market consulting firm specializing in the power
industry has published a report that predicts there will be a surplus of
generating capacity in the ERCOT market for the next several years. The
commencement of commercial operation of new facilities in the ERCOT region will
increase the competitiveness of the wholesale power market, which could have a
material adverse effect on Texas Genco's results of operations, financial
condition, cash flows and the market value of Texas Genco's assets.

Texas Genco's 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 Texas Genco's 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, and greater flexibility in the timing of their sale of
generating capacity and ancillary services than Texas Genco does.

TEXAS GENCO IS SUBJECT TO OPERATIONAL AND MARKET RISKS ASSOCIATED WITH ITS
CAPACITY AUCTIONS.

Texas Genco is obligated to sell substantially all of its capacity and
related ancillary services through 2003 pursuant to the capacity auctions more
fully described under "Our Business -- Electric Generation" above. In these
auctions, Texas Genco sells firm entitlements on a forward basis to capacity and
ancillary services dispatched within specified operational constraints. Although
Texas Genco has reserved a portion of its aggregate net generation capacity from
its capacity auctions for planned or forced outages at its facilities,
unanticipated plant outages or other problems with its generation facilities
could result in its firm capacity and ancillary services commitments exceeding
its available generation capacity. As a result, Texas Genco could be required to
obtain replacement power from third parties in the open market to satisfy its
firm commitments that could result in significant additional costs. In addition,
an unexpected outage at one of Texas Genco's

33

lower cost facilities could require it to run one of its higher cost plants in
order to satisfy its obligations even though the energy payments for the
dispatched power are based on the cost at the lower-cost facility.

Texas Genco sells capacity entitlements in state mandated auctions and in
its other contractually mandated auctions. The mechanics, regulations and
agreements governing Texas Genco's capacity auctions are complex, and the
auction process in which Texas Genco sells entitlements to its capacity is
relatively new. The state mandated auctions require, among other things, Texas
Genco's capacity entitlements to be sold in pre-determined amounts. The
characteristics of the capacity entitlements Texas Genco sells in state mandated
auctions are defined by rules adopted by the Texas Utility Commission and,
therefore, cannot be changed to respond to market demands or operational
requirements without approval by the Texas Utility Commission.

IF THE ERCOT MARKET DOES NOT FUNCTION IN THE MANNER CONTEMPLATED BY THE TEXAS
ELECTRIC RESTRUCTURING LAW, TEXAS GENCO'S BUSINESS PROSPECTS, RESULTS OF
OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY IMPACTED.

The initiatives under the Texas electric restructuring law have had a
significant impact on the nature of the electric power industry in Texas and the
manner in which participants in the ERCOT market conduct their business. These
changes are ongoing, and we cannot predict the future development of the ERCOT
market or the ultimate effect that this changing regulatory environment will
have on Texas Genco's business. Some restructured markets in other states have
recently experienced supply problems and extreme price volatility. If the ERCOT
market does not function as planned once the deregulation initiatives called for
by the Texas electric restructuring law have taken their full effect, Texas
Genco's results of operations, financial condition and cash flows could be
adversely affected. In addition, any market failures could lead to revisions or
reinterpretations of the Texas electric restructuring law, the adoption of new
laws and regulations applicable to Texas Genco or its facilities and other
future changes in laws and regulations that may have a detrimental effect on
Texas Genco's business.

As part of the transition to retail competition in Texas, the ERCOT market
has changed from operating with multiple control areas, each managed by one of
the utilities in the state, to a single control area managed by the ERCOT ISO.
The ERCOT ISO is responsible for maintaining reliable operations of the bulk
electric power supply system in the new combined control area. If the ERCOT ISO
is unable to successfully manage these functions, the ERCOT market may not
operate properly and Texas Genco's results of operations could be adversely
affected. In addition, the ERCOT ISO may impose or the Texas Utility Commission
may require price limitations, bidding rules and other mechanisms that could
impact wholesale prices in the ERCOT market and the outcomes of Texas Genco's
capacity auctions.

THE OPERATION OF TEXAS GENCO'S POWER GENERATION FACILITIES INVOLVES RISKS THAT
COULD ADVERSELY AFFECT ITS REVENUES, COSTS, RESULTS OF OPERATIONS, FINANCIAL
CONDITION AND CASH FLOWS.

Texas Genco is subject to various risks associated with operating its power
generation facilities, any of which could adversely affect its 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;

- fuel supply interruptions;

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

- limitations imposed by the ERCOT ISO;
34

- 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 Texas Genco's facilities were 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.

Texas Genco employs experienced personnel to maintain and operate its
facilities and carries insurance to mitigate the effects of some of the
operating risks described above. Texas Genco's 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 Texas Genco's operations may be significantly reduced or its costs
of operations may significantly increase.

TEXAS GENCO RELIES ON POWER TRANSMISSION FACILITIES THAT IT DOES NOT OWN OR
CONTROL AND THAT ARE SUBJECT TO TRANSMISSION CONSTRAINTS WITHIN THE ERCOT
MARKET. IF THESE FACILITIES FAIL TO PROVIDE TEXAS GENCO WITH ADEQUATE
TRANSMISSION CAPACITY, IT MAY NOT BE ABLE TO DELIVER WHOLESALE ELECTRIC POWER
TO ITS CUSTOMERS AND IT MAY INCUR ADDITIONAL COSTS.

Texas Genco depends on transmission and distribution facilities owned and
operated by our wholly owned subsidiary, CenterPoint Houston, and on
transmission and distribution systems owned by others to deliver the wholesale
electric power it sells from its power generation facilities to its customers,
who in turn deliver power to the end users. If transmission is disrupted, or if
transmission capacity infrastructure is inadequate, Texas Genco's ability to
sell and deliver wholesale electric energy may be adversely impacted.

The single control area of the ERCOT market is currently organized into
four congestion zones, referred to as the North, South, West and Houston zones.
These congestion zones are determined by physical constraints on the ERCOT
transmission system that make it difficult or impossible at times to move power
from a zone on one side of the constraint to the zone on the other side of the
constraint. All but two of Texas Genco's facilities are located in the Houston
congestion zone. Texas Genco's Limestone facility is located in the North
congestion zone and the South Texas Project is located in the South congestion
zone. Texas Genco sells a portion of the entitlements offered in its state
mandated auctions to customers located in congestion zones other than the
Houston zone. Transmission congestion between these zones could impair Texas
Genco's ability to schedule power for transmission across zonal boundaries,
which are defined by the ERCOT ISO, thereby inhibiting its efforts to match its
facility scheduled outputs with its 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. Texas Genco schedules its anticipated
requirements based on its own forecasted needs, which rely in part on demand
forecasts made by its customers. These forecasts may prove to be inaccurate.
Texas Genco could be deemed responsible for congestion costs if it schedules
delivery of power between congestion zones during times when the ERCOT ISO
expects congestion to occur between the zones. If Texas Genco is liable for
congestion costs, its financial results could be adversely affected. For more
information about the ERCOT market, please read "Our
Business -- Overview -- ERCOT Market Framework" above.

TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD
BE ADVERSELY IMPACTED BY A DISRUPTION OF ITS FUEL SUPPLIES.

Texas Genco relies primarily on natural gas, coal, lignite and uranium to
fuel its generation facilities. Texas Genco purchases its fuel from a number of
different suppliers under long-term contracts and on the spot market. Under
Texas Genco's capacity auctions, it sells firm entitlements to capacity and
ancillary services.
35

Therefore, any disruption in the delivery of fuel could prevent Texas Genco from
operating its facilities to meet its auction commitments, which could adversely
affect its results of operations, financial condition and cash flows.

Delivery of natural gas to each of Texas Genco's natural gas-fired
facilities typically depends on the natural gas pipelines or distributors for
that location. As a result, Texas Genco is subject to the risk that a natural
gas pipeline or distributor may suffer disruptions or curtailments in its
ability to deliver natural gas to it or that the amounts of natural gas Texas
Genco requests are curtailed. These disruptions or curtailments could adversely
affect Texas Genco's ability to operate its natural gas-fired generating
facilities. Texas Genco leases 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.

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

TO DATE, TEXAS GENCO HAS SOLD A SUBSTANTIAL PORTION OF ITS AUCTIONED CAPACITY
ENTITLEMENTS TO A SINGLE CUSTOMER, RELIANT RESOURCES. ACCORDINGLY, TEXAS
GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE
ADVERSELY AFFECTED IF RELIANT RESOURCES DECLINED TO PARTICIPATE IN TEXAS
GENCO'S FUTURE AUCTIONS OR FAILED TO MAKE PAYMENTS WHEN DUE UNDER RELIANT
RESOURCES' PURCHASED ENTITLEMENTS.

By participating in Texas Genco's contractually mandated auctions,
subsidiaries of Reliant Resources purchased entitlements to 63% of the aggregate
2002 capacity and 58% of the aggregate 2003 capacity that Texas Genco has sold
to date through its capacity auctions. Reliant Resources made these purchases
either through the exercise of its contractual rights to purchase 50% of the
entitlements Texas Genco auctions in its contractually mandated auctions or
through the submission of bids. In the event Reliant Resources declined to
participate in Texas Genco's future auctions or failed to make payments when
due, Texas Genco's results of operations, financial condition and cash flows
could be adversely affected. In this regard, Reliant Resources has reported that
it is facing large maturities of debt over the next year, and its securities
ratings are now below investment grade.

TEXAS GENCO MAY INCUR SUBSTANTIAL COSTS AND LIABILITIES AS A RESULT OF ITS
OWNERSHIP OF NUCLEAR FACILITIES.

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

- 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 its assessment of the severity of the
situation, until compliance is achieved. Revised safety requirements promulgated
by the NRC could necessitate substantial
36

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 did occur, it could have a material adverse effect on Texas Genco's
results of operations, financial condition and cash flows.

CONTRACTUAL RESTRICTIONS ON THE OPERATION OF TEXAS GENCO'S BUSINESS MAY LIMIT
ITS ABILITY TO TAKE ACTIONS AVAILABLE TO OTHER COMPANIES THAT ARE NOT SUBJECT
TO SIMILAR RESTRICTIONS.

Effective December 31, 2000, Reliant Resources and Reliant Energy entered
into a master separation agreement, that now governs the rights and obligations
of us and Reliant Resources in connection with the business separation plan of
Reliant Energy adopted in response to the Texas electric restructuring law.
Reliant Resources also has an option to purchase the shares of Texas Genco stock
owned by us that is exercisable in January 2004. Texas Genco has agreed to
comply with certain restrictions governing its operations as contemplated by the
master separation agreement and option agreement. These restrictions limit Texas
Genco's ability to:

- merge or consolidate with another entity;

- sell assets;

- enter into long-term agreements and commitments for the purchase of fuel
or the purchase or sale of power outside the ordinary course of business;

- engage in other businesses;

- construct or acquire new generation plants or capacity;

- engage in hedging transactions;

- encumber Texas Genco's assets;

- issue additional equity securities;

- pay special dividends; and

- make certain loans, investments or advances to, or engage in certain
transactions with, Texas Genco's affiliates.

TEXAS GENCO MAY NOT HAVE ACCESS TO SUFFICIENT CAPITAL IN THE AMOUNTS AND AT
THE TIMES NEEDED TO FINANCE ITS BUSINESS.

To date, Texas Genco's capital has been provided by internally generated
cash flows and borrowings and capital contributions from CenterPoint Energy. We
can give no assurances that Texas Genco's current and future capital structure,
operating performance, financial condition and cash flows will permit it to
access the capital markets or to obtain other financing as needed to meet its
working capital requirements and projected future capital expenditures on
favorable terms. Texas Genco's projected future capital expenditures are
substantial. Texas Genco's 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 its business, which may lead to volatility in
its financial results and cash flows. CenterPoint Energy has agreed to lend
funds to Texas Genco from time to time upon Texas Genco's request until the
earlier of the closing date on which Reliant Resources acquires Texas Genco
common stock from CenterPoint Energy pursuant to the Reliant Resources option or
the expiration of the Reliant Resources option. In the event CenterPoint Energy
were to experience liquidity problems or otherwise failed to perform, Texas
Genco may be unable to obtain third party financing.

In addition, Texas Genco's ability to raise capital is restricted under its
agreements with CenterPoint Energy. These restrictions limit Texas Genco's
ability to:

- issue additional equity securities;

- encumber its assets; or

37

- incur indebtedness, except to satisfy requirements for operating and
maintenance expenditures and other capital expenditures contemplated
under its agreements with CenterPoint Energy, to meet its working capital
needs, or to refinance indebtedness incurred for the foregoing purposes.

In connection with CenterPoint Energy's registration as a public utility
holding company under the 1935 Act, the SEC has limited the aggregate amount of
Texas Genco's external borrowings to $500 million. In addition, the order issued
to CenterPoint Energy under the 1935 Act restricts Texas Genco's ability to pay
dividends out of capital accounts. Under these restrictions, Texas Genco is
permitted to pay dividends out of its current or retained earnings, and it may
also pay dividends in an amount of up to $100 million in excess of its current
or retained earnings.

TEXAS GENCO'S OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION. IF TEXAS GENCO
FAILS TO COMPLY WITH APPLICABLE REGULATIONS OR OBTAIN OR MAINTAIN ANY
NECESSARY GOVERNMENTAL PERMIT OR APPROVAL, IT MAY BE SUBJECT TO CIVIL,
ADMINISTRATIVE AND/OR CRIMINAL PENALTIES THAT COULD ADVERSELY IMPACT ITS
RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

Texas Genco's 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
Texas Genco or any of its generation facilities or future changes in laws and
regulations may have a detrimental effect on its business.

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 Texas Genco's 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 Texas Genco's business.

If Texas Genco fails to comply with regulatory requirements that apply to
its operations, regulatory agencies could seek to impose civil, administrative
and/or criminal liabilities or could take other actions seeking to curtail its
operations. These liabilities or actions could adversely impact its results of
operations, financial condition and cash flows.

TEXAS GENCO'S COSTS OF COMPLIANCE WITH ENVIRONMENTAL LAWS ARE SIGNIFICANT AND
THE COST OF COMPLIANCE WITH NEW ENVIRONMENTAL LAWS AND ITS EXPOSURE TO
POTENTIAL LIABILITIES ASSOCIATED WITH THE ENVIRONMENTAL CONDITION OF ITS
FACILITIES COULD ADVERSELY AFFECT ITS PROFITABILITY.

Texas Genco's business is subject to extensive environmental regulation by
federal, state and local authorities. Texas Genco is required to comply with
numerous environmental laws and regulations, and to obtain numerous governmental
permits, in operating its facilities. Texas Genco may incur significant
additional costs to comply with these requirements. If Texas Genco fails to
comply with these requirements, it could be subject to civil or criminal
liability and fines. Existing environmental regulations could be revised or
reinterpreted, new laws and regulations could be adopted or become applicable to
Texas Genco or its 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, Texas
Genco's business, results of operations, financial condition and cash flows
could be adversely affected.

Texas Genco 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

38

Texas Genco fails to obtain and comply with them, it may not be able to operate
its facilities or it may be required to incur additional costs.

Texas Genco is generally responsible for all on-site liabilities associated
with the environmental condition of its power generation facilities, regardless
of when the liabilities arose and whether the liabilities are known or unknown.
These liabilities may be substantial.

CHANGES IN TECHNOLOGY MAY MAKE TEXAS GENCO'S POWER GENERATION FACILITIES LESS
COMPETITIVE, WHICH COULD ADVERSELY IMPACT THEIR VALUE AND THE RESULTS OF TEXAS
GENCO'S OPERATIONS.

A significant portion of Texas Genco's generation facilities were
constructed many years ago and rely on older technologies. Some of Texas Genco's
competitors may have newer generation facilities and technologies that allow
them to produce and sell power more efficiently, which could adversely affect
Texas Genco's results of operations, financial condition and cash flows. In
addition, research and development activities are ongoing to improve alternate
technologies to produce electricity, including fuel cells, microturbines,
windmills and photovoltaic (solar) cells. It is possible that advances in these
or other technologies will reduce the current costs of electricity production to
a level that is below that of Texas Genco's generation facilities. If this
occurs, Texas Genco's generation facilities will be less competitive and the
value of its power plants could be significantly impaired. Also, electricity
demand could be reduced by increased conservation efforts and advances in
technology that could likewise significantly reduce the value of Texas Genco's
power generation facilities.

RISK FACTORS AFFECTING THE RESULTS OF OUR NATURAL GAS DISTRIBUTION AND PIPELINES
AND GATHERING BUSINESSES

OUR NATURAL GAS DISTRIBUTION BUSINESS MUST COMPETE WITH ALTERNATIVE ENERGY
SOURCES.

CERC competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other gas
distributors and marketers also compete directly with CERC for natural gas sales
to end-users. In addition, as a result of federal regulatory changes affecting
interstate pipelines, natural gas marketers operating on these pipelines may be
able to bypass CERC's facilities and market, sell and/or transport natural gas
directly to commercial and industrial customers. Any reduction in the amount of
natural gas marketed, sold or transported by CERC as a result of competition may
have an adverse impact on CERC's results of operations, financial condition and
cash flows.

OUR NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL
GAS PRICING LEVELS.

CERC is subject to risk associated with upward price movements of natural
gas. High natural gas prices might affect CERC's ability to collect balances due
from its customers and could create the potential for uncollectible accounts
expense to exceed the recoverable levels built into CERC's tariff rates. In
addition, a sustained period of high natural gas prices could apply downward
demand pressure on natural gas consumers in CERC's service territory.

CERC MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE
COSTS OF NATURAL GAS.

Generally, the regulations of the states in which CERC operates allow it to
pass through changes in the costs of natural gas to its customers through
purchased gas adjustment provisions in the applicable tariffs. There is,
however, a timing difference between its purchases of natural gas and the
ultimate recovery of these costs. Consequently, CERC may incur carrying costs as
a result of this timing difference that are not recoverable from its customers.
The failure to recover those additional carrying costs may have an adverse
effect on CERC's results of operations, financial condition and cash flows.

39

OUR PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN
THE TRANSPORTATION AND STORAGE OF NATURAL GAS AND INDIRECTLY WITH ALTERNATIVE
FORMS OF ENERGY.

Our two interstate pipelines and our gathering systems compete with other
interstate and intrastate pipelines and gathering systems in the transportation
and storage of natural gas. The principal elements of competition are rates,
terms of service, and flexibility and reliability of service. They also compete
indirectly with other forms of energy, including electricity, coal and fuel
oils. The primary competitive factor is price. The actions of CERC's competitors
could lead to lower prices, which may have an adverse impact on CERC's results
of operations, financial condition and cash flows.

IF WE FAIL TO EXTEND CONTRACTS WITH TWO OF OUR SIGNIFICANT INTERSTATE
PIPELINES' CUSTOMERS, IT COULD HAVE AN ADVERSE IMPACT ON CERC'S OPERATIONS.

Contracts with two of our interstate pipelines' significant customers,
Arkla and Laclede, are currently scheduled to expire in 2005 and 2007,
respectively. To the extent the pipelines are unable to extend these contracts
or the contracts are renegotiated at rates substantially different than the
rates provided in the current contracts, it could have an adverse effect on
CERC's results of operations, financial condition and cash flows.

OUR INTERSTATE PIPELINES ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS.

Our interstate pipelines largely rely on gas sourced in the various supply
basins located in the Midcontinent region of the United States. To the extent
the availability of this supply is substantially reduced, it could have an
adverse effect on CERC's results of operations, financial condition and cash
flows.

CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

A portion of CERC's revenues are derived from natural gas sales and
transportation. Thus, CERC's revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.

ITEM 2. PROPERTIES

CHARACTER OF OWNERSHIP

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

ELECTRIC TRANSMISSION & DISTRIBUTION

For information regarding the properties of our Electric Transmission &
Distribution business segment, please read "Our Business -- Electric
Transmission & Distribution" in Item 1 of this report, which information is
incorporated herein by reference.

ELECTRIC GENERATION

For information regarding the properties of our Electric Generation
business segment, please read "Our Business -- Electric Generation" in Item 1 of
this report, which information is incorporated herein by reference.

NATURAL GAS DISTRIBUTION

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

40

PIPELINES AND GATHERING

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

OTHER OPERATIONS

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

ITEM 3. LEGAL PROCEEDINGS

For a brief description of certain legal and regulatory proceedings
affecting us, see "Regulation" and "Environmental Matters" in Item 1 of this
report and Notes 4 and 13 to our consolidated financial statements.

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

There were no matters submitted to the vote of our security holders during
the fourth quarter of 2002.

PART II

ITEM 5. MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS

As of February 25, 2003, our common stock was held of record by
approximately 67,308 shareholders. Our common stock is listed on the New York
and Chicago Stock Exchanges and is traded under the symbol "CNP."

The following table sets forth the high and low sales prices of the common
stock of CenterPoint Energy or its predecessor on the New York Stock Exchange
composite tape during the periods indicated, as reported by Bloomberg, and the
cash dividends declared in these periods. Prior to August 31, 2002, information
shown is for our predecessor, Reliant Energy. Cash dividends paid aggregated
$1.50 per share in 2001 and $1.07 per share in 2002.

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

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

(2) The reduction in the quarterly dividend to $0.16 reflects the Restructuring
of CenterPoint Energy and the Reliant Resources Distribution.

(3) The fourth quarter 2002 stock prices reflect the distribution of our 83%
ownership interest in Reliant Resources on September 30, 2002. The closing
price of Reliant Resources' common stock on that date was $1.75.

The closing market price of our common stock on December 31, 2002 was $8.01
per share. On February 28, 2003, our board of directors declared a quarterly
dividend of $0.10 per share of our outstanding common stock, payable on March
31, 2003 to shareholders of record as of the close of business March 12, 2003.
This quarterly dividend is the maximum allowed under our amended $3.85 billion
bank facility.

Under the terms of our amended $3.85 billion bank facility, we agreed that
our quarterly common stock dividend will not exceed $0.10 per share. If we have
not reduced the bank facility by a total of at least $400 million by the end of
2003, of which at least $200 million has come from the issuance of capital stock
or securities linked to capital stock (such as convertible debt), the maximum
dividend payable during 2004 and for the balance of the term of the facility is
subject to an additional test. Under that test the maximum permitted quarterly
dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of our net
income per share for the 12 months ended on the last day of the previous
quarter.

In addition to the limitations imposed by our bank facility, the amount of
future cash dividends will be subject to determination based upon our results of
operations and financial condition, our future business prospects, any
applicable contractual restrictions and other factors that our board of
directors considers relevant and will be declared at the discretion of the board
of directors.

42

ITEM 6. SELECTED FINANCIAL DATA

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

The selected financial data presented below reflect certain
reclassifications necessary to present Reliant Resources as discontinued
operations as a result of the distribution of all of the shares of Reliant
Resources common stock owned by CenterPoint Energy to its common shareholders on
a pro rata basis (the Reliant Resources Distribution) and the retroactive
effects of the adoption of Statement of Financial Accounting Standards (SFAS)
No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS
No. 144), as it relates to the Company's Latin America operations. The selected
financial data also gives effect to the Restructuring. For additional
information regarding the Reliant Resources Distribution and our investments in
Latin America, please read Note 2 to our consolidated financial statements.

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

(1) 1998 net income includes a non-cash, unrealized loss on our indexed debt
securities of $764 million (after-tax), or $2.69 loss per basic and diluted
share. For additional information on the indexed debt securities, please
read Note 7 to our consolidated financial statements. Fixed charges exceeded
earnings by $225 million in 1998.

(2) 1999 net income includes an aggregate non-cash, unrealized gain on our
indexed debt securities and our Time Warner, Inc. (now AOL Time Warner Inc.)
investment, of $1.2 billion (after-tax), or $4.09 earnings per basic share
and $4.08 earnings per diluted share. For additional information on the
indexed debt securities and AOL Time Warner investment, please read Note 7
to our consolidated financial statements. The extraordinary item in 1999 is
a loss related to an accounting impairment of certain generation related
regulatory assets of our Electric Generation business segment. For
additional information regarding the impairment, please read Note 4 to our
consolidated financial statements.

(3) 2000 net income includes an aggregate non-cash loss on our indexed debt
securities and our AOL Time Warner investment of $67 million (after-tax), or
$0.24 loss per basic share and $0.23 loss per diluted share. 2000 net income
also includes a $226 million (after-tax) charge (net of a tax benefit of
$122 million), or $0.78 loss per basic share and $0.77 loss per diluted
share, to reflect the loss on disposal of our Latin America investments. For
additional information on the indexed debt securities and AOL Time Warner
investment, please read Note 7 to our consolidated financial statements. For
additional information regarding our investments in Latin America, please
read Note 2 to our consolidated financial statements.

(4) 2001 net income includes the following: (i) the cumulative effect of an
accounting change resulting from the adoption of SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities" ($59 million after-tax
gain, or $0.20 earnings per basic and diluted share) and (ii) an impairment
of our Latin America operations ($51 million after-tax, or $0.17 loss per
basic and diluted share). For additional information related to the
cumulative effect of accounting change, please read Note 5 to our
consolidated financial statements. For additional information regarding our
investments in Latin America, please read Note 2 to our consolidated
financial statements.

(5) The extraordinary item in 2002 is a loss related to the early extinguishment
of debt ($17 million after-tax, or $0.06 loss per basic and diluted share).
For additional information related to the extraordinary item, please read
Note 9 to our consolidated financial statements.

44

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

The following discussion and analysis should be read in combination with
our consolidated financial statements included in Item 8 herein.

OVERVIEW

We are a public utility holding company, created on August 31, 2002 as part
of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) in
compliance with requirements of the Texas electric restructuring law. We are the
successor to Reliant Energy for financial reporting purposes under the
Securities Exchange Act of 1934. Our wholly owned operating subsidiaries own and
operate electric generation plants, electric transmission and distribution
facilities, natural gas distribution facilities and natural gas pipelines. We
are subject to regulation as a "registered holding company" under the Public
Utility Holding Company Act of 1935 (1935 Act). At December 31, 2002, our wholly
owned subsidiaries included:

- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in our electric transmission and distribution business in the
Texas Gulf Coast area;

- Texas Genco Holdings, Inc. (Texas Genco), which owns and operates our
Texas generating plants; and

- CenterPoint Energy Resources Corp. (CERC Corp., and, together with its
subsidiaries, CERC), which owns and operates our local gas distribution
companies, gas gathering systems and interstate pipelines.

We distributed our 83%-ownership interest in Reliant Resources, Inc.
(Reliant Resources) to our shareholders on September 30, 2002 (the Reliant
Resources Distribution).

We distributed approximately 19% of the outstanding common stock of Texas
Genco to our shareholders on January 6, 2003.

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

- Electric Transmission & Distribution;

- Electric Generation;

- Natural Gas Distribution;

- Pipelines and Gathering; and

- Other Operations.

Effective with the full deregulation of sales of electric energy to retail
customers in Texas beginning in January 2002, power generators and retail
electric providers in Texas ceased to be subject to traditional cost-based
regulation. Since that date, we have sold generation capacity, energy and
ancillary services related to power generation at prices determined by the
market. Our transmission and distribution services remain subject to rate
regulation.

Beginning January 1, 2002, the basis of business segment reporting has
changed for our Texas electric operations. Although our former retail sales
business is no longer conducted by us, retail customers remained regulated
customers of our former integrated electric utility, Reliant Energy HL&P,
through the date of their first meter reading in 2002. Sales of electricity to
retail customers in 2002 prior to this meter reading are reflected in the
Electric Transmission & Distribution business segment. The Texas generation
operations of Reliant Energy HL&P are now a separate reportable business
segment, Electric Generation, whereas they previously had been part of the
Electric Operations business segment. The remaining transmission and
distribution function is now reported separately in the Electric Transmission &
Distribution business segment. In 2001, Latin America was a separate business
segment, but is now reported in the Other Operations business segment.
Reportable business segments from 2001 have been restated to conform to the 2002
presentation.
45

For business segment reporting information, please read Notes 1 and 17 to our
consolidated financial statements.

The consolidated financial statements have been prepared to reflect the
effects of the Reliant Resources Distribution on the CenterPoint Energy
financial statements. The consolidated financial statements present the Reliant
Resources businesses (previously reported as the Wholesale Energy, European
Energy and Retail Energy business segments and related corporate costs) as
discontinued operations, in accordance with Statement of Financial Accounting
Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of
Long-Lived Assets" (SFAS No. 144). Accordingly, the consolidated financial
statements include the necessary reclassifications to reflect these operations
as discontinued operations for each of the three years in the period ended
December 31, 2002.

As a result of the Reliant Resources Distribution, CenterPoint Energy
recorded a non-cash loss on disposal of discontinued operations of $4.3 billion
in the third quarter of 2002. This loss represents the excess of the carrying
value of CenterPoint Energy's net investment in Reliant Resources over the
market value of Reliant Resources' common stock.

As of December 31, 2001 the Latin America business operations were no
longer reported as discontinued operations and were presented as a single line
item in continuing operations within the Statement of Consolidated Operations
and as a single line item on the Consolidated Balance Sheet in accordance with
Emerging Issues Task Force Issue No. 90-6, "Accounting for Certain Events, Not
Addressed in Issue No. 87-11 Relating to an Acquired Operating Unit to Be Sold."
Effective January 1, 2002, we adopted SFAS No. 144, which does not permit this
single line presentation for assets held and used, such as our Latin America
investments. Certain reclassifications have been made to our consolidated
financial statements to show the retroactive effects of adoption of SFAS No.
144.

In February 2003, the Company sold its interest in Argener, a cogeneration
facility in Argentina, for $23.1 million. The carrying value of this investment
was approximately $11 million as of December 31, 2002.

46

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

CONSOLIDATED RESULTS OF OPERATIONS

47

The following discussion of consolidated results of operations and results
of operations by business segment is based on earnings from continuing
operations before interest expense, distribution on trust preferred securities,
income taxes, extraordinary item and cumulative effect of accounting change
(EBIT). EBIT, as defined, is shown because it is a financial measure we use to
evaluate the performance of our business segments and we believe it is a measure
of financial performance that may be used as a means to analyze and compare
companies on the basis of operating performance. We expect that some analysts
and investors will want to review EBIT when evaluating our company. EBIT is not
defined under accounting principles generally accepted in the United States
(GAAP), should not be considered in isolation or as a substitute for a measure
of performance prepared in accordance with GAAP and is not indicative of
operating income from operations as determined under GAAP. Additionally, our
computation of EBIT may not be comparable to other similarly titled measures
computed by other companies, because all companies do not calculate it in the
same fashion. We consider operating income to be a comparable measure under
GAAP. We believe the difference between operating income and EBIT on both a
consolidated and business segment basis is not material. We have provided a
reconciliation of consolidated operating income to EBIT and EBIT to net income
below as well as in the individual business segment discussion that follows.

2002 COMPARED TO 2001

Income from Continuing Operations. We reported income from continuing
operations before the cumulative effect of accounting change, extraordinary
item, and preferred dividends of $386 million ($1.29 per diluted share) for 2002
compared to $447 million ($1.53 per diluted share) for 2001. Effective January
1, 2002, we discontinued amortizing goodwill in accordance with SFAS No. 142,
"Goodwill and Other Intangibles" (SFAS No. 142). During 2001, we recognized $49
million of goodwill amortization expense. The $61 million decrease in income
from continuing operations before the cumulative effect of accounting change,

48

extraordinary item and preferred dividends for the year ended December 31, 2002
as compared to the same period in 2001 was primarily due to the following:

- a $160 million decrease in EBIT from our Electric business segments,
reflecting the movement of a portion of this business to Reliant
Resources' Retail Energy business segment and reduced rates of return on
these regulated operations effective January 2002;

- a $61 million increase in EBIT from our Natural Gas Distribution business
segment;

- a $20 million increase in EBIT from our Pipelines and Gathering business
segment;

- a $142 million increase in EBIT from our Other Operations business
segment;

- a $131 million increase in interest expense due to higher borrowing
costs; and

- a $20 million decrease in income tax expense.

Income Tax Expense. The effective tax rates for 2002 and 2001 were 35.0%
and 33.8%, respectively. The increase in the effective tax rate for 2002
compared to 2001 was primarily due to an increase in state taxes, a reduced
benefit from the amortization of investment tax credits and a higher effective
tax rate related to our Latin America operations, offset by the discontinuance
of goodwill amortization in accordance with SFAS No. 142.

Extraordinary Item. The 2002 results reflect a $17 million after-tax loss
resulting from the early extinguishment of debt related to CenterPoint Houston's
$850 million term loan and the repurchase of $175 million of CenterPoint
Energy's pollution control bonds.

Cumulative Effect of Accounting Change. The 2001 results reflect a $59
million after-tax non-cash gain from the adoption of SFAS No. 133, "Accounting
for Derivative Instruments and Hedging Activities," as amended (SFAS No. 133).
For additional discussion of the adoption of SFAS No. 133, please read Note 5 to
our consolidated financial statements.

2001 COMPARED TO 2000

Income From Continuing Operations. We reported income from continuing
operations of $447 million ($1.53 per diluted share) for 2001, before a
cumulative effect of accounting change of $59 million, net of tax, related to
the adoption of SFAS No. 133, compared to $222 million ($0.77 per diluted share)
for 2000.

The increase in income from continuing operations of $225 million was
primarily due to the following:

- a $348 million decrease in loss before income and taxes from our Other
Operations business segment, primarily due to a $269 million decrease in
losses/impairments related to our Latin America operations and a $91
million decrease in a non-cash loss on our AOL Time Warner investment and
our related indexed debt securities in 2001 as compared to 2000; and

- a $27 million increase in EBIT from our Natural Gas Distribution segment.

The above items were partially offset by:

- a $102 million decrease in EBIT from our Electric business segments
primarily due to the impact of milder weather, reduced rates charged to
certain governmental agencies as mandated by the Texas electric
restructuring law, fees paid for the early termination of an accounts
receivable factoring agreement and higher benefit expenses; and

- an increase in net interest expense of $43 million primarily related to
interest rate swaps entered into in 2001 and the issuance of the Series
2001-1 Transition Bonds in 2001.

Income Tax Expense. The effective tax rates for 2001 and 2000 were 33.8%
and 51.3%, respectively. The decrease in the effective tax rate in 2001 compared
to 2000 was primarily due to non-recurring increased tax expense arising from
the sale of our Latin America investments, including the write-off of deferred
tax

49

assets related to the Latin America business segment in 2000 and a decrease in
state taxes in 2001 compared to 2000.

AOL TIME WARNER INVESTMENT AND INDEXED DEBT SECURITIES

In 2002, holders of approximately 16% of the 17.2 million 2.0% Zero-Premium
Exchangeable Subordinated Notes due 2029 (ZENS) originally issued exercised
their right to exchange their ZENS for cash, resulting in aggregate cash
payments by CenterPoint Energy of approximately $45 million.

One of our subsidiaries owns shares of AOL TW common stock (AOL TW Common)
and elected to liquidate a portion of such holdings to facilitate the company's
making the cash payments for the ZENS exchanged in 2002. In connection with the
exchanges in 2002, we received net proceeds of approximately $43 million from
the liquidation of approximately 4.1 million shares of AOL TW Common at an
average price of $10.56 per share. We now hold 21.6 million shares of AOL TW
Common which are classified as trading securities under SFAS No. 115 and are
expected to be held to facilitate our ability to meet our obligation under the
ZENS.

For additional information regarding our investment in AOL TW, our indexed
debt securities and the effect of adoption of SFAS No. 133 on January 1, 2001 on
our ZENS obligation, please read Note 7 to our consolidated financial
statements.

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents EBIT (in millions) for each of our business
segments for 2000, 2001 and 2002. Some amounts from the previous years have been
reclassified to conform to the 2002 presentation of the financial statements.
These reclassifications do not affect consolidated net income.

EBIT BY BUSINESS SEGMENT

ELECTRIC BUSINESS SEGMENTS

Beginning in 2002, we are reporting two new business segments for what was
the former Electric Operations business segment:

- Electric Transmission & Distribution; and

- Electric Generation.

The Electric Transmission & Distribution business segment reports results
from two sources. This business segment includes the regulated electric
transmission and distribution operations as well as impacts of

50

generation-related stranded costs recoverable by the regulated utility. The
previously regulated generation operations in Texas are being reported in the
new Electric Generation business segment.

As a result of the implementation of deregulation and the corresponding new
business segments, the regulated transmission and distribution utility recovers
the cost of its service through an energy delivery charge, and not as a
component of the prior bundled rate, which included energy and delivery charges.
The design of the new energy delivery rate differs from the prior bundled rate.
The winter/summer rate differential for residential customers has been
eliminated and the energy component of the rate structure for commercial and
industrial customers has been removed, which will tend to lessen some of the
pronounced seasonal variation of revenues which has been experienced in prior
periods.

Although our former retail sales business is no longer conducted by us,
retail customers remained regulated customers of Reliant Energy HL&P through the
date of their first meter reading in 2002. Operations during this transition
period are reflected in the Electric Transmission & Distribution business
segment.

The new Electric Transmission & Distribution business segment, CenterPoint
Houston, reported EBIT of $1.1 billion for 2002, consisting of EBIT of $421
million for the regulated electric transmission and distribution business,
including retail sales during the transition period as discussed above, and
non-cash EBIT of $697 million of Excess Cost Over Market (ECOM) regulatory
assets associated with costs recorded pursuant to the Texas electric
restructuring law as explained below. Operating revenues were $1.5 billion,
excluding ECOM, and purchased power costs were $66 million in 2002. The
purchased power costs relate to operation of the regulated utility during the
transition period discussed above.

In the Electric Transmission & Distribution business segment, throughput
declined 2% during 2002 as compared to 2001. The decrease was primarily due to
reduced energy delivery in the industrial sector resulting from self-generation
by several major customers, partially offset by increased residential usage
primarily due to non-weather related factors. Additionally, despite a slowing
economy, total metered customers continued to grow at an annual rate of
approximately 2% during the year.

The new Electric Generation business segment, Texas Genco, is comprised of
over 14,000 megawatts of electric generation located entirely in the state of
Texas. This business segment reported a loss before interest and taxes of $130
million for 2002, primarily due to low natural gas prices and ample generating
capacity in Texas, which created a weak price environment when the capacity
auctions described below were conducted in late 2001 and early 2002. Operating
revenues were $1.5 billion and fuel and purchased power costs were $1.1 billion
in 2002.

Under the Texas electric restructuring law, each power generator that is
unbundled from an integrated electric utility in Texas has an obligation to
conduct state mandated capacity auctions of 15% of its capacity. In addition,
under a master separation agreement between CenterPoint Energy and Reliant
Resources, Texas Genco is contractually obligated to auction all capacity in
excess of the state mandated capacity auctions. The auctions conducted
periodically between September 2001 and January 2003 were consummated at prices
below those used in the ECOM model by the Texas Utility Commission. Under the
Texas electric restructuring law, a regulated utility, in our case, CenterPoint
Houston, may recover in a regulatory proceeding scheduled for 2004 any
difference between market prices received through the state mandated auctions
and the Texas Utility Commission's earlier estimates of those market prices.
This difference, recorded as a regulatory asset, produced $697 million of EBIT
in 2002.

51

The following tables provide summary data of our Electric Transmission &
Distribution and Electric Generation business segments for 2002 and our Electric
Operations business segment for 2000 and 2001 (in millions, except throughput,
power sales and electric sales data):

2002 Compared to 2001. During 2001, our Electric Operations business
segment reflected the regulated electric utility business, including generation,
transmission and distribution, and retail electric sales. As of January 1, 2002,
with the opening of the Texas market to full retail electric competition,
generation and retail sales are no longer subject to cost of service regulation.
Retail electric sales involve the sale of electricity and related services to
end users of electricity and were included as part of the bundled regulated
service prior to 2002. Beginning in January 2002, our operations no longer
include retail electricity sales. Accordingly, there are no meaningful
comparisons for these business segments against prior periods.

Operation and maintenance expenses for the Electric Transmission &
Distribution and Electric Generation segments decreased by $86 million in 2002
compared to those of the Electric Operations business segment in 2001. The
decrease was primarily due to:

- a $77 million decrease in factoring expense as a result of the
termination of an agreement under which the former Electric Operations
business segment had sold its customer accounts receivable;

- a $22 million decrease due to fewer plant outages in 2002;

- a $10 million decrease in transmission cost of service; and

- a $16 million decrease in transmission line losses in 2002 as this is now
a cost of retail electric providers.

These decreases were partially offset by a $40 million increase in benefits
expense, including severance costs of $23 million in connection with the
voluntary early retirement program resulting from the mothballing of generating
capacity by Texas Genco and the reduction in work force by CenterPoint Houston
in 2002.

In June 1998, the Texas Utility Commission issued an order approving a
transition to competition plan (Transition Plan) filed by Reliant Energy in
December 1997. In order to reduce Reliant Energy's exposure to potential
stranded costs related to generation assets, the Transition Plan permitted the
redirection of depreciation expense to generation assets that Reliant Energy
otherwise would apply to transmission, distribution and general plant assets. In
addition, the Transition Plan provided that all earnings above a stated overall
annual rate of return on invested capital be used to recover Reliant Energy's
investment in generation

53

assets. Reliant Energy implemented the Transition Plan effective January 1,
1998. For further discussion of the Transition Plan, please read Note 4(a) to
our consolidated financial statements.

Depreciation and amortization decreased $25 million in 2002, compared to
2001. The decrease was primarily due to a decrease in amortization of the book
impairment regulatory asset ($281 million) recorded in June 1999, which was
fully amortized in December 2001, offset by depreciation expense recorded in
2002 as a result of the discontinuance of redirection of depreciation expense
related to electric transmission and distribution assets ($217 million) and
increased amortization related to transition property associated with the
transition bonds issued in November 2001 ($35 million). For further discussion
related to the impairment recorded in June 1999, please read Note 4(a) to our
consolidated financial statements.

Taxes other than income taxes decreased $120 million compared to 2001. The
decrease was primarily due to lower property taxes due to lower tax valuations
of generation assets ($10 million), lower gross receipts taxes ($64 million),
which became the responsibility of the retail electric providers upon
deregulation, and lower franchise taxes ($46 million).

Other income, net decreased $21 million in 2002 compared to 2001. The
decrease was primarily due to a $37 million decrease in interest income from
under-recovery of fuel in 2002 as compared to 2001, partially offset by a $19
million increase in interest income from affiliated parties.

2001 Compared to 2000. Our Electric Operations business segment's EBIT for
2001 decreased $102 million compared to 2000. The decrease was primarily due to
milder weather, decreased customer demand, increased contract services and
benefit expenses and a charge recorded in the fourth quarter of 2001 resulting
from the early termination of an accounts receivable factoring agreement. The
decrease was also due to the implementation of the pilot program for Texas
deregulation in August 2001, reduced rates for certain governmental agencies and
increased administrative expenses related to the separation of our regulated and
unregulated businesses. These decreases were partially offset by decreased
amortization expense and customer growth.

Operating revenues increased $17 million in 2001. Base revenues decreased
$119 million in 2001 due to decreased customer demand as a result of the effect
of milder weather compared to 2000 and decreased customer usage on a weather
normalized basis. The weather impact represented approximately $84 million of
the decrease in base revenues in 2001 as compared to 2000. This decrease was
offset by increased reconcilable fuel revenue of $136 million. The 6% increase
in reconcilable fuel revenue in 2001 resulted primarily from increased fuel
costs as discussed below. The Texas Utility Commission provides for recovery of
certain fuel and purchased power costs through a fixed fuel factor included in
electric rates. Revenues collected through this factor are adjusted monthly to
equal expenses; therefore, these revenues and expenses have no effect on
earnings unless fuel costs are subsequently determined not to be recoverable.
The adjusted over/under recovery of fuel costs is recorded in our Consolidated
Balance Sheets as regulatory liabilities or regulatory assets, respectively.

Fuel and purchased power expenses in 2001 increased by $130 million, or 5%,
over 2000 expenses. This increase is due to increased purchased power volume
related to the load balancing requirements associated with ERCOT adapting to a
single control area, with a slightly higher cost for purchased power ($44.26 and
$44.42 per megawatt hour in 2000 and 2001, respectively). The purchased power
increase was partially offset by the decline in the volume of natural gas used
at a slightly higher rate ($3.98 and $4.23 per million British thermal units in
2000 and 2001, respectively).

Operation and maintenance expenses increased $74 million in 2001 compared
to 2000 primarily due to the following items:

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

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

- an $11 million increase in administrative expenses related to the
separation of our regulated and unregulated businesses; and
54

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

Depreciation and amortization expense decreased $54 million primarily due
to a decrease in amortization of the book impairment regulatory asset recorded
in June 1999 and decreased amortization expense due to regulatory assets related
to cancelled projects being fully amortized in June 2000, partially offset by
accelerated amortization of certain regulatory assets related to energy
conservation management as required by the Texas Utility Commission.

Other income, net increased $25 million in 2001 compared to 2000. The
increase was primarily due to an increase in interest income from under-recovery
of fuel in 2001 compared to 2000.

NATURAL GAS DISTRIBUTION

Our Natural Gas Distribution business segment's operations consist of
intrastate natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers in Arkansas, Louisiana,
Minnesota, Mississippi, Oklahoma and Texas. This business segment's operations
also include non-rate regulated natural gas sales to and transportation services
for commercial and industrial customers in the six states listed above as well
as several other Midwestern states.

The following table provides summary data of our Natural Gas Distribution
business segment for 2000, 2001 and 2002 (in millions, except throughput data):

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

2002 Compared to 2001. Our Natural Gas Distribution business segment's
EBIT increased $61 million for the year ended December 31, 2002 as compared to
the same period in 2001. Operating margins (revenues less fuel costs) in 2002
were $37 million higher than in 2001 primarily as a result of improved margins
from

55

rate increases in 2002, a 5% increase in throughput and changes in estimates of
unbilled revenues and deferred gas costs, which reduced operating margins in
2001.

Operation and maintenance expenses decreased $2 million in 2002 as compared
to 2001 primarily due to a reduction in bad debt expense in 2002 as a result of
improved collections and lower gas prices, offset by higher benefits expense and
administrative expenses.

Depreciation and amortization expense decreased approximately $21 million
for the year ended December 31, 2002 primarily as a result of the discontinuance
of goodwill amortization in accordance with SFAS No. 142 as further discussed in
Note 3(d) to our consolidated financial statements. Goodwill amortization was
$31 million for the year ended December 31, 2001. This was partially offset by
an increase in depreciation expense due to an increased asset base.

Taxes other than income taxes decreased $8 million for the year ended
December 31, 2002 as compared to the same period in 2001, due primarily to
reduced franchise fees as a result of decreased revenues.

2001 Compared to 2000. Our Natural Gas Distribution business segment's
EBIT increased $27 million in 2001 from 2000. Operating margins (revenues less
fuel costs) in 2001 were $14 million higher than in 2000 primarily due to
increased volumes in the first quarter of 2001 due to the effect of colder
weather, partially offset by changes in estimates of unbilled revenues and
recoverability of deferred gas accounts and other items.

Operation and maintenance expenses decreased $12 million in 2001 as
compared to 2000 primarily due to expenses totaling approximately $31 million
incurred in 2000 in connection with exiting certain non-rate regulated natural
gas business activities outside our established market areas offset by the
following items:

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

- higher employee benefit costs.

Other income, net increased $15 million in 2001 compared to 2000. The
increase was primarily due to a $12 million increase in interest income from
affiliated parties.

PIPELINES AND GATHERING

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

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The following table provides summary data of our Pipelines and Gathering
business segment for 2000, 2001 and 2002 (in millions, except throughput data):

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

(1) Elimination of volumes both transported and sold.

2002 Compared to 2001. Our Pipelines and Gathering business segment's EBIT
increased $20 million in 2002 from 2001 as discussed below.

Operation and maintenance expenses increased $9 million for the year ended
December 31, 2002 compared to 2001 primarily due to project work consisting of
construction management, material acquisition, engineering, project planning and
other services as well as increased employee benefit costs. Project work
expenses are offset by revenues billed for these services.

Depreciation and amortization expense decreased $17 million in 2002 as
compared to 2001 primarily as a result of the discontinuance of goodwill
amortization in accordance with SFAS No. 142 as further discussed in Note 3(d)
to our consolidated financial statements.

Other income increased $4 million in 2002 as compared to 2001 primarily due
to interest accrued on a fuel-related sales tax refund.

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

OTHER OPERATIONS

Our Other Operations business segment consists primarily of our Latin
America operations, office buildings and other real estate used in our business
operations, district cooling in the central business district in downtown
Houston, energy management services and other corporate operations which support
all of our business operations.

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The following table shows EBIT of our Other Operations business segment for
the 2000, 2001 and 2002:

2002 Compared to 2001. Our Other Operations business segment's EBIT
increased by $142 million in 2002 compared to 2001. The increase was primarily
due to a $79 million pre-tax decrease in losses/ impairments related to our
Latin America investments, reductions in unallocated corporate costs of $34
million and reductions in corporate accruals, primarily benefits, of $27
million.

2001 Compared to 2000. Other Operations' loss before interest and taxes
decreased by $348 million in 2001 compared to 2000. This decrease was primarily
due to a $269 million pre-tax decrease in losses/ impairments related to our
Latin America investments in 2000 and a $91 million pre-tax decrease in a non-
cash loss on our AOL TW investment and related indexed debt securities in 2001
as compared to 2000.

DISCONTINUED OPERATIONS

On September 30, 2002, CenterPoint Energy distributed all of the shares of
Reliant Resources common stock owned by CenterPoint Energy on a pro rata basis
to shareholders of CenterPoint Energy common stock. The consolidated financial
statements have been prepared to reflect the effect of the Reliant Resources
Distribution as described above on the CenterPoint Energy consolidated financial
statements. The consolidated financial statements present the Reliant Resources
businesses (Wholesale Energy, European Energy, Retail Energy and related
corporate costs) as discontinued operations for each of the years in the two
year period ended December 31, 2001 and for the nine months ended September 30,
2002. We also recorded a $4.4 billion non-cash loss on disposal of these
discontinued operations. This loss represents the excess of the carrying value
of our net investment in Reliant Resources over the market value of Reliant
Resources common stock.

FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS

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

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

- state and federal legislative and regulatory actions or developments,
including deregulation, re-regulation and restructuring of the electric
utility industry, constraints placed on our activities or business by the
1935 Act, changes in or application of laws or regulations applicable to
other aspects of our business and actions with respect to:

- approval of stranded costs;

- allowed rates of return;

- rate structures;

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- recovery of investments; and

- operation and construction of facilities;

- non-payment for our services due to financial distress of our customers,
including Reliant Resources;

- the successful and timely completion of our capital projects;

- industrial, commercial and residential growth in our service territory
and changes in market demand and demographic patterns;

- changes in business strategy or development plans;

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

- changes in interest rates or rates of inflation;

- unanticipated changes in operating expenses and capital expenditures;

- weather variations and other natural phenomena;

- commercial bank and financial market conditions, our access to capital,
the cost of such capital, receipt of certain approvals under the 1935
Act, and the results of our financing and refinancing efforts, including
availability of funds in the debt capital markets;

- actions by rating agencies;

- legal and administrative proceedings and settlements;

- changes in tax laws;

- inability of various counterparties to meet their obligations with
respect to our financial instruments;

- any lack of effectiveness of our disclosure controls and procedures;

- changes in technology;

- significant changes in our relationship with our employees, including the
availability of qualified personnel and the potential adverse effects if
labor disputes or grievances were to occur;

- significant changes in critical accounting policies;

- acts of terrorism or war, including any direct or indirect effect on our
business resulting from terrorist attacks such as occurred on September
11, 2001 or any similar incidents or responses to those incidents;

- the availability and price of insurance;

- the outcome of the pending securities lawsuits against us, Reliant Energy
and Reliant Resources;

- the outcome of the Securities and Exchange Commission investigation
relating to the treatment in our consolidated financial statements of
certain activities of Reliant Resources;

- the ability of Reliant Resources to satisfy its indemnity obligations to
us;

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

- political, legal, regulatory and economic conditions and developments in
the United States; and

- other factors discussed in Item 1 of this report under "Risk Factors."

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LIQUIDITY AND CAPITAL RESOURCES

HISTORICAL CASH FLOWS

The net cash provided by/used in operating, investing and financing
activities for 2000, 2001 and 2002 is as follows (in millions):

CASH PROVIDED BY OPERATING ACTIVITIES

Net cash provided by operations in 2002 decreased $1.5 billion compared to
2001. This decrease primarily resulted from a $1.0 billion increase in net
regulatory assets and liabilities due primarily to refunds of excess mitigation
credits to ratepayers in 2002 ($224 million) and an increase in non-cash revenue
related to the ECOM true-up, which resulted in a $697 million increase in
regulatory assets in 2002, as well as $156 million paid in connection with the
settlement of forward-starting interest rate swaps with an aggregate notional
amount of $1.5 billion. Other changes in working capital also contributed to
this decrease.

Net cash provided by operations in 2001 increased $776 million compared to
2000. This increase primarily resulted from:

- significant reductions in accounts receivable, partially offset by
reductions in accounts payable, during 2001 compared to 2000 as a result
of higher natural gas prices experienced in late 2000; and

- an increase in recovered fuel costs by our Electric business segments.

This increase was partially offset by other changes in working capital.

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities decreased $396 million during 2002
compared to 2001 due primarily to decreased environmental-related capital
expenditures in our electric business segments.

Net cash used in investing activities increased $921 million during 2001
compared to 2000. This increase was primarily due to additional capital
expenditures in 2001 of $305 million primarily related to our Electric business
segments, offset by net proceeds of $729 million received in 2000 from the sale
of our Latin America assets, net of investments and advances.

CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

Cash flows provided by financing activities increased $1.8 billion in 2002
compared to 2001, primarily due to an increase in short-term borrowings of $668
million as compared to a decrease in short-term borrowings of $1.4 billion in
2001.

Cash flows used in financing activities increased $2.4 billion in 2001
compared to 2000, primarily due to a decline in short term borrowings, partially
offset by an increase in proceeds from long-term debt.

FUTURE SOURCES AND USES OF CASH

We believe that our borrowing capability combined with cash flows from
operations will be sufficient to meet the operational capital and debt service
needs of our businesses for the next twelve months.

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Our liquidity and capital requirements will be affected by:

- capital expenditures;

- debt service requirements;

- various regulatory actions; and

- working capital requirements.

The following table sets forth our capital requirements for 2002, and
estimates of our capital requirements for 2003 through 2007 (in millions):

- ---------------
(1) It is anticipated that Reliant Resources will purchase the majority interest
in Texas Genco held by CenterPoint Energy in early 2004 pursuant to the
terms of an option that Reliant Resources holds or that this interest or
individual generating assets will otherwise be sold to one or more other
parties.

The following table sets forth estimates of our contractual obligations to
make future payments for 2003 through 2007 and thereafter (in millions):

- ---------------
(1) On February 28, 2003, CenterPoint Energy extended the termination date of
its $3.85 billion credit facility to June 30, 2005 as discussed further
below. As a result of this extension, the $3.85 billion credit facility has
been classified as long-term debt as of December 31, 2002 in the
Consolidated Balance Sheet.

(2) For a discussion of operating leases, please read Note 13(b) to our
consolidated financial statements.

(3) For a discussion of other commodity commitments, please read Note 13(a) to
our consolidated financial statements.

Long-Term Debt. Our long-term debt consists of our obligations and
obligations of our subsidiaries, including transition bonds issued by an
indirect wholly owned subsidiary (transition bonds).

On February 28, 2003, we reached agreement with a syndicate of banks on a
second amendment to our $3.85 billion bank facility (the "Second Amendment").
Under the Second Amendment, the maturity date of the bank facility was extended
from October 2003 to June 30, 2005, and the $1.2 billion in mandatory
prepayments that would have been required this year (including $600 million due
on February 28, 2003) were

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eliminated. The facility consists of a $2.35 billion term loan and a $1.5
billion revolver. The revolver was fully drawn as of February 28, 2003.
Borrowings bear interest based on the London interbank offered rate (LIBOR)
under a pricing grid tied to our credit rating. At our current credit ratings,
the pricing for loans remains the same. The drawn cost for the facility at our
current ratings is LIBOR plus 450 basis points. We have agreed to pay the banks
an extension fee of 75 basis points on the amounts outstanding under the bank
facility on October 9, 2003. We also paid $41 million in fees that were due on
February 28, 2003, along with $20 million in fees that had been due on June 30,
2003.

In addition, the interest rates will be increased by 25 basis points
beginning May 28, 2003 if we do not grant the banks a security interest in our
81% stock ownership of Texas Genco. Granting the security interest in the stock
of Texas Genco requires approval from the SEC under the 1935 Act, which is
currently being sought. That security interest would be released when we sell
Texas Genco, which is expected to occur in 2004. Proceeds from the sale will be
used to reduce the bank facility.

Also under the Second Amendment, on or before May 28, 2003, we expect to
grant to the banks warrants to purchase up to 10%, on a fully diluted basis, of
our common stock at a price equal to the greater of $6.56 per share or 110% of
the closing price on the New York Stock Exchange on the date the warrants are
issued. The warrants would not be exercisable for a year after issuance but
would remain outstanding for four years; provided, that if we reduce the bank
facility during 2003 by specified amounts, the warrants will be extinguished. To
the extent that we reduce the bank facility by up to $400 million on or before
May 28, 2003, up to half of the warrants will be extinguished on a basis
proportionate to the reduction in the credit facility. To the extent such
warrants are not extinguished on or before May 28, 2003, they will vest and
become exercisable in accordance with their terms. Whether or not we are able to
extinguish warrants on or before May 28, 2003, the remaining 50% of the warrants
will be extinguished, again on a proportionate basis, if we reduce the bank
facility by up to $400 million by the end of 2003. We plan to eliminate the
warrants entirely before they vest by accessing the capital markets to fund the
total payments of $800 million during 2003; however, because of current
financial market conditions and uncertainties regarding such conditions over the
balance of the year, there can be no assurance that we will be able to
extinguish the warrants or to do so on favorable terms.

The warrants and the underlying common stock would be registered with the
SEC and could be exercised either through the payment of the purchase price or
on a "cashless" basis under which we would issue a number of shares equal to the
difference between the then-current market price and the warrant exercise price.
Issuance of the warrants is also subject to obtaining SEC approval under the
1935 Act, which is currently being sought. If that approval is not obtained on
or before May 28, 2003, we will provide the banks equivalent cash compensation
over the term that our warrants would have been exercisable to the extent they
are not otherwise extinguished.

In the Second Amendment, we also agreed that our quarterly common stock
dividend will not exceed $0.10 per share. If we have not reduced the bank
facility by a total of at least $400 million by the end of 2003, of which at
least $200 million has come from the issuance of capital stock or securities
linked to capital stock (such as convertible debt), the maximum dividend payable
during 2004 and for the balance of the term of the facility is subject to an
additional test. Under that test the maximum permitted quarterly dividend will
be the lesser of (i) $0.10 per share or (ii) 12.5% of our net income per share
for the 12 months ended on the last day of the previous quarter.

The Second Amendment provides that proceeds from capital stock or
indebtedness issued or incurred by us must be applied (subject to a $200 million
basket for CERC and another $250 million basket for borrowings by us and other
limited exceptions) to repay bank loans and reduce the bank facility. Similarly,
cash proceeds from the sale of assets of more than $30 million or, if less, a
group of sales aggregating more than $100 million, must be applied to repay bank
loans and reduce the bank facility, except that proceeds of up to $120 million
can be reinvested in our businesses.

On November 12, 2002, CenterPoint Houston entered into a $1.3 billion
collateralized term loan maturing November 2005. The interest rate on the loan
is LIBOR plus 9.75%, subject to a minimum rate of 12.75%. The loan is secured by
CenterPoint Houston's general mortgage bonds. Proceeds from the loan were
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used (1) to repay CenterPoint Houston's $850 million term loan, (2) to repay
$300 million of debt that matured on November 15, 2002, (3) to purchase $100
million of pollution control bonds on December 2, 2002, and (4) to pay costs of
issuance. The loan agreement contains various business and financial covenants,
including a covenant restricting CenterPoint Houston's debt, excluding
transition bonds, as a percent of its total capitalization to 68%. The loan
agreement also limits incremental secured debt that may be issued by CenterPoint
Houston to $300 million.

One of our indirect finance subsidiaries, CenterPoint Energy Transition
Bond Company, LLC, has $736 million aggregate principal amount of outstanding
transition bonds that were issued in 2001 in accordance with the Texas electric
restructuring law. Classes of the transition bonds have final maturity dates of
September 15, 2007, September 15, 2009, September 15, 2011 and September 15,
2015 and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively.
The transition bonds are secured by "transition property," as defined in the
Texas electric restructuring law, which includes the irrevocable right to
recover, through non-bypassable transition charges payable by retail electric
customers, qualified costs provided in the Texas electric restructuring law. The
transition bonds are reported as our long-term debt, although the holders of the
transition bonds have no recourse to any of our assets or revenues, and our
creditors have no recourse to any assets or revenues (including, without
limitation, the transition charges) of the transition bond company. CenterPoint
Houston has no payment obligations with respect to the transition bonds except
to remit collections of transition charges as set forth in a servicing agreement
between CenterPoint Houston and the transition bond company and in an
intercreditor agreement among CenterPoint Houston, our indirect transition bond
subsidiary and other parties.

We purchased $175 million principal amount of outstanding pollution control
bonds in the fourth quarter of 2002 at 100% of their principal amount. If market
conditions permit, we expect to remarket the $175 million principal amount of
pollution control bonds in the first half of 2003.

Long-term debt maturities in 2003 include $150 million principal amount of
medium-term notes maturing in April 2003 and $16.6 million principal amount of
pollution control bonds maturing in December 2003. In addition, CERC Corp. has
$500 million principal amount of Term Enhanced Remarketable Securities that must
be repaid or remarketed in November 2003.

We have $840 million of outstanding ZENS that may be exchanged for cash at
any time. Holders of ZENS submitted for exchange are entitled to receive a cash
payment equal to 95% of the market value of the reference shares of AOL TW
Common. There are 1.5 reference shares of AOL TW Common for each of the 17.2
million ZENS units originally issued (of which approximately 16% were exchanged
for cash of approximately $45 million in 2002). The exchange market value is
calculated using the average closing price per share of AOL TW Common on the New
York Stock Exchange on one or more trading days following the notice date for
the exchange. One of our subsidiaries owns the reference shares of AOL TW Common
and generally liquidates such holdings to the extent of ZENS exchanged. Cash
proceeds from such liquidations are used to fund ZENS exchanged for cash.
Although proceeds from the sale of AOL TW Common offset the cash paid on
exchanges, ZENS exchanges result in a cash outflow because of our current tax
obligations. Current tax obligations in 2002 increased by $58 million as a
result of the 2002 exchanges of ZENS having a principal amount of $160 million
and the related sale of 4.1 million shares of AOL TW Common.

CenterPoint Houston has issued approximately $1.2 billion aggregate
principal amount of first mortgage bonds and approximately $1.8 billion
aggregate principal amount of general mortgage bonds, of which approximately
$1.1 billion combined aggregate principal amount of first mortgage bonds and
general mortgage bonds collateralizes debt of CenterPoint Energy. The general
mortgage bonds are issued under the General Mortgage Indenture dated as of
October 10, 2002. The lien of the general mortgage indenture is junior to that
of the Mortgage, pursuant to which the first mortgage bonds are issued. The
aggregate amount of additional general mortgage bonds and first mortgage bonds
that could be issued is approximately $900 million based on estimates of the
value of property encumbered by the General Mortgage, the cost of such property
and the 70% bonding ratio contained in the General Mortgage. The issuance of
additional first mortgage and general mortgage bonds is currently contractually
limited to an additional $300 million of general mortgage bonds.

63

Short-Term Debt and Receivables Facility. During 2003, the following bank
and receivables facilities are scheduled to terminate on the dates indicated.

As of December 31, 2002, there was $347 million borrowed under CERC's $350
million revolving credit facility. On February 28, 2003, CERC executed a
commitment letter with a major bank for a $350 million, 180-day bridge facility,
which is subject to the satisfation of various closing conditions. This facility
will be available for repaying borrowings under CERC's existing $350 million
revolving credit facility that expires on March 31, 2003 in the event sufficient
proceeds are not raised in the capital markets to repay such borrowings on or
before March 31, 2003. Final terms for the bridge facility have not been
established, but it is anticipated that the rates for borrowings under the
facility will be LIBOR plus 450 basis points. CERC paid a commitment fee of 25
basis points on the commitment amount and will be required to pay a facility fee
of 75 basis points on the amount funded and an additional 100 basis points on
the amount funded and outstanding for more than two months. In connection with
this facility, CERC expects to provide the lender with collateral in the form of
a security interest in the stock it owns in its interstate natural gas pipeline
subsidiaries.

On December 31, 2002, CERC Corp. had received proceeds from the sale of
receivables of approximately $107 million under its $150 million receivables
facility and its $350 million bank facility was fully drawn or utilized in the
form of letters of credit. Advances under the $150 million receivables facility
are not recorded as a financing because the facility provides for the sale of
receivables to third parties as discussed in Note 3(i) to the consolidated
financial statements.

In February 2003, CenterPoint Houston obtained a $75 million revolving
credit facility that terminates on April 30, 2003. A condition precedent to
utilizing the facility is that security in the form of general mortgage bonds
must be delivered to the lender. Rates for borrowings under this facility,
including the facility fee, will be LIBOR plus 250 basis points.

On December 31, 2002, we had $265 million of temporary investments.

Refunds to CenterPoint Houston Customers. An order issued by the Texas
Utility Commission on October 3, 2001 established the transmission and
distribution rates that became effective in January 2002. The Texas Utility
Commission determined that CenterPoint Houston had overmitigated its stranded
costs by redirecting transmission and distribution depreciation and by
accelerating depreciation of generation assets (an amount equal to earnings
above a stated overall rate of return on rate base that was used to recover our
investment in generation assets) as provided under the 1998 transition plan and
the Texas electric restructuring law. In this final order, CenterPoint Houston
is required to reverse the amount of redirected depreciation and accelerated
depreciation taken for regulatory purposes as allowed under the transition plan
and the Texas electric restructuring law. Per the October 3, 2001 order,
CenterPoint Houston recorded a regulatory liability to reflect the prospective
refund of the accelerated depreciation. CenterPoint Houston began refunding
excess mitigation credits with the January 2002 unbundled bills, to be refunded
over a seven-year period. The annual refund of excess earnings is approximately
$237 million. Under the Texas electric restructuring law, a final settlement of
these stranded costs will occur in 2004.

Cash Requirements in 2003. Our liquidity and capital requirements are
affected primarily by our results of operations, capital expenditures, debt
service requirements, and working capital needs.

Our principal cash requirements during 2003 include the following:

- $167 million of maturing long-term debt;

- approximately $684 million of capital expenditures;

64

- an estimated $237 million which we are obligated to return to customers
as a result of the Texas Utility Commission's findings of over-mitigation
of stranded costs;

- remarketing or refinancing of $500 million of CERC Corp. debt, plus the
possible payment of option termination costs (currently estimated to be
$61 million) as discussed in "Quantitative and Qualitative Disclosures
About Market Risk -- Interest Rate Risk" in Item 7A;

- payments expected to aggregate $350 million in connection with the
termination of bank facilities unless replacement facilities or
extensions are arranged; and

- dividend payments on CenterPoint Energy common stock.

We expect to meet our capital requirements through cash flows from
operations, short-term borrowings and proceeds from debt and/or equity
offerings. We believe that our current liquidity, along with anticipated cash
flows from operations and proceeds from short-term borrowings, including the
renewal, extension or replacement of existing bank facilities, and anticipated
sales of securities in the capital markets will be sufficient to meet our cash
needs. However, disruptions in our ability to access the capital markets on a
timely basis could adversely affect our liquidity. Limits on our ability to
issue secured debt, as described in this report, may adversely affect our
ability to issue debt securities. In addition, the recent cost of our secured
debt issuances has been very high. A similar cost with regard to additional
issuances could significantly impact our debt service. Please read "Risk
Factors -- Risk Factors Associated with Financial Condition and Other
Risks -- If we are unable to arrange future financings on acceptable terms, our
ability to fund future capital expenditures and refinance existing indebtedness
could be limited" in Item 1 of this report.

At December 31, 2002, CenterPoint Energy had a shelf registration statement
for 15 million shares of common stock and CERC Corp. had a shelf registration
statement covering $50 million of debt securities. The amount of any debt
security or any security having equity characteristics that we can issue,
whether registered or unregistered, or whether debt is secured or unsecured, is
expected to be affected by the market's perception of our creditworthiness,
general market conditions and factors affecting our industry. Proceeds from the
sales of securities are expected to be used primarily to refinance debt.

Principal Factors Affecting Cash Requirements in 2004 and 2005. We
anticipate selling our 81% ownership interest in Texas Genco in 2004. Should
Reliant Resources decline to exercise its option to purchase our interest in
Texas Genco, we will explore other alternatives to monetize Texas Genco's
assets, including possible sale of our ownership interest in Texas Genco or of
its individual generating assets, which may significantly affect the timing of
any cash proceeds. Proceeds from that sale, plus proceeds from the
securitization in 2004 or 2005 of stranded costs related to generating assets of
Texas Genco and generation related regulatory assets, are expected to aggregate
in excess of $5 billion.

We expect to issue securitization bonds in 2004 or 2005 to monetize and
recover the balance of stranded costs relating to electric generation assets and
other qualified costs as determined in the 2004 true-up proceeding. The issuance
will be done pursuant to a financing order to be issued by the Texas Utility
Commission. As with the debt of our existing transition bond company, payments
on these new securitization bonds would also be made from funds obtained through
non-bypassable charges assessed to retail electric customers required to take
delivery service from CenterPoint Houston. The holders of the securitization
bonds would not have recourse to any of our assets or revenues, and our
creditors would not have recourse to any assets or revenues of the entity
issuing the securitization bonds. All or a portion of the proceeds from the
issuance of securitization bonds remaining after repayment of CenterPoint
Houston's $1.3 billion collateralized term loan are expected to be utilized to
retire other existing debt.

Impact on Liquidity of a Downgrade in Credit Ratings. As of March 4, 2003,
Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a
division of The McGraw Hill Companies

65

(S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to
senior debt of CenterPoint Energy and certain subsidiaries:

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

(1) A "negative" outlook from Moody's reflects concerns over the next 12 to 18
months which will either lead to a review for a potential downgrade or a
return to a stable outlook. A "stable outlook" from Moody's indicates that
Moody's does not expect to put the rating on review for an upgrade or
downgrade within 18 months from when the outlook was assigned or last
affirmed.

(2) A "stable" outlook from S&P indicates that the rating is not likely to
change over the intermediate to longer term.

(3) A "negative" outlook from Fitch encompasses a one- to two-year horizon as to
the likely rating direction.

We cannot assure you that these ratings will remain in effect for any given
period of time or that one or more of these ratings will not be lowered or
withdrawn entirely by a rating agency. We note that these credit ratings are not
recommendations to buy, sell or hold our securities and may be revised or
withdrawn at any time by the rating agency. Each rating should be evaluated
independently of any other rating. Any future reduction or withdrawal of one or
more of our credit ratings could have a material adverse impact on our ability
to obtain short- and long-term financing, the cost of such financings and the
execution of our commercial strategies.

A decline in credit ratings would increase facility fees and borrowing
costs under our existing bank credit facilities. A decline in credit ratings
would also increase the interest rate on long-term debt to be issued in the
capital markets and would negatively impact our ability to complete capital
market transactions.

Our bank facilities contain "material adverse change" clauses that could
impact our ability to make new borrowings under these facilities. The "material
adverse change" clauses in most of our bank facilities relate to an event,
development or circumstance that has or would reasonably be expected to have a
material adverse effect on (a) the business, financial condition or operations
of the borrower and its subsidiaries taken as a whole, or (b) the legality,
validity or enforceability of the loan documents.

The $150 million receivables facility of CERC Corp. requires the
maintenance of credit ratings of at least BB from S&P and Ba2 from Moody's.
Receivables would cease to be sold in the event a credit rating fell below the
threshold.

Each ZENS note is exchangeable at the holder's option at any time for an
amount of cash equal to 95% of the market value of the reference shares of AOL
TW Common attributable to each ZENS note. If our creditworthiness were to drop
such that ZENS note holders thought our liquidity was adversely affected or the
market for the ZENS notes were to become illiquid, some ZENS holders might
decide to exchange their ZENS for cash. Funds for the payment of cash upon
exchange could be obtained from the sale of the AOL TW Common that we own or
from other sources. We own shares of AOL TW Common equal to 100% of the
reference shares used to calculate our obligation to the holders of the ZENS
notes. ZENS exchanges result in a cash outflow because deferred tax liabilities
related to the ZENS and AOL TW Common become current tax obligations when ZENS
are exchanged and AOL TW Common is sold.

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CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary of CERC
Corp., provides comprehensive natural gas sales and services to industrial and
commercial customers who are primarily located within or near the territories
served by our pipelines and distribution subsidiaries. In order to hedge its
exposure to natural gas prices, CenterPoint Energy Gas Resources Corp. has
agreements with provisions standard for the industry that establish credit
thresholds and require a party to provide additional collateral on two business
days' notice when that party's rating or the rating of a credit support provider
for that party (CERC Corp. in this case) falls below those levels. As of March
4, 2003, the senior unsecured debt of CERC Corp. was rated BBB by S&P and Ba1 by
Moody's. Based on these ratings, we estimate that unsecured credit limits
extended to CenterPoint Energy Gas Resources Corp. by counterparties could
aggregate $25 million; however, utilized credit capacity is significantly lower.

Cross Defaults. Under our bank facility, a payment default by us or any of
our significant subsidiaries on any indebtedness exceeding $50 million will
cause a default.

Pension Plan. As discussed in Note 11 to the consolidated financial
statements, we maintain a non-contributory pension plan covering substantially
all employees. Employer contributions are based on actuarial computations that
establish the minimum contribution required under the Employee Retirement Income
Security Act of 1974 (ERISA) and the maximum deductible contribution for income
tax purposes. During 2001, we contributed from treasury stock $107 million of
CenterPoint Energy common stock to the plan. No contributions were made to the
plan during 2002.

Under the terms of our pension plan, we reserve the right to change, modify
or terminate the plan. Our funding policy is to review amounts annually and
contribute an amount at least equal to the minimum contribution required under
ERISA.

Plan assets used to satisfy pension obligations have been adversely
impacted by the recent decline in equity market values. However, based on
current estimates, we will not be required to make pension contributions until
2005.

In accordance with SFAS No. 87, "Employers' Accounting for Pensions," (SFAS
87) changes in pension obligations and assets may not be immediately recognized
as pension costs in the income statement, but generally are recognized in future
years over the remaining average service period of plan participants. As such,
significant portions of pension costs recorded in any period may not reflect the
actual level of benefit payments provided to plan participants.

In 2000, we recorded a pension benefit of $39 million. Pension costs were
$39 million and $35 million for 2001 and 2002, respectively. Included in the net
pension benefit cost in 2001 was $45 million of expense related to Reliant
Resources' participants. For 2002, a pension benefit of $4 million was recorded
related to Reliant Resources' participants. Pension benefit and expense for
Reliant Resources' participants are reflected in the Statement of Consolidated
Operations as discontinued operations.

The calculation of pension expense and related liabilities requires the use
of assumptions. Changes in these assumptions can result in different expense and
liability amounts, and future actual experience can differ from the assumptions.
Two of the most critical assumptions are the expected long-term rate of return
on plan assets and the assumed discount rate.

As of December 31, 2002, the expected long-term rate of return on plan
assets was changed from 9.5% to 9.0%. The change in the assumption was developed
by reviewing the plan's targeted asset allocation and asset class return
expectations. We believe that our long-term asset allocation on average will
approximate the targeted allocation. We regularly review our actual asset
allocation and periodically rebalance plan assets as appropriate.

As of December 31, 2002, the projected benefit obligation was calculated
assuming a discount rate of 6.75%, which is a .5% decline from the 7.25%
discount rate assumed in 2001. The discount rate was determined by reviewing
yields on high-quality bonds that receive one of the two highest ratings given
by a recognized rating agency and the expected duration of pension obligation
specific to the characteristics of our plan.

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Pension expense for 2003 is estimated to be $90 million based on an
expected return on plan assets of 9.0% and a discount rate of 6.75% as of
December 31, 2002. If the expected return assumption was lowered by .5% (from
9.0% to 8.5%), 2003 pension expense would increase by approximately $5 million.
Similarly, if the discount rate was lowered by .5% (from 6.75% to 6.25%), this
assumption change would increase our projected benefit obligation, pension
liabilities and 2003 pension expense by approximately $98 million, $88 million
and $8 million, respectively. In addition, the assumption change would result in
an additional charge to comprehensive income during 2002 of $57 million, net of
tax.

Primarily due to the decline in the market value of the pension plan's
assets and increased benefit obligations associated with a reduction in the
discount rate, the value of the plan's assets is less than our accumulated
benefit obligation. As a result, we recorded a non-cash minimum liability
adjustment, which resulted in a charge to other comprehensive income during the
fourth quarter of 2002 of $414 million, net of tax. Recording a minimum
liability adjustment did not affect our results of operations during 2002 nor
our ability to meet any financial covenants related to our debt facilities.

Future changes in plan asset returns, assumed discount rates and various
other factors related to the pension will impact our future pension expense and
liabilities. We cannot predict with certainty what these factors will be in the
future.

Other Factors that Could Affect Cash Requirements. In addition to the
above factors, our liquidity and capital resources could be affected by:

- the need to provide cash collateral in connection with certain contracts;

- acceleration of payment dates on certain gas supply contracts under
certain circumstances;

- increases in fees and interest expense in connection with debt
refinancings;

- various regulatory actions; and

- the ability of Reliant Resources and its subsidiaries to satisfy its
obligations as a principal customer of CenterPoint Houston and Texas
Genco and in respect of its indemnity obligations to us.

Money Pool. We have a "money pool" through which we and our participating
subsidiaries can borrow or invest on a short-term basis. Funding needs are
aggregated and external borrowing or investing is based on the net cash
position. The money pool's net funding requirements are expected to be met with
bank loans. The terms of the money pool are in accordance with requirements
applicable to registered public utility holding companies under the 1935 Act.

Capitalization. Factors affecting our capitalization include:

- covenants in our and our subsidiaries' bank facilities and other
borrowing agreements; and

- limitations imposed on us as a registered public utility holding company.

The bank facilities of CenterPoint Houston and CERC Corp. restrict debt as
a percentage of total capitalization. Our $3.85 billion credit agreement limits
dividend payments as described above, contains a debt to earnings before
interest, taxes, depreciation and amortization (EBITDA) covenant, an EBITDA to
interest covenant and restrictions on the use of proceeds from debt issuances
and asset sales.

In connection with our registration as a public utility holding company
under the 1935 Act, the SEC has placed the following limitations on our external
debt:

- the aggregate amount of CenterPoint Houston's external borrowings has
been limited to $3.55 billion;

- the aggregate amount of CERC Corp.'s external borrowings has been limited
to $2.7 billion; and

- the aggregate amount of Texas Genco's external borrowings has been
limited to $500 million.

Additionally, the SEC has placed limitations on our dividends and the
dividends of our subsidiaries that require common equity as a percentage of
total capitalization for CenterPoint Houston, CERC Corp. and Texas Genco to be
at least 30% after the payment of such dividends. The order issued by the SEC
that
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authorizes our financing program expires on June 30, 2003, and we must seek a
new financing order before that date. Any new order may contain restrictions or
authorizations different from those described above.

OFF BALANCE SHEET FINANCING

In connection with the November 2002 amendment and extension of CERC
Corp.'s $150 million receivables facility, CERC Corp. formed a bankruptcy remote
subsidiary for the sole purpose of buying and selling receivables created by
CERC. This transaction is accounted for as a sale of receivables under the
provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities", and, as a result, the related
receivables are excluded from our Consolidated Balance Sheets. For additional
information regarding this transaction, please read Note 3(i) to our
consolidated financial statements.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the
presentation of our financial condition and results of operations and requires
management to make difficult, subjective or complex accounting estimates. An
accounting estimate is an approximation made by management of a financial
statement element, item or account in the financial statements. Accounting
estimates in our historical consolidated financial statements measure the
effects of past business transactions or events, or the present status of an
asset or liability. The accounting estimates described below require us to make
assumptions about matters that are highly uncertain at the time the estimate is
made. Additionally, different estimates that we could have used or changes in an
accounting estimate that are reasonably likely to occur could have a material
impact on the presentation of our financial condition or results of operations.
The circumstances that make these judgments difficult, subjective and/or complex
have to do with the need to make estimates about the effect of matters that are
inherently uncertain. Estimates and assumptions about future events and their
effects cannot be predicted with certainty. We base our estimates on historical
experience and on various other assumptions that we believe to be reasonable
under the circumstances, the results of which form the basis for making
judgments. These estimates may change as new events occur, as more experience is
acquired, as additional information is obtained and as our operating environment
changes. We believe the following accounting policies involve the application of
critical accounting estimates. Accordingly, these accounting estimates have been
reviewed and discussed with the audit committee of the board of directors.

ACCOUNTING FOR RATE REGULATION

SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation"
(SFAS No. 71), provides that rate-regulated entities account for and report
assets and liabilities consistent with the recovery of those incurred costs in
rates if the rates established are designed to recover the costs of providing
the regulated service and if the competitive environment makes it probable that
such rates can be charged and collected. Application of SFAS No. 71 to the
electric generation portion of our business was discontinued as of June 30,
1999. Our Electric Transmission & Distribution business continues to apply SFAS
No. 71 which results in our accounting for the regulatory effects of recovery of
"stranded costs" and other "regulatory assets" resulting from the unbundling of
the transmission and distribution business from our electric generation
operations in our consolidated financial statements. Certain expenses and
revenues subject to utility regulation or rate determination normally reflected
in income are deferred on the balance sheet and are recognized in income as the
related amounts are included in service rates and recovered from or refunded to
customers. Regulatory assets reflected in our Consolidated Balance Sheets
aggregated $3.3 billion and $4.0 billion as of December 31, 2001 and 2002,
respectively. Significant accounting estimates embedded within the application
of SFAS No. 71 with respect to our Electric Transmission & Distribution business
segment relate to $2.0 billion of recoverable electric generation plant
mitigation assets (stranded costs) and $697 million of ECOM true-up. The
stranded costs are comprised of $1.1 billion of previously recorded accelerated
depreciation and $841 million of previously redirected depreciation. These
stranded costs are recoverable under the provisions of the Texas electric
restructuring law. The ultimate amount of stranded cost recovery is subject to a
final determination which will occur in 2004 and is contingent upon the market
value of Texas Genco. Any

69

significant changes in our accounting estimate of stranded costs as a result of
current market conditions or changes in the regulatory recovery mechanism
currently in place could result in a material write-down of all or a portion of
these regulatory assets. Regulatory assets related to ECOM true-up represent the
regulatory assets associated with costs incurred as a result of mandated
capacity auctions conducted beginning in 2002 by our Electric Generation
business being consummated at market-based prices that have been substantially
below the estimate of those prices made by the Texas Utility Commission in the
spring of 2001. Any significant changes in our estimate of our regulatory asset
associated with ECOM true-up could have a significant effect on our financial
condition and results of operations. Additionally, any significant changes in
our estimated stranded costs or ECOM true-up recovery could significantly affect
our liquidity subsequent to the final true-up proceedings conducted by the Texas
Utility Commission which are expected to conclude in late 2004.

IMPAIRMENT OF LONG-LIVED ASSETS

Long-lived assets recorded in our Consolidated Balance Sheets primarily
consist of property, plant and equipment (PP&E). Net PP&E comprises $11.4
billion or 58% of our total assets as of December 31, 2002. We make judgments
and estimates in conjunction with the carrying value of these assets, including
amounts to be capitalized, depreciation and amortization methods and useful
lives. We evaluate our PP&E for impairment whenever indicators of impairment
exist. Accounting standards require that if the sum of the undiscounted expected
future cash flows from a company's asset is less than the carrying value of the
asset, an asset impairment must be recognized in the financial statements. The
amount of impairment recognized is calculated by subtracting the fair value of
the asset from the carrying value of the asset.

As a result of the distribution of approximately 19% of Texas Genco's
common stock to our shareholders on January 6, 2003, we re-evaluated our
electric generation assets for impairment as of December 31, 2002. This analysis
required us to make long-term estimates of future cash receipts associated with
the operation or sale of these electric generation assets and related cash
outflows. These forecasts require assumptions about demand for electricity
within the ERCOT market, future ERCOT market conditions, commodity prices and
regulatory developments. As of December 31, 2002, no impairment had been
indicated because the estimated cash flows associated with the operations of
their assets exceeded their carrying value. However the effects of competition
within the ERCOT market, the results of our capacity auctions, and the timing
and extent of changes in commodity prices, particularly natural gas prices,
could have a significant effect on our future cash flows and therefore affect
any future determination of asset impairment.

IMPAIRMENT OF GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS

We evaluate our goodwill and other indefinite-lived intangible assets for
impairment at least annually and more frequently when indicators of impairment
exist. Accounting standards require that if the fair value of a reporting unit
is less than its carrying value, including goodwill, a charge for impairment of
goodwill must be recognized. To measure the amount of the impairment loss, we
would compare the implied fair value of the reporting unit's goodwill with its
carrying value.

We recorded goodwill associated with the acquisition of our Natural Gas
Distribution and Pipelines and Gathering operations in 1997. We reviewed our
goodwill for impairment as of January 1, 2002. We computed the fair value of the
Natural Gas Distribution and the Pipelines and Gathering operations as the sum
of the discounted estimated net future cash flows applicable to each of these
operations. We determined that the fair value for each of the Natural Gas
Distribution operations and the Pipelines and Gathering operations exceeded
their corresponding carrying value, including unallocated goodwill. We also
concluded that no interim impairment indicators existed subsequent to this
initial evaluation. As of December 31, 2002 we had recorded $1.7 billion of
goodwill. Future evaluations of the carrying value of goodwill could be
significantly impacted by our estimates of cash flows associated with our
Natural Gas Distribution and Pipelines and Gathering operations, regulatory
matters, and estimated operating costs.

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UNBILLED ENERGY REVENUES

Revenues related to the sale and/or delivery of electricity or natural gas
(energy) are generally recorded when energy is delivered to customers. However,
the determination of energy sales to individual customers is based on the
reading of their meters, which is performed on a systematic basis throughout the
month. At the end of each month, amounts of energy delivered to customers since
the date of the last meter reading are estimated and the corresponding unbilled
revenue is estimated. Unbilled electric delivery revenue is estimated each month
based on daily supply volumes, applicable rates and analyses reflecting
significant historical trends and experience. Unbilled natural gas sales are
estimated based on estimated purchased gas volumes, estimated lost and
unaccounted for gas and tariffed rates in effect. Accrued unbilled revenues
recorded in the Consolidated Balance Sheet as of December 31, 2001 were $33
million related to our Electric Operations business segment and $269 million
related to our Natural Gas Distribution business segment. Accrued unbilled
revenues recorded in the Consolidated Balance Sheet as of December 31, 2002 were
$70 million related to our Electric Transmission & Distribution business segment
and $284 million related to our Natural Gas Distribution business segment.

NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 141, "Business Combinations" (SFAS No. 141). SFAS No. 141 requires business
combinations initiated after June 30, 2001 to be accounted for using the
purchase method of accounting and broadens the criteria for recording intangible
assets separate from goodwill. Recorded goodwill and intangibles will be
evaluated against these new criteria and may result in certain intangibles being
transferred to goodwill, or alternatively, amounts initially recorded as
goodwill may be separately identified and recognized apart from goodwill. We
adopted the provisions of the statement that apply to goodwill and intangible
assets acquired prior to June 30, 2001 on January 1, 2002. The adoption of SFAS
No. 141 did not have any impact on our historical results of operations or
financial position.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
an asset retirement obligation to be recognized as a liability is incurred and
capitalized as part of the cost of the related tangible long-lived assets. Over
time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Retirement obligations associated with long-lived assets included within the
scope of SFAS No. 143 are those for which a legal obligation exists under
enacted laws, statutes and written or oral contracts, including obligations
arising under the doctrine of promissory estoppel. SFAS No. 143 is effective for
fiscal years beginning after June 15, 2002, with earlier application encouraged.
SFAS No. 143 requires entities to record a cumulative effect of change in
accounting principle in the income statement in the period of adoption. We
adopted SFAS No. 143 on January 1, 2003.

We have completed an assessment of the applicability and implications of
SFAS No. 143. As a result of the assessment, we have identified retirement
obligations for nuclear decommissioning at the South Texas Project and for
lignite mine operations at the Jewett mine supplying the Limestone electric
generation facility. Nuclear decommissioning and the lignite mine have recorded
liabilities under our previous method of accounting. Liabilities recorded for
estimated decommissioning obligations were $138 million and $140 million at
December 31, 2001 and 2002, respectively. Liabilities recorded for estimated
lignite mine reclamation costs were $28 million and $40 million at December 31,
2001 and 2002, respectively. We have also identified other asset retirement
obligations that cannot be calculated because the assets associated with the
retirement obligations have an indeterminate life.

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We used an expected cash flow approach to measure our asset retirement
obligations under SFAS No. 143. The following amounts represent our asset
retirement obligations on a pro-forma basis as if we had adopted SFAS No. 143 as
of the respective dates:

The net difference between the amounts determined under SFAS No. 143 and
our previous method of accounting for estimated nuclear decommissioning costs of
$16 million will be recorded as a liability. The net difference between the
amounts determined under SFAS No. 143 and our previous method of accounting for
estimated mine reclamation costs of $37 million will be recorded as a cumulative
effect of accounting change.

Our rate-regulated businesses have previously recognized removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2002, these previously recognized removal costs of $618 million do
not represent SFAS No. 143 asset retirement obligations, but rather embedded
regulatory liabilities. Our non-rate regulated businesses have also previously
recognized removal costs as a component of depreciation expense. Upon adoption
of SFAS No. 143, we will reverse $115 million of previously recognized removal
costs with respect to these non-rate regulated businesses as a cumulative effect
of accounting change.

In August 2001, the FASB issued SFAS No. 144. SFAS No. 144 provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. SFAS No. 144 supercedes SFAS No.
121, "Accounting for the Impairment of Long-Lived Assets and for Long-Lived
Assets to Be Disposed Of" and Accounting Principles Board (APB) Opinion No. 30,
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions", while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 was effective for fiscal years beginning
after December 15, 2001, with early adoption encouraged. SFAS No. 144 did not
materially change the methods we use to measure impairment losses on long-lived
assets, but may result in additional future dispositions being reported as
discontinued operations than was previously permitted. Adoption of SFAS No. 144
also resulted in the retroactive reclassification of our Latin America
operations as discussed in Note 2 to our consolidated financial statements. We
adopted SFAS No. 144 on January 1, 2002.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement
that gains and losses on debt extinguishment must be classified as extraordinary
items in the income statement. Instead, such gains and losses will be classified
as extraordinary items only if they are deemed to be unusual and infrequent.
SFAS No. 145 also requires that capital leases that are modified so that the
resulting lease agreement is classified as an operating lease be accounted for
as a sale-leaseback transaction. The changes related to debt extinguishment are
effective for fiscal years beginning after May 15, 2002, and the changes related
to lease accounting are effective for transactions occurring after May 15, 2002.
We have applied this guidance prospectively as it relates to lease accounting
and will apply the accounting provisions related to debt extinguishment in 2003.
Upon adoption of SFAS No. 145, any gain or loss on extinguishment of debt that
was classified as an extraordinary item in prior periods presented shall be
reclassified.

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In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies Emerging Issues Task Force (EITF) Issue No. 94-3, "Liability
Recognition for Certain Employee Termination Benefits and Other Costs to Exit an
Activity (including Certain Costs Incurred in a Restructuring)" (EITF No. 94-3).
The principal difference between SFAS No. 146 and EITF No. 94-3 relates to the
requirements for recognition of a liability for costs associated with an exit or
disposal activity. SFAS No. 146 requires that a liability be recognized for a
cost associated with an exit or disposal activity when it is incurred. A
liability is incurred when a transaction or event occurs that leaves an entity
little or no discretion to avoid the future transfer or use of assets to settle
the liability. Under EITF No. 94-3, a liability for an exit cost was recognized
at the date of an entity's commitment to an exit plan. In addition, SFAS No. 146
also requires that a liability for a cost associated with an exit or disposal
activity be recognized at its fair value when it is incurred. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31,
2002 with early application encouraged. We will apply the provisions of SFAS No.
146 to all exit, or disposal activities initiated after December 31, 2002.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In addition, FIN 45 requires disclosures about the guarantees that
an entity has issued. The provision for initial recognition and measurement of
the liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure provisions of FIN 45 are
effective for financial statements of interim or annual periods ending after
December 15, 2002. The adoption of FIN 45 is not expected to materially affect
our consolidated financial statements. We have adopted the additional disclosure
provisions of FIN 45 in our consolidated financial statements as of December 31,
2002.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation, Transition and Disclosure -- an Amendment of SFAS No. 123" (SFAS
No. 148). SFAS No. 148 provides alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. SFAS No. 148 also requires that disclosures of the pro
forma effect of using the fair value method of accounting for stock-based
employee compensation be displayed more prominently and in a tabular format.
Additionally, SFAS No. 148 requires disclosure of the pro forma effect in
interim financial statements. The transition and annual disclosure requirements
of SFAS No.148 are effective for fiscal years ending after December 15, 2002. We
currently account for our stock-based compensation awards to employees and
directors under the accounting prescribed by APB Opinion No. 25 and provide the
disclosures required by SFAS No. 123. We will continue to account for our
stock-based compensation awards to employees and directors under the accounting
prescribed by APB Opinion No. 25 and have adopted the additional disclosure
provisions of SFAS No. 148 in our consolidated financial statements as of
December 31, 2002.

In January 2003, the FASB issued FIN No. 46, "Consolidation of Variable
Interest Entities, an Interpretation of Accounting Research Bulletin No. 51"
(FIN 46). FIN 46 requires certain variable interest entities to be consolidated
by the primary beneficiary of the entity if the equity investors in the entity
do not have the characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. We do not expect the adoption of
FIN 46 to have a material impact on our results of operations and financial
condition.

See Note 5 to our consolidated financial statements for a discussion of our
adoption of SFAS No. 133 on January 1, 2001 and adoption of subsequent cleared
guidance. See Note 3(d) to our consolidated financial statements for a
discussion of our adoption of SFAS No. 142, "Goodwill and Other Intangible
Assets."

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES

We are exposed to various market risks. These risks arise from transactions
entered into in the normal course of business and are inherent in our
consolidated financial statements. Most of the revenues and income from our
business activities are impacted by market risks. Categories of market risk
include exposure to commodity prices through non-trading activities, interest
rates and equity prices. A description of each market risk is set forth below:

- Commodity price risk results from exposures to changes in spot prices,
forward prices and price volatilities of commodities, such as natural gas
and other energy commodities risk.

- Interest rate risk primarily results from exposures to changes in the
level of borrowings and changes in interest rates.

- Equity price risk results from exposures to changes in prices of
individual equity securities.

Management has established comprehensive risk management policies to
monitor and manage these market risks. We seek to manage these risk exposures
through the implementation of our risk management policies and framework. We
seek to manage our exposures through the use of derivative financial instruments
and derivative commodity instrument contracts. During the normal course of
business, we review our hedging strategies and determine the hedging approach we
deem appropriate based upon the circumstances of each situation.

Derivative instruments such as futures, forward contracts, swaps and
options derive their value from underlying assets, indices, reference rates or a
combination of these factors. These derivative instruments include negotiated
contracts, which are referred to as over-the-counter derivatives, and
instruments that are listed and traded on an exchange.

Derivative transactions are entered into in our non-trading operations to
manage and hedge certain exposures, such as exposure to changes in gas prices.
We believe that the associated market risk of these instruments can best be
understood relative to the underlying assets or risk being hedged.

INTEREST RATE RISK

We have outstanding long-term debt, bank loans, mandatory redeemable
preferred securities of subsidiary trusts holding solely our junior subordinated
debentures (trust preferred securities), securities held in our nuclear
decommissioning trusts, some lease obligations and our obligations under the
ZENS that subject us to the risk of loss associated with movements in market
interest rates. We utilize interest rate swaps in order to hedge portions of our
floating-rate debt and to hedge a portion of the interest rate applicable to
future offerings of long-term debt.

Our floating-rate obligations aggregated $3.1 billion and $5.5 billion at
December 31, 2001 and 2002, respectively. If the floating interest rates were to
increase by 10% from December 31, 2002 rates, our combined interest expense
would increase by a total of $3.3 million each month in which such increase
continued.

At December 31, 2001 and 2002, we had outstanding fixed-rate debt
(excluding indexed debt securities) and trust preferred securities aggregating
$6.1 billion and $5.4 billion, respectively, in principal amount and having a
fair value of $6.1 billion and $5.4 billion, respectively. These instruments are
fixed-rate and, therefore, do not expose us to the risk of loss in earnings due
to changes in market interest rates (please read Notes 9 and 10 to our
consolidated financial statements). However, the fair value of these instruments
would increase by approximately $260 million if interest rates were to decline
by 10% from their levels at December 31, 2002. In general, such an increase in
fair value would impact earnings and cash flows only if we were to reacquire all
or a portion of these instruments in the open market prior to their maturity.

As discussed in Note 13(f) to our consolidated financial statements, we
contributed $14.8 million in each of 2000 and 2001 to a trust established to
fund our share of the decommissioning costs for the South Texas
74

Project. In 2002, we contributed $2.9 million to this trust. The securities held
by the trust for decommissioning costs had an estimated fair value of $163
million as of December 31, 2002, of which approximately 49% were fixed-rate debt
securities that subject us to risk of loss of fair value with movements in
market interest rates. If interest rates were to increase by 10% from their
levels at December 31, 2002, the decrease in fair value of the fixed-rate debt
securities would be approximately $1.0 million. In addition, the risk of an
economic loss is mitigated. Any unrealized gains or losses are accounted for in
accordance with SFAS No. 71 as a regulatory asset/liability because we believe
that our future contributions, which are currently recovered through the
ratemaking process, will be adjusted for these gains and losses. For further
discussion regarding the recovery of decommissioning costs pursuant to the Texas
electric restructuring law, please read Note 4(a) to our consolidated financial
statements.

As discussed in Note 9(b) to our consolidated financial statements, CERC
Corp.'s $500 million aggregate principal amount of 6 3/8% Term Enhanced
Remarketable Securities (TERM Notes) include an embedded option to remarket the
securities. The option is expected to be exercised in the event that the ten-
year Treasury rate in 2003 is below 5.66%. At December 31, 2002, we could
terminate the option at a cost of $61 million. A decrease of 10% in the December
31, 2002 level of interest rates would increase the cost of terminating the
option by approximately $17 million.

As discussed in Note 7 to our consolidated financial statements, upon
adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was
bifurcated into a debt component and a derivative component. The debt component
of $104 million at December 31, 2002 is a fixed-rate obligation and, therefore,
does not expose us to the risk of loss in earnings due to changes in market
interest rates. However, the fair value of the debt component would increase by
approximately $15 million if interest rates were to decline by 10% from levels
at December 31, 2002. Changes in the fair value of the derivative component,
$225 million at December 31, 2002, are recorded in our Statements of
Consolidated Operations and, therefore, we are exposed to changes in the fair
value of the derivative component as a result of changes in the underlying
risk-free interest rate. If the risk-free interest rate were to increase by 10%
from December 31, 2002 levels, the fair value of the derivative component would
increase by approximately $4 million, which would be recorded as an unrealized
loss in our Statements of Consolidated Operations.

As of December 31, 2002, we had interest rate swaps having an aggregate
notional amount of $750 million to fix the interest rate applicable to floating
rate debt. At December 31, 2002, the swaps relating to floating rate debt could
be terminated at a cost of $16 million. The swaps relating to short-term debt do
not qualify as cash flow hedges under SFAS No. 133, and are marked to market in
our Consolidated Balance Sheets with changes reflected in interest expense in
the Statements of Consolidated Operations. A decrease of 10% in the December 31,
2002 level of interest rates would increase the cost of terminating the swaps
outstanding at December 31, 2002 by approximately $1 million.

During 2002, we settled our forward-starting interest rate swaps having an
aggregate notional amount of $1.5 billion at a cost of $156 million.

For information regarding the accounting for interest rate swaps, please
read Note 5 to our consolidated financial statements.

EQUITY MARKET VALUE RISK

We are exposed to equity market value risk through our ownership of 21.6
million shares of AOL TW Common, which are held by us to facilitate our ability
to meet our obligations under the ZENS. Please read Note 7 to our consolidated
financial statements for a discussion of the effect of adoption of SFAS No. 133
on our ZENS obligation and our historical accounting treatment of our ZENS
obligation. A decrease of 10% from the December 31, 2002 market value of AOL TW
Common would result in a net loss of approximately $3 million, which would be
recorded as a loss in our Statements of Consolidated Operations.

As discussed above under "-- Interest Rate Risk," we contribute to a trust
established to fund our share of the decommissioning costs for the South Texas
Project, which held debt and equity securities as of December 31, 2002. The
equity securities expose us to losses in fair value. If the market prices of the

75

individual equity securities were to decrease by 10% from their levels at
December 31, 2002, the resulting loss in fair value of these securities would be
approximately $8 million. Currently, the risk of an economic loss is mitigated
as discussed above under "-- Interest Rate Risk."

COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES

To reduce our commodity price risk from market fluctuations in the revenues
derived from the sale of natural gas and related transportation, we enter into
forward contracts, swaps and options (Non-Trading Energy Derivatives) in order
to hedge some expected purchases of natural gas and sales of natural gas (a
portion of which are firm commitments at the inception of the hedge).
Non-Trading Energy Derivatives are also utilized to fix the price of future
operational gas requirements.

We use derivative instruments as economic hedges to offset the commodity
exposure inherent in our businesses. The stand-alone commodity risk created by
these instruments, without regard to the offsetting effect of the underlying
exposure these instruments are intended to hedge, is described below. We measure
the commodity risk of our Non-Trading Energy Derivatives using a sensitivity
analysis. The sensitivity analysis performed on our Non-Trading Energy
Derivatives measures the potential loss in earnings based on a hypothetical 10%
movement in energy prices. An increase of 10% in the market prices of energy
commodities from their December 31, 2001 levels would have decreased the fair
value of our Non-Trading Energy Derivatives by $14 million. A decrease of 10% in
the market prices of energy commodities from their December 31, 2002 levels
would have decreased the fair value of our Non-Trading Energy Derivatives by $12
million.

The above analysis of the Non-Trading Energy Derivatives utilized for
hedging purposes does not include the favorable impact that the same
hypothetical price movement would have on our physical purchases and sales of
natural gas to which the hedges relate. Furthermore, the Non-Trading Energy
Derivative portfolio is managed to complement the physical transaction
portfolio, reducing overall risks within limits. Therefore, the adverse impact
to the fair value of the portfolio of Non-Trading Energy Derivatives held for
hedging purposes associated with the hypothetical changes in commodity prices
referenced above would be offset by a favorable impact on the underlying hedged
physical transactions, assuming:

- the Non-Trading Energy Derivatives are not closed out in advance of their
expected term;

- the Non-Trading Energy Derivatives continue to function effectively as
hedges of the underlying risk; and

- as applicable, anticipated underlying transactions settle as expected.

If any of the above-mentioned assumptions ceases to be true, a loss on the
derivative instruments may occur, or the options might be worthless as
determined by the prevailing market value on their termination or maturity date,
whichever comes first. Non-Trading Energy Derivatives designated and effective
as hedges, may still have some percentage which is not effective. The change in
value of the Non-Trading Energy Derivatives that represents the ineffective
component of the hedges is recorded in our results of operations. During 2002,
we recognized a $0.9 million loss as a result of the discontinuance of a cash
flow hedge because it was no longer probable that the forecasted transaction
would occur.

We have established a Risk Oversight Committee, comprised of corporate and
business segment officers, that oversees all commodity price and credit risk
activities, including trading, marketing, risk management services and hedging
activities. The committee's duties are to establish commodity risk policies,
allocate risk capital, approve trading of new products and commodities, monitor
risk positions and ensure compliance with the risk management policies and
procedures and trading limits established by our board of directors.

Our policies prohibit the use of leveraged financial instruments. A
leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.

76

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA OF THE COMPANY

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED OPERATIONS

See Notes to the Company's Consolidated Financial Statements
77

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

See Notes to the Company's Consolidated Financial Statements
78

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

See Notes to the Company's Consolidated Financial Statements
79

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED CASH FLOWS

See Notes to the Company's Consolidated Financial Statements
80

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

STATEMENTS OF CONSOLIDATED SHAREHOLDERS' EQUITY

See Notes to the Company's Consolidated Financial Statements
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

RESTRUCTURING

CenterPoint Energy, Inc. (CenterPoint Energy or the Company) is a public
utility holding company, created on August 31, 2002 as part of a corporate
restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented
certain requirements of the Texas electric restructuring law described below. In
December 2000, Reliant Energy transferred a significant portion of its
unregulated businesses to Reliant Resources, Inc. (Reliant Resources), which, at
the time, was a wholly owned subsidiary of Reliant Energy. Reliant Resources
conducted an initial public offering of approximately 20% of its common stock in
May 2001 (the Reliant Resources Offering). In December 2001, Reliant Energy's
shareholders approved an agreement and plan of merger pursuant to which the
following steps occurred on August 31, 2002 (the Restructuring):

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

- Reliant Energy and its subsidiaries became subsidiaries of CenterPoint
Energy; and

- Each share of Reliant Energy common stock was converted into one share of
CenterPoint Energy common stock.

On September 5, 2002, CenterPoint Energy announced that its board of
directors had declared a distribution of all of the shares of Reliant Resources
common stock owned by CenterPoint Energy to its common shareholders on a pro
rata basis (the Reliant Resources Distribution). The Reliant Resources
Distribution was made on September 30, 2002 to shareholders of record of
CenterPoint Energy common stock as of the close of business on September 20,
2002.

CenterPoint Energy is the successor to Reliant Energy for financial
reporting purposes under the Securities Exchange Act of 1934. The Company's
indirect wholly owned operating subsidiaries own and operate electric
transmission and distribution facilities, natural gas distribution facilities,
natural gas pipelines and electric generating plants. The Company is subject to
regulation as a "registered holding company" under the Public Utility Holding
Company Act of 1935 (1935 Act). As of December 31, 2002, the Company's indirect
wholly owned subsidiaries include:

- CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which
engages in Reliant Energy's former electric transmission and distribution
business in a 5,000-square mile area of the Texas Gulf Coast that
includes Houston;

- CenterPoint Energy Resources Corp. (CERC Corp., and together with its
subsidiaries, CERC), formerly Reliant Energy Resources Corp. (RERC Corp.,
and, together with its subsidiaries, RERC), which owns gas distribution
systems that together form one of the United States' largest natural gas
distribution operations in terms of number of customers served. Through
wholly owned subsidiaries, CERC owns two interstate natural gas pipelines
and gas gathering systems and provides various ancillary services; and

- Texas Genco Holdings, Inc. (Texas Genco), which owns and operates the
Texas generating plants formerly belonging to the integrated electric
utility that was a part of Reliant Energy. The Company distributed
approximately 19% of the 80 million outstanding shares of common stock of
Texas Genco to the Company's shareholders on January 6, 2003. As a result
of the distribution of Texas Genco common stock, CenterPoint Energy
recorded an impairment charge of $396 million, which will be reflected as
a regulatory asset representing stranded costs in the Consolidated
Balance Sheet in the first quarter of 2003. This impairment charge
represents the excess of the carrying value of CenterPoint Energy's net
investment in Texas Genco over the market value of Texas Genco's common
stock. Additionally, in connection with the distribution, CenterPoint
Energy will record minority interest ownership in Texas Genco of $146
million in its Consolidated Balance Sheet in the first quarter of 2003.

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

BASIS OF PRESENTATION

The consolidated financial statements have been prepared to reflect the
effect of the Reliant Resources Distribution on the CenterPoint Energy financial
statements. The consolidated financial statements present the Reliant Resources
businesses (Wholesale Energy, European Energy, Retail Energy and related
corporate costs) as discontinued operations, in accordance with Statement of
Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or
Disposal of Long-Lived Assets" (SFAS No. 144). Accordingly, the consolidated
financial statements for each of the two years in the period ended December 31,
2001 and for the nine months ended September 30, 2002 reflect these operations
as discontinued operations.

The Company's reportable business segments include the following: Electric
Transmission & Distribution, Electric Generation, Natural Gas Distribution,
Pipelines and Gathering and Other Operations. Effective with the deregulation of
the Texas electric industry beginning January 1, 2002, the basis of business
segment reporting has changed for the Company's electric operations. The Texas
generation operations of CenterPoint Energy's former integrated electric
utility, Reliant Energy HL&P (Texas Genco), are now a separate reportable
business segment, Electric Generation, whereas they previously had been part of
the Electric Operations business segment. The remaining transmission and
distribution function (CenterPoint Houston) is now reported separately in the
Electric Transmission & Distribution business segment. Natural Gas Distribution
consists of intrastate natural gas sales to, and natural gas transportation and
distribution for, residential, commercial, industrial and institutional
customers and non-rate regulated retail gas marketing operations to commercial
and industrial customers. Pipelines and Gathering includes the interstate
natural gas pipeline operations and the natural gas gathering and pipeline
services businesses. Other Operations consists primarily of the Company's Latin
America operations, office buildings and other real estate used in our business
operations, district cooling in the central business district in downtown
Houston, energy management services and other corporate operations which support
all of the Company's business operations. Latin America operations primarily
consist of an electric utility and an electric cogeneration plant located in
Argentina.

In February 2003, the Company sold its interest in Argener, a cogeneration
facility in Argentina, for $23.1 million. The carrying value of this investment
was approximately $11 million as of December 31, 2002.

(2) RECLASSIFICATION OF FINANCIAL STATEMENTS

DISCONTINUED OPERATIONS

On September 30, 2002, CenterPoint Energy distributed to its shareholders
240 million shares of Reliant Resources common stock, which represented
CenterPoint Energy's approximately 83% ownership interest in Reliant Resources,
by means of a tax-free spin-off in the form of a dividend. Holders of
CenterPoint Energy common stock on the record date received 0.788603 shares of
Reliant Resources common stock for each share of CenterPoint Energy stock that
they owned on the record date. The total value of the Reliant Resources
Distribution, after the impairment charge discussed below, was $847 million.

As a result of the spin-off of Reliant Resources, CenterPoint Energy
recorded a non-cash loss on disposal of discontinued operations of $4.4 billion
in 2002. This loss represents the excess of the carrying value of CenterPoint
Energy's net investment in Reliant Resources over the market value of Reliant
Resources' common stock. CenterPoint Energy's financial statements reflect the
reclassifications necessary to present Reliant Resources as discontinued
operations for all periods shown. Through the date of the spin-off, Reliant
Resources' assets and liabilities are shown in CenterPoint Energy's Consolidated
Balance Sheets as current and non-current assets and liabilities of discontinued
operations.

Reliant Resources' revenues for the years ended December 31, 2000 and 2001
and the nine months ended September 30, 2002 included in discontinued operations
were $18.7 billion, $31.1 billion and $29.2 billion, respectively. Income from
discontinued operations for the years ended December 31, 2000 and 2001 and the
83

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

nine months ended September 30, 2002 is reported net of income tax expense of
$84.3 million, $271.6 million and $290.1 million, respectively. These amounts
have not been restated to reflect Reliant Resources' adoption of Emerging Issues
Task Force (EITF) Issue No. 02-3, "Recognition and Reporting Gains and Losses on
Energy Trading Contracts under Issues No. 98-10 and 00-17" during the third
quarter of 2002.

Reliant Resources' energy trading, marketing, power origination and risk
management services activities and contracted sales of electricity to large
commercial, industrial and institutional customers are accounted for under
mark-to-market accounting. Under the mark-to-market method of accounting,
financial instruments and contractual commitments are recorded at fair value in
revenues upon contract execution. The net changes in their fair values are
reported as revenues in the period of change. Trading and marketing revenues
related to the physical sale of natural gas, electric power and other energy
related commodities are recorded on a gross basis in the delivery period.

Reliant Resources' gains and losses related to financial instruments and
contractual commitments qualifying and designated as hedges related to the sale
of electric power and sales and purchases of natural gas are recognized in the
same period as the settlement of the underlying physical transaction. These
realized gains and losses are included in income from discontinued operations.

Summarized balance sheet information related to discontinued operations is
as follows as of December 31, 2001:

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

OTHER RECLASSIFICATIONS

Effective December 1, 2000, the Company's board of directors approved a
plan to dispose of its Latin America operations through sales of its assets.
Accordingly, in the Company's 2000 consolidated financial statements, the
Company reported the results of its Latin America operations as discontinued
operations in accordance with Accounting Principles Board (APB) Opinion No. 30
"Reporting the Results of Operations -- Reporting the Effects of Disposal of a
Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring
Events and Transactions" (APB Opinion No. 30) for each of the three years in the
period ended December 31, 2000.

In the fourth quarter of 2000, the Latin America business segment sold its
investments in El Salvador, Colombia and Brazil for an aggregate $790 million in
after-tax proceeds. The Company recorded a $242 million after-tax ($294 million
pre-tax) loss in connection with the sale of these investments.

In the fourth quarter of 2000 and in the first quarter of 2001, the Company
recorded additional after-tax impairments related to its Latin America
operations of $89 million and $7 million ($95 million and $6 million pre-tax),
respectively, based on the expected net realizable value of the businesses upon
their disposition.

On December 20, 2001, negotiations for the sale of the remaining Latin
America investments were terminated as a result of adverse economic developments
in Argentina.

During December 2001, the Company concluded there were indicators of
impairment related to the remaining assets in this business segment, and
accordingly, an impairment evaluation was conducted at the end of the fourth
quarter under the guidelines of SFAS No. 121, "Accounting for the Impairment of
Long-Lived Assets and for Long-Lived Assets to Be Disposed of" (SFAS No. 121).
This evaluation resulted in an after-tax impairment charge of $43 million ($74
million pre-tax), representing the excess of book value over estimated net
realizable value. The fair value of the remaining net assets was determined
using a net discounted cash flows approach. The charge was included as a
component of operating income with respect to consolidated subsidiaries and
other income with respect to equity investments in unconsolidated subsidiaries.
The impairment was primarily related to the economic deterioration in Argentina.

As of December 31, 2001 the Latin America business operations were no
longer reported as discontinued operations and were presented as a single line
item in continuing operations within the Statement of Consolidated Income and as
a single line item on the Consolidated Balance Sheet in accordance with EITF
Issue No. 90-6, "Accounting for Certain Events, Not Addressed in Issue No. 87-11
Relating to an Acquired Operating Unit to Be Sold". Effective January 1, 2002
the Company adopted SFAS No. 144 which does not permit this single line
presentation for assets held and used, such as the Company's Latin America
investments. Certain reclassifications have been made to the Company's
consolidated financial statements to show the retroactive effects of adoption of
SFAS No. 144.

(3) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(A) RECLASSIFICATIONS AND USE OF ESTIMATES

In addition to the items discussed in Note 2, some amounts from the
previous years have been reclassified to conform to the 2002 presentation of
financial statements. These reclassifications do not affect net income.

The preparation of financial statements in conformity with generally
accepted accounting principles requires management to make estimates and
assumptions that affect the reported amounts of assets and liabilities,
disclosure of contingent assets and liabilities at the date of the financial
statements, and the reported amounts of revenues and expenses during the
reporting period. Actual results could differ from those estimates.

85

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(B) PRINCIPLES OF CONSOLIDATION

The accounts of CenterPoint Energy and its wholly owned and majority owned
subsidiaries are included in the consolidated financial statements. All
significant intercompany transactions and balances are eliminated in
consolidation. The Company uses the equity method of accounting for investments
in entities in which the Company has an ownership interest between 20% and 50%
and exercises significant influence. Other investments, excluding marketable
securities, are generally carried at cost.

(C) REVENUES

The Company records revenue for electricity and natural gas sales and
services to retail customers under the accrual method and these revenues are
generally recognized upon delivery. The Pipelines and Gathering business segment
records revenues as transportation services are provided. Energy sales and
services not billed by month-end are accrued based upon estimated energy and
services delivered.

(D) LONG-LIVED ASSETS AND INTANGIBLES

The Company records property, plant and equipment at historical cost. The
Company expenses repair and maintenance costs as incurred. Property, plant and
equipment includes the following:

In July 2001, the Financial Accounting Standards Board (FASB) issued SFAS
No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142), which provides
that goodwill and certain intangibles with indefinite lives will not be
amortized into results of operations, but instead will be reviewed periodically
for impairment and written down and charged to results of operations only in the
periods in which the recorded value of goodwill and certain intangibles with
indefinite lives is more than its fair value. On January 1, 2002, the Company
adopted the provisions of the statement that apply to goodwill and intangible
assets acquired prior to June 30, 2001.

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

With the adoption of SFAS No. 142, the Company ceased amortization of
goodwill as of January 1, 2002. A reconciliation of previously reported net
income and earnings per share to the amounts adjusted for the exclusion of
goodwill amortization follows:

The components of the Company's other intangible assets consist of the
following:

The Company recognizes specifically identifiable intangibles, including
land use rights and permits, when specific rights and contracts are acquired.
The Company has no intangible assets with indefinite lives recorded as of
December 31, 2002. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range from 40 to 75 years for land rights and 4 to 25 years for other
intangibles.

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Amortization expense for other intangibles for 2000, 2001 and 2002 was $1.3
million, $1.2 million and $1.9 million, respectively. Estimated amortization
expense for the five succeeding fiscal years is as follows (in millions):

2003........................................................ $ 2
2004........................................................ 2
2005........................................................ 2
2006........................................................ 2
2007........................................................ 2
---
Total..................................................... $10
===

Goodwill by reportable business segment is as follows (in millions):

The Company completed its review during the second quarter of 2002 pursuant
to SFAS No. 142 for its reporting units in the Natural Gas Distribution,
Pipelines and Gathering and Other Operations business segments. No impairment
was indicated as a result of this assessment.

The Company periodically evaluates long-lived assets, including property,
plant and equipment, goodwill and specifically identifiable intangibles, when
events or changes in circumstances indicate that the carrying value of these
assets may not be recoverable. The determination of whether an impairment has
occurred is based on an estimate of undiscounted cash flows attributable to the
assets, as compared to the carrying value of the assets. An impairment analysis
of generating facilities requires estimates of possible future market prices,
load growth, competition and many other factors over the lives of the
facilities. A resulting impairment loss is highly dependent on these underlying
assumptions.

During the fourth quarter of 2001, the Reliant Resources Distribution was
deemed to be a probable event. As Reliant Resources has an option to purchase
the Company's 81% interest in its generation subsidiary, Texas Genco, in 2004
(see Note 4(b)), the Company was required to evaluate Texas Genco's assets for
potential impairment in accordance with SFAS No. 121, due to an expected
decrease in the number of years the Company expects to hold and operate these
assets. As of December 31, 2001, no impairment had been indicated. As a result
of the distribution of approximately 19% of Texas Genco's common stock to
CenterPoint Energy's shareholders on January 6, 2003, the Company re-evaluated
these assets for impairment as of December 31, 2002 in accordance with SFAS No.
144. As of December 31, 2002, no impairment had been indicated. The Company
anticipates that future events, such as a change in the estimated holding period
of Texas Genco's generation assets, will require the Company to re-evaluate
these assets for impairment between now and 2004. If an impairment is indicated,
it could be material and will not be fully recoverable through the 2004 true-up
proceeding calculations (see Note 4(a)).

The Texas electric restructuring law provides the Company recovery of the
regulatory book value of its Texas generating assets for the amount the net
regulatory book value exceeds the estimated market value. If the Company's 81%
interest in Texas Genco is sold to Reliant Resources or to a third party in the
future, a loss on sale of these assets, or an impairment of the recorded
recoverable electric generation plant mitigation regulatory asset (see Note
3(e)), will occur to the extent the recorded book value of the Texas generating

88

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

assets exceeds the regulatory book value. As of December 31, 2002, the recorded
book value was $649 million in excess of the regulatory book value. This amount
declines each year as the recorded book value is depreciated and increases by
the amount of capital expenditures. For further discussion of the difference
between the regulatory book value and the recorded book value, see Note 4.

(E) REGULATORY ASSETS AND LIABILITIES

The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of the Electric Transmission & Distribution business segment and the
utility operations of the Natural Gas Distribution business segment and to some
of the accounts of the Pipelines and Gathering business segment. For information
regarding Texas Genco's discontinuance of the application of SFAS No. 71 in 1999
and the effect on its regulatory assets and the Texas electric restructuring
law, see Note 4(a).

The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2001 and 2002:

If events were to occur that would make the recovery of these assets and
liabilities no longer probable, the Company would be required to write off or
write down these regulatory assets and liabilities. In addition, the Company
would be required to determine any impairment of the carrying costs of plant and
inventory assets.

Through December 31, 2001, the Public Utility Commission of Texas (Texas
Utility Commission) provided for the recovery of most of the Company's fuel and
purchased power costs from customers through a fixed fuel factor included in
electric rates. Included in the above table in recoverable electric generation
related regulatory assets, net are $126 million and $66 million of net
regulatory assets related to the recovery of fuel costs as of December 31, 2001
and 2002, respectively. For additional information regarding CenterPoint
Houston's fuel filings, see Note 4(c).

Texas Genco sells, through auctions, entitlements to substantially all of
its installed electric generation capacity, excluding reserves for planned and
forced outages. In September, October and December 2001, and March, July,
October and November 2002, Texas Genco conducted auctions as required by the
Texas Utility Commission and by the master separation agreement with Reliant
Resources.

The capacity auctions were consummated at market-based prices that are
substantially below the estimate of those prices made by the Texas Utility
Commission in the spring of 2001. The Texas electric restructuring law provides
for the recovery in a "true-up" proceeding in 2004 of any difference between
market power prices and the earlier estimates of those prices by the Texas
Utility Commission, using the prices received in the auctions required by the
Texas Utility Commission as the measure of market prices (ECOM

89

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

true-up). In 2002, CenterPoint Energy recorded approximately $697 million in
non-cash revenue related to the cost recovery of the difference between the
market power prices and the Texas Utility Commission's earlier estimates. For
additional information regarding the capacity auctions and the related true-up
proceeding, see Note 4(a).

In 2001, the Company monetized $738 million of regulatory assets in a
securitization financing authorized by the Texas Utility Commission pursuant to
the Texas electric restructuring law. The securitized regulatory assets are
being amortized ratably as transition charges are collected over the life of the
outstanding transition bonds. For additional information regarding the
securitization financing, see Note 4(a).

For additional information regarding recoverable impaired plant costs and
recoverable electric generation related assets and the related amortization
during 2000 and 2001, see Notes 3(g) and 4(a).

(F) DEPRECIATION AND AMORTIZATION EXPENSE

Depreciation is computed using the straight-line method based on economic
lives or a regulatory mandated recovery period. Other amortization expense
includes amortization of regulatory assets and other intangibles. See Notes 3(f)
and 4(a) for additional discussion of these items.

The following table presents depreciation, goodwill amortization and other
amortization expense for 2000, 2001 and 2002.

(G) CAPITALIZATION OF INTEREST AND ALLOWANCE FOR FUNDS USED DURING CONSTRUCTION

Allowance for funds used during construction (AFUDC) represents the
approximate net composite interest cost of borrowed funds and a reasonable
return on the equity funds used for construction. Although AFUDC increases both
utility plant and earnings, it is realized in cash through depreciation
provisions included in rates for subsidiaries that apply SFAS No. 71. Interest
and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component
of projects under construction and will be amortized over the assets' estimated
useful lives. During 2000, 2001 and 2002, the Company capitalized interest and
AFUDC related to debt of $11 million, $9 million and $12 million, respectively.

(H) INCOME TAXES

The Company files a consolidated federal income tax return and follows a
policy of comprehensive interperiod income tax allocation. The Company uses the
liability method of accounting for deferred income taxes and measures deferred
income taxes for all significant income tax temporary differences. Investment
tax credits were deferred and are being amortized over the estimated lives of
the related property. Unremitted earnings from the Company's foreign operations
are deemed to be permanently reinvested in foreign operations. For additional
information regarding income taxes, see Note 12.

(I) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable are net of an allowance for doubtful accounts of $46
million and $24 million at December 31, 2001 and 2002, respectively. The
provision for doubtful accounts in the Company's Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

of Consolidated Operations for 2000, 2001 and 2002 was $38 million, $59 million
and $26 million, respectively.

During 2000 and 2001, substantially all of the customer accounts receivable
of the Company's integrated electric utility were sold. Receivables aggregating
$4.9 billion and $5.8 billion were sold in 2000 and 2001, respectively. In
December 2001, the Company terminated the agreement under which it sold electric
customer accounts receivable and recorded an early termination charge of $20
million in the Statements of Consolidated Operations. Proceeds for the
repurchase of receivables, which occurred in January 2002, were obtained from a
combination of bank loans and the sale of commercial paper. Net proceeds from
the sale of accounts receivable were $523 million at December 31, 2001. Such
proceeds were not reflected as debt in the Consolidated Balance Sheets.

In the first quarter of 2002, CERC reduced its trade receivables facility
from $350 million to $150 million. During 2001 and 2002, CERC sold its customer
accounts receivable and utilized $346 million of its $350 million receivables
facility at December 31, 2001 and $107 million of its $150 million receivables
facility at December 31, 2002. The amount of receivables sold will fluctuate
based on the amount of receivables created by CERC.

In connection with CERC's November 2002 amendment and extension of its
receivables facility, CERC Corp. formed a bankruptcy remote subsidiary for the
sole purpose of buying and selling receivables created by CERC. This transaction
is accounted for as a sale of receivables under the provisions of SFAS No. 140,
"Accounting for Transfers and Servicing of Financial Assets and Extinguishments
of Liabilities", and, as a result, the related receivables are excluded from the
Consolidated Balance Sheet.

(J) INVENTORY

Inventory consists principally of materials and supplies, coal and lignite
and natural gas. Inventories used in the production of electricity and in the
retail natural gas distribution operations are valued at the lower of average
cost or market except for coal and lignite, which are valued under the last-in,
first-out method.

(K) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES

In accordance with SFAS No. 115, "Accounting for Certain Investments in
Debt and Equity Securities" (SFAS No. 115), the Company reports
"available-for-sale" securities at estimated fair value within other long-term
assets in the Company's Consolidated Balance Sheets and any unrealized gain or
loss, net of tax, as a separate component of shareholders' equity and
accumulated other comprehensive income. In accordance with SFAS No. 115, the
Company reports "trading" securities at estimated fair value in the Company's
Consolidated Balance Sheets, and any unrealized holding gains and losses are
recorded as other income (expense) in the Company's Statements of Consolidated
Operations.

As of December 31, 2001 and 2002, the Company held debt and equity
securities in its nuclear decommissioning trust, which is reported at its fair
value of $169 million and $163 million, respectively, in the Company's
Consolidated Balance Sheets in other long-term assets. Any unrealized losses or
gains are

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accounted for as a long-term asset/liability as the Company will not benefit
from any gains, and losses will be recovered through the rate-making process.

As of December 31, 2001 and 2002, the Company held an investment in AOL
Time Warner Inc. (AOL TW) common stock (AOL TW Common), which was classified as
a "trading" security. For information regarding the Company's investment in AOL
TW Common, see Note 7.

(L) ENVIRONMENTAL COSTS

The Company expenses or capitalizes environmental expenditures, as
appropriate, depending on their future economic benefit. The Company expenses
amounts that relate to an existing condition caused by past operations, and that
do not have future economic benefit. The Company records undiscounted
liabilities related to these future costs when environmental assessments and/or
remediation activities are probable and the costs can be reasonably estimated.
Subject to SFAS No. 71, a corresponding regulatory asset is recorded in
anticipation of recovery through the rate making process by subsidiaries that
apply SFAS No. 71.

(M) FOREIGN CURRENCY ADJUSTMENTS

Local currencies are the functional currency of the Company's foreign
operations. Foreign subsidiaries' assets and liabilities have been translated
into U.S. dollars using the exchange rate in effect at the balance sheet date.
Revenues, expenses, gains and losses have been translated using the weighted
average exchange rate for each month prevailing during the periods reported.
Cumulative adjustments resulting from translation have been recorded as a
component of accumulated other comprehensive loss in shareholders' equity.

(N) STATEMENTS OF CONSOLIDATED CASH FLOWS

For purposes of reporting cash flows, the Company considers cash
equivalents to be short-term, highly liquid investments with maturities of three
months or less from the date of purchase. In connection with the issuance of
transition bonds in October 2001, the Company was required to establish
restricted cash accounts to collateralize the bonds that were issued in this
financing transaction. These restricted cash accounts are classified as
long-term as they are not available for withdrawal until the maturity of the
bonds. Cash and Cash Equivalents does not include restricted cash. For
additional information regarding the securitization financing, see Note 4(a).

(O) NEW ACCOUNTING PRONOUNCEMENTS

In July 2001, the FASB issued SFAS No. 141, "Business Combinations" (SFAS
No. 141). SFAS No. 141 requires business combinations initiated after June 30,
2001 to be accounted for using the purchase method of accounting and broadens
the criteria for recording intangible assets separate from goodwill. Recorded
goodwill and intangibles will be evaluated against these new criteria and may
result in certain intangibles being transferred to goodwill, or alternatively,
amounts initially recorded as goodwill may be separately identified and
recognized apart from goodwill. The Company adopted the provisions of the
statement which apply to goodwill and intangible assets acquired prior to June
30, 2001 on January 1, 2002. The adoption of SFAS No. 141 did not have any
impact on the Company's historical results of operations or financial position.

In June 2001, the FASB issued SFAS No. 143, "Accounting for Asset
Retirement Obligations" (SFAS No. 143). SFAS No. 143 requires the fair value of
an asset retirement obligation to be recognized as a liability is incurred and
capitalized as part of the cost of the related tangible long-lived assets. Over
time, the liability is accreted to its present value each period, and the
capitalized cost is depreciated over the useful life of the related asset.
Retirement obligations associated with long-lived assets included within the
scope of SFAS No. 143 are those for which a legal obligation exists under
enacted laws, statutes and written or oral contracts,

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including obligations arising under the doctrine of promissory estoppel. SFAS
No. 143 is effective for fiscal years beginning after June 15, 2002, with
earlier application encouraged. SFAS No. 143 requires entities to record a
cumulative effect of change in accounting principle in the income statement in
the period of adoption. The Company adopted SFAS No. 143 on January 1, 2003.

The Company has completed an assessment of the applicability and
implications of SFAS No. 143. As a result of the assessment, the Company has
identified retirement obligations for nuclear decommissioning at the South Texas
Nuclear Project (South Texas Project) and for lignite mine operations at the
Jewett mine supplying the Limestone electric generation facility. Nuclear
decommissioning and the lignite mine have recorded liabilities under the
Company's previous method of accounting. Liabilities recorded for estimated
decommissioning obligations were $138 million and $140 million at December 31,
2001 and 2002, respectively. Liabilities recorded for estimated lignite mine
reclamation costs were $28 million and $40 million at December 31, 2001 and
2002, respectively. The Company has also identified other asset retirement
obligations that cannot be calculated because the assets associated with the
retirement obligations have an indeterminate life.

The Company used an expected cash flow approach to measure its asset
retirement obligations under SFAS No. 143. The following amounts represent the
Company's asset retirement obligations on a pro-forma basis as if it had adopted
SFAS No. 143 as of the respective dates:

The net difference between the amounts determined under SFAS No. 143 and
the Company's previous method of accounting for estimated nuclear
decommissioning costs of $16 million will be recorded as a liability. The net
difference between the amounts determined under SFAS No. 143 and the Company's
previous method of accounting for estimated mine reclamation costs of $37
million will be recorded as a cumulative effect of accounting change.

The Company's rate-regulated businesses have previously recognized removal
costs as a component of depreciation expense in accordance with regulatory
treatment. As of December 31, 2002, these previously recognized removal costs of
$618 million do not represent SFAS No. 143 asset retirement obligations, but
rather embedded regulatory liabilities. The Company's non-rate regulated
businesses have also previously recognized removal costs as component of
depreciation expense. Upon adoption of SFAS No. 143, the Company will reverse
$115 million of previously recognized removal costs with respect to these
non-rate regulated businesses as a cumulative effect of accounting change.

In August 2001, the FASB issued SFAS No. 144. SFAS No. 144 provides new
guidance on the recognition of impairment losses on long-lived assets to be held
and used or to be disposed of and also broadens the definition of what
constitutes a discontinued operation and how the results of a discontinued
operation are to be measured and presented. SFAS No. 144 supercedes SFAS No. 121
and APB Opinion No. 30, while retaining many of the requirements of these two
statements. Under SFAS No. 144, assets held for sale that are a component of an
entity will be included in discontinued operations if the operations and cash
flows will be or have been eliminated from the ongoing operations of the entity
and the entity will not have any significant continuing involvement in the
operations prospectively. SFAS No. 144 did not materially change the methods
used by the Company to measure impairment losses on long-lived assets but may
result in more future dispositions being reported as discontinued operations
than would previously have been permitted. The

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Company adopted SFAS No. 144 on January 1, 2002. Adoption of SFAS No. 144 also
resulted in the retroactive reclassification of the Company's Latin America
operations as discussed in Note 2.

In April 2002, the FASB issued SFAS No. 145, "Rescission of FASB Statements
No. 4, 44, and 64, Amendment of FASB Statement No. 13, and Technical
Corrections" (SFAS No. 145). SFAS No. 145 eliminates the current requirement
that gains and losses on debt extinguishment must be classified as extraordinary
items in the income statement. Instead, such gains and losses will be classified
as extraordinary items only if they are deemed to be unusual and infrequent.
SFAS No. 145 also requires that capital leases that are modified so that the
resulting lease agreement is classified as an operating lease be accounted for
as a sale-leaseback transaction. The changes related to debt extinguishment are
effective for fiscal years beginning after May 15, 2002, and the changes related
to lease accounting are effective for transactions occurring after May 15, 2002.
The Company has applied this guidance prospectively as it relates to lease
accounting and will apply the accounting provision related to debt
extinguishment in 2003. Upon adoption of SFAS No. 145, any gain or loss on
extinguishment of debt that was classified as an extraordinary item in prior
periods presented shall be reclassified.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs
Associated with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146
nullifies EITF Issue No. 94-3, "Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (including Certain
Costs Incurred in a Restructuring)" (EITF No. 94-3). The principal difference
between SFAS No. 146 and EITF No. 94-3 relates to the requirements for
recognition of a liability for costs associated with an exit or disposal
activity. SFAS No. 146 requires that a liability be recognized for a cost
associated with an exit or disposal activity when it is incurred. A liability is
incurred when a transaction or event occurs that leaves an entity little or no
discretion to avoid the future transfer or use of assets to settle the
liability. Under EITF No. 94-3, a liability for an exit cost was recognized at
the date of an entity's commitment to an exit plan. In addition, SFAS No. 146
also requires that a liability for a cost associated with an exit or disposal
activity be recognized at its fair value when it is incurred. SFAS No. 146 is
effective for exit or disposal activities that are initiated after December 31,
2002 with early application encouraged. The Company will apply the provisions of
SFAS No. 146 to all exit or disposal activities initiated after December 31,
2002.

In November 2002, the FASB issued FASB Interpretation No. (FIN) 45,
"Guarantor's Accounting and Disclosure Requirements for Guarantees, Including
Indirect Guarantees of Indebtedness of Others" (FIN 45). FIN 45 requires that a
liability be recorded in the guarantor's balance sheet upon issuance of certain
guarantees. In addition, FIN 45 requires disclosures about the guarantees that
an entity has issued. The provision for initial recognition and measurement of
the liability will be applied on a prospective basis to guarantees issued or
modified after December 31, 2002. The disclosure provisions of FIN 45 are
effective for financial statements of interim or annual periods ending after
December 15, 2002. The adoption of FIN 45 is not expected to materially affect
the Company's consolidated financial statements. The Company has adopted the
additional disclosure provisions of FIN 45 in its consolidated financial
statements as of December 31, 2002.

In December 2002, the FASB issued SFAS No. 148, "Accounting for Stock-Based
Compensation, Transition and Disclosure -- an Amendment of SFAS No. 123" (SFAS
No. 148). SFAS No. 148 provides alternative methods of transition for a
voluntary change to the fair value based method of accounting for stock-based
employee compensation. SFAS No. 148 also requires that disclosures of the pro
forma effect of using the fair value method of accounting for stock-based
employee compensation be displayed more prominently and in a tabular format.
Additionally, SFAS No. 148 requires disclosure of the pro forma effect in
interim financial statements. The transition and annual disclosure requirements
of SFAS No. 148 are effective for fiscal years ending after December 15, 2002.
The Company currently accounts for its stock-based compensation awards to
employees and directors under the accounting prescribed by APB Opinion No. 25
and provides the disclosures required by SFAS No. 123. The Company will continue
to account for its stock-based

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compensation awards to employees and directors under the accounting prescribed
by APB Opinion No. 25 and has adopted the additional disclosure provisions of
SFAS No. 148 in its consolidated financial statements as of December 31, 2002.
(See Note 11).

In January 2003, the FASB issued FIN 46 "Consolidation of Variable Interest
Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46).
FIN 46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. For variable interest entities created or acquired prior to
February 1, 2003, the provisions of FIN 46 must be applied for the first interim
or annual period beginning after June 15, 2003. The Company does not expect the
adoption of FIN 46 to have a material impact on its results of operations and
financial condition.

See Note 5 for a discussion of the Company's adoption of SFAS No. 133,
"Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133) on
January 1, 2001 and adoption of subsequent cleared guidance. See Note 3(d) for a
discussion of the Company's adoption of SFAS No. 142 on January 1, 2002.

(4) REGULATORY MATTERS

(A) TEXAS ELECTRIC RESTRUCTURING LAW AND DISCONTINUANCE OF SFAS NO. 71 FOR
ELECTRIC GENERATION OPERATIONS

In June 1999, the Texas legislature adopted the Texas electric
restructuring law, which substantially amended the regulatory structure
governing electric utilities in Texas in order to allow retail electric
competition. Retail pilot projects allowing competition for up to 5% of each
utility's load in all customer classes began in the third quarter of 2001, and
retail electric competition for all other customers began in January 2002. In
preparation for competition, the Company made significant changes in the
electric utility operations it conducts through its former electric utility
division, Reliant Energy HL&P (now CenterPoint Houston). In addition, the Texas
Utility Commission issued a number of new rules and determinations in
implementing the Texas electric restructuring law.

The Texas electric restructuring law defined the process for competition
and created a transition period during which most utility rates were frozen at
rates not in excess of their then-current levels. The Texas electric
restructuring law provided for utilities to recover their generation related
stranded costs and regulatory assets (as defined in the Texas electric
restructuring law).

Unbundling. As of January 1, 2002, electric utilities in Texas such as
CenterPoint Houston unbundled their businesses in order to separate power
generation, transmission and distribution, and retail activities into different
units. Pursuant to the Texas electric restructuring law, the Company submitted a
plan in January 2000 that was later amended and updated to accomplish the
required separation (the business separation plan). The transmission and
distribution business continues to be subject to cost-of-service rate regulation
and is responsible for the delivery of electricity to retail customers. The
Company transferred the Texas generation facilities that were formerly part of
Reliant Energy HL&P (Texas generation business) to Texas Genco in connection
with the Restructuring. As a result of these changes, the Company's Texas
generation operations are no longer conducted as part of an integrated utility
and comprise a new business segment, Electric Generation. Additionally, these
operations will not be part of the Company's business if they are acquired in
2004 by Reliant Resources pursuant to an option agreement described below or
they are otherwise sold.

Generation. Power generators began selling electric energy to wholesale
purchasers, including retail electric providers, at unregulated prices on
January 1, 2002. To facilitate a competitive market, each power generation
company affiliated with a transmission and distribution utility is required to
sell at auction 15% of the output of its installed generating capacity. The
first auction was held in September 2001 for power
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

delivered beginning January 1, 2002. This obligation continues until January 1,
2007 unless before that date the Texas Utility Commission determines that at
least 40% of the quantity of electric power consumed in 2000 by residential and
small commercial load in the electric utility's service area is being served by
retail electric providers other than an affiliated or formerly affiliated retail
electric provider. Texas Genco plans to auction all of its remaining capacity
(less approximately 10% withheld to provide for unforeseen outages) during the
time period prior to Reliant Resources' exercise of the Texas Genco Option
discussed below. Pursuant to the business separation plan, Reliant Resources is
entitled to purchase, at prices established in these auctions, 50% (but no less
than 50%) of the remaining capacity, energy and ancillary services auctioned by
Texas Genco. Sales to Reliant Resources represented approximately 66% of Texas
Genco's total revenues in 2002.

Transmission and Distribution Rates. All retail electric providers in
CenterPoint Houston's service area pay the same rates and other charges for
transmission and distribution services.

CenterPoint Houston's distribution rates charged to retail electric
providers are generally based on amounts of energy delivered. Transmission rates
charged to other distribution companies are based on amounts of energy
transmitted under "postage stamp" rates that do not vary with the distance the
energy is being transmitted. All distribution companies in ERCOT pay CenterPoint
Houston the same rates and other charges for transmission services. The
transmission and distribution rates for CenterPoint Houston have been in effect
since January 1, 2002, when electric competition began. This regulated delivery
charge includes the transmission and distribution rate (which includes costs for
nuclear decommissioning and municipal franchise fees), a system benefit fund fee
imposed by the Texas electric restructuring law, a transition charge associated
with securitization of regulatory assets and an excess mitigation credit imposed
by the Texas Utility Commission.

Stranded Costs. CenterPoint Houston will be entitled to recover its
stranded costs (the excess of net regulatory book value of generation assets (as
defined by the Texas electric restructuring law) over the market value of those
assets) and its regulatory assets related to generation. The Texas electric
restructuring law prescribes specific methods for determining the amount of
stranded costs and the details for their recovery. During the transition period
to deregulation (the Transition Period), which included 1998 and the first six
months of 1999, and extending through the base rate freeze period from July 1999
through 2001, the Texas electric restructuring law provided that earnings above
a stated overall annual rate of return on invested capital be used to recover
the Company's investment in generation assets (Accelerated Depreciation). In
addition, during the Transition Period, the redirection of depreciation expense
to generation assets that CenterPoint Houston would otherwise apply to
transmission, distribution and general plant assets was permitted for regulatory
purposes (Redirected Depreciation). Please read the discussion of the accounting
treatment for depreciation for financial reporting purposes below under
"-- Accounting." The Company cannot predict the amount, if any, of these costs
that may not be recovered.

In accordance with the Texas electric restructuring law, beginning on
January 1, 2002, and ending December 31, 2003, any difference between market
power prices received in the generation capacity auctions mandated by the Texas
electric restructuring law and the Texas Utility Commission's earlier estimates
of those prices will be included in the 2004 stranded cost true-up proceeding,
as further discussed below. This component of the true-up is intended to ensure
that neither the customers nor the Company is disadvantaged economically as a
result of the two-year transition period by providing this pricing structure.

On October 24, 2001, CenterPoint Energy Transition Bond Company, LLC (Bond
Company), a Delaware limited liability company and direct wholly owned
subsidiary of CenterPoint Houston, issued $749 million aggregate principal
amount of its Series 2001-1 Transition Bonds pursuant to a financing order of
the Texas Utility Commission. Classes of the bonds have final maturity dates of
September 15, 2007, September 15, 2009, September 15, 2011 and September 15,
2015, and bear interest at rates of 3.84%, 4.76%, 5.16% and 5.63%, respectively.
Scheduled payments on the bonds are from 2002 through 2013. Net proceeds to the
Bond Company from the issuance were $738 million. The Bond Company paid
CenterPoint Houston
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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

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$738 million for the transition property. Proceeds were used for general
corporate purposes, including the repayment of indebtedness.

The Transition Bonds are secured primarily by the "transition property,"
which includes the irrevocable right to recover, through non-bypassable
transition charges payable by certain retail electric customers, the qualified
costs of CenterPoint Houston authorized by the financing order. The holders of
the Bond Company's bonds have no recourse to any assets or revenues of
CenterPoint Houston, and the creditors of CenterPoint Houston have no recourse
to any assets or revenues (including, without limitation, the transition
charges) of the Bond Company. CenterPoint Houston has no payment obligations
with respect to the Transition Bonds except to remit collections of transition
charges as set forth in a servicing agreement between CenterPoint Houston and
the Bond Company and in an intercreditor agreement among CenterPoint Houston,
the Bond Company and other parties.

The non-bypassable transition charges are required by the financing order
to be trued-up annually, effective November 1, for the term of the transition
charge. CenterPoint Houston filed an annual true-up with the Texas Utility
Commission on August 2, 2002 for transition charges that became effective
November 1, 2002.

Costs associated with nuclear decommissioning will continue to be subject
to cost-of-service rate regulation and are included in a charge to transmission
and distribution customers. For further discussion of the effect of the business
separation plan on funding of the nuclear decommissioning trust fund, see Note
4(b).

True-Up Proceeding. The Texas electric restructuring law and current Texas
Utility Commission implementation guidance provide for a true-up proceeding to
be initiated in or after January 2004. The purpose of the true-up proceeding is
to quantify and reconcile the amount of stranded costs, the capacity auction
true-up, unreconciled fuel costs (see Note 3(e)), and other regulatory assets
associated with CenterPoint Houston's former electric generating operations that
were not previously securitized through the Transition Bonds. The 2004 true-up
proceeding will result in either additional charges being assessed on or credits
being issued to certain retail electric customers. The Company appealed the
Texas Utility Commission's true-up rule on the basis that there are no negative
stranded costs, that the Company should be allowed to collect interest on
stranded costs, and that the premium on the partial stock valuation applies to
only the equity of Texas Genco, not equity plus debt. The Texas court of appeals
issued a decision on February 6, 2003 upholding the rule in part and reversing
in part. The court ruled that there are no negative stranded costs and that the
premium on the partial stock valuation applies only to equity. The court upheld
the Texas Utility Commission's rule that interest on stranded costs begins upon
the date of the final true-up order. On February 21, 2003, the Company filed a
motion for rehearing on the issue that interest on amounts determined in the
true-up proceeding should accrue from an earlier date . The Company has not
accrued interest in its consolidated financial statements, but estimates that
interest could be material. If the court of appeals denies the Company's motion,
then the Company will have 45 days to appeal to the Texas Supreme Court. The
Company has not decided what action, if any, it will take if the motion for
rehearing is denied.

Accounting. Historically, the Company has applied the accounting policies
established in SFAS No. 71. Effective June 30, 1999, the Company applied SFAS
No. 101 to Texas Genco.

In 1999, the Company evaluated the effects that the Texas electric
restructuring law would have on the recovery of its generation related
regulatory assets and liabilities. The Company determined that a pre-tax
accounting loss of $282 million existed because it believes only the economic
value of its generation related regulatory assets (as defined by the Texas
electric restructuring law) will be recoverable. Therefore, the Company recorded
a $183 million after-tax extraordinary loss in the fourth quarter of 1999.
Pursuant to EITF Issue No. 97-4 "Deregulation of the Pricing of
Electricity -- Issues Related to the Application of FASB Statements No. 71 and
No. 101" (EITF No. 97-4), the remaining recoverable regulatory assets are now

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associated with the transmission and distribution portion of the Company's
electric utility business. For details regarding the Company's regulatory
assets, see Note 3(e).

At June 30, 1999, the Company performed an impairment test of its
previously regulated electric generation assets pursuant to SFAS No. 121 on a
plant specific basis. Under SFAS No. 121, an asset is considered impaired, and
should be written down to fair value, if the future undiscounted net cash flows
expected to be generated by the use of the asset are insufficient to recover the
carrying amount of the asset. For assets that are impaired pursuant to SFAS No.
121, the Company determined the fair value for each generating plant by
estimating the net present value of future cash flows over the estimated life of
each plant. The difference between fair value and net book value was recorded as
a reduction in the current book value. The Company determined that $797 million
of electric generation assets were impaired in 1999. Of this amount, $745
million related to the South Texas Project and $52 million related to two
gas-fired generation plants. The Texas electric restructuring law provides for
recovery of this impairment through regulated cash flows during the transition
period and through charges to transmission and distribution customers. As such,
a regulatory asset was recorded for an amount equal to the impairment loss and
was included on the Company's Consolidated Balance Sheets as a regulatory asset.
The Company recorded amortization expense related to the recoverable impaired
plant costs and other assets created from discontinuing SFAS No. 71 of $221
million during the six months ended December 31, 1999, $329 million in 2000 and
$247 million in 2001.

The impairment analysis requires estimates of possible future market
prices, load growth, competition and many other factors over the lives of the
plants. The resulting impairment loss is highly dependent on these underlying
assumptions. In addition, after January 10, 2004, CenterPoint Houston must
finalize and reconcile stranded costs (as defined by the Texas electric
restructuring law) in a filing with the Texas Utility Commission. Any positive
difference between the regulatory net book value and the fair market value of
the generation assets (as defined by the Texas electric restructuring law) will
be collected through future charges. Any overmitigation of stranded costs may be
refunded by a reduction in future charges. This final reconciliation allows
alternative methods of third party valuation of the fair market value of these
assets, including outright sale, stock valuations and asset exchanges.

In order to reduce potential exposure to stranded costs related to
generation assets, CenterPoint Houston recognized Redirected Depreciation of
$195 million and $99 million in 1998 and for the six months ended June 30, 1999,
respectively, for regulatory and financial reporting purposes. This redirection
was in accordance with the Company's Transition Plan. Subsequent to June 30,
1999, Redirected Depreciation expense could no longer be recorded by the
Company's electric generation business for financial reporting purposes as these
operations are no longer accounted for under SFAS No. 71. During the six months
ended December 31, 1999 and during 2000 and 2001, $99 million, $218 million and
$230 million in depreciation expense, respectively, was redirected from
transmission and distribution for regulatory and financial reporting purposes
and was established as an embedded regulatory asset included in transmission and
distribution related plant and equipment balances. As of December 31, 2001, the
cumulative amount of Redirected Depreciation for regulatory purposes was $841
million, prior to the effects of the October 3, 2001 order discussed below.

Additionally, as allowed by the Texas Utility Commission, in an effort to
further reduce potential exposure to stranded costs related to generation
assets, CenterPoint Houston recorded Accelerated Depreciation of $194 million
and $104 million in 1998 and for the six months ended June 30, 1999,
respectively, for regulatory and financial reporting purposes. Accelerated
Depreciation expense was recorded in accordance with the Company's Transition
Plan during this period. Subsequent to June 30, 1999, Accelerated Depreciation
expense could no longer be recorded by the Company's electric generation
business for financial reporting purposes, as these operations are no longer
accounted for under SFAS No. 71. During the six months ended December 31, 1999
and during 2000 and 2001, $179 million, $385 million and $264 million,
respectively, of Accelerated Depreciation was recorded for regulatory reporting
purposes, reducing the regulatory book value of the Company's electric
generation assets.

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The Texas Utility Commission issued a final order on October 3, 2001
(October 3, 2001 Order) that established the transmission and distribution
utility rates that became effective in January 2002. In this Order, the Texas
Utility Commission found that CenterPoint Houston had overmitigated its stranded
costs by redirecting transmission and distribution depreciation and by
accelerating depreciation of generation assets as provided under the Transition
Plan and Texas electric restructuring law. As a result of the October 3, 2001
Order, CenterPoint Houston was required to reverse the $841 million embedded
regulatory asset related to Redirected Depreciation, thereby reducing the net
book value of transmission and distribution assets. CenterPoint Houston was
required to record a regulatory liability of $1.1 billion related to Accelerated
Depreciation. The October 3, 2001 Order requires this amount to be refunded
through excess mitigation credits to certain retail electric customers during a
seven-year period which began in January 2002.

As of December 31, 2002, in contemplation of the 2004 true-up proceeding,
CenterPoint Houston has recorded a regulatory asset of $2.0 billion representing
the estimated future recovery of previously incurred stranded costs, which
includes $1.1 billion of previously recorded Accelerated Depreciation plus
Redirected Depreciation, both reversed in 2001. Offsetting this regulatory asset
is a $969 million regulatory liability to refund the excess mitigation to
ratepayers. This estimated recovery is based upon current projections of the
market value of the Company's Texas generation assets to be covered by the 2004
true-up proceeding calculations. The regulatory liability reflects a current
refund obligation arising from prior mitigation of stranded costs deemed
excessive by the Texas Utility Commission. CenterPoint Houston began refunding
excess mitigation credits with January 2002 bills. These credits are to be
refunded over a seven-year period. Because accounting principles generally
accepted in the United States of America require CenterPoint Houston to estimate
fair market values in advance of the final reconciliation, the financial impacts
of the Texas electric restructuring law with respect to the final determination
of stranded costs in the 2004 true-up proceeding are subject to material
changes. Factors affecting such changes may include estimation risk, uncertainty
of future energy and commodity prices and the economic lives of the plants. If
events were to occur that made the recovery of some of the remaining generation
related regulatory assets no longer probable, the Company would write off the
unrecoverable balance of such assets as a charge against earnings.

(B) AGREEMENTS RELATED TO TEXAS GENERATING ASSETS

Pursuant to the business separation plan, on January 6, 2003, the Company
distributed approximately 19% of Texas Genco's 80 million outstanding shares of
common stock to its shareholders in order to establish a public market value for
shares of that stock which will be used in 2004 to calculate how much
CenterPoint Houston will be able to recover as stranded costs. Reliant Resources
has an option to purchase the Company's remaining 81% interest in Texas Genco
(Texas Genco Option). The Texas Genco Option may be exercised between January
10, 2004 and January 24, 2004. The per share exercise price under the option
will be the average daily closing price on the applicable national exchange for
publicly held shares of common stock of Texas Genco for the 30 consecutive
trading days with the highest average closing price during the 120 trading days
immediately preceding January 10, 2004, plus a control premium, up to a maximum
of 10%, to the extent a control premium is included in the valuation
determination made by the Texas Utility Commission relating to the market value
of Texas Genco's common stock equity. The exercise price is also subject to
adjustment based on the difference between the cash dividends paid during the
period there is a public ownership interest in Texas Genco and Texas Genco's
earnings during that period. Reliant Resources has agreed that if it exercises
the Texas Genco Option and purchases the shares of Texas Genco common stock,
Reliant Resources will also purchase all notes and other receivables from Texas
Genco then held by CenterPoint Energy, at their principal amount plus accrued
interest. Similarly, if Texas Genco holds notes or receivables from the Company,
Reliant Resources will assume those obligations in exchange for a payment to
Reliant Resources by the Company of an amount equal to the principal plus
accrued interest. Exercise of the Texas Genco Option by Reliant Resources will
be subject to various regulatory approvals, including Hart-Scott-Rodino
antitrust clearance and United States Nuclear Regulatory Commission (NRC)
license transfer approval.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Texas Genco is the beneficiary of the decommissioning trust that has been
established to provide funding for decontamination and decommissioning of a
nuclear electric generation station in which Texas Genco owns a 30.8% interest
(see Note 6). CenterPoint Houston collects through rates or other authorized
charges to its electric utility customers amounts designated for funding the
decommissioning trust, and pays the amounts to Texas Genco. Texas Genco in turn
deposits these amounts into the decommissioning trust. Upon decommissioning of
the facility, in the event funds from the trust are inadequate, CenterPoint
Houston or its successor will be required to collect through rates or other
authorized charges to customers as contemplated by the Texas Utilities Code all
additional amounts required to fund Texas Genco's obligations relating to the
decommissioning of the facility. Following the completion of the
decommissioning, if surplus funds remain in the decommissioning trust, the
excess will be refunded to the ratepayers of CenterPoint Houston or its
successor.

(C) CENTERPOINT HOUSTON REGULATORY FILINGS

CenterPoint Houston and Texas Genco filed their joint application to
reconcile fuel revenues and expenses with the Texas Utility Commission on July
1, 2002. This final fuel reconciliation filing covers reconcilable fuel revenue,
fuel expense and interest of approximately $8.5 billion incurred from August 1,
1997 through January 30, 2002. Also included in this amount is an under-recovery
of $94 million, which was the balance at July 31, 1997 as approved in
CenterPoint Houston's last fuel reconciliation. On January 28, 2003, a
settlement agreement was reached under which it was agreed that certain items
totaling $24 million were written off during the fourth quarter of 2002 and
items totaling $203 million will be carried forward for resolution by the Texas
Utility Commission in late 2003 or early 2004.

(D) ARKLA RATE CASE

In November 2001, CenterPoint Energy Arkla (Arkla) filed a rate request in
Arkansas seeking rates to yield approximately $47 million in additional annual
gross revenue. In August 2002, a settlement was approved by the Arkansas Public
Service Commission (APSC) that is expected to result in an increase in base
rates of approximately $32 million annually. In addition, the APSC approved a
gas main replacement surcharge that is expected to provide $2 million of
additional gross revenue in 2003 and additional amounts in subsequent years. The
new rates included in the final settlement were effective with all bills
rendered on and after September 21, 2002.

(E) OKLAHOMA RATE CASE

In May 2002, Arkla filed a request in Oklahoma to increase its base rates
by $13.7 million annually. In December 2002, a settlement was approved by the
Oklahoma Corporation Commission that is expected to result in an increase in
base rates of approximately $7.3 million annually. The new rates included in the
final settlement were effective with all bills rendered on and after December
29, 2002.

(5) DERIVATIVE INSTRUMENTS

Effective January 1, 2001, the Company adopted SFAS No. 133, which
establishes accounting and reporting standards for derivative instruments,
including certain derivative instruments embedded in other contracts, and for
hedging activities. This statement requires that derivatives be recognized at
fair value in the balance sheet and that changes in fair value be recognized
either currently in earnings or deferred as a component of other comprehensive
income, depending on the intended use of the derivative instrument as hedging
(a) the exposure to changes in the fair value of an asset or liability (Fair
Value Hedge) or (b) the exposure to variability in expected future cash flows
(Cash Flow Hedge) or (c) the foreign currency exposure of a net investment in a
foreign operation. For a derivative not designated as a hedging instrument, the
gain or loss is recognized in earnings in the period it occurs.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax
increase in net income of $59 million and a cumulative after-tax increase in
accumulated other comprehensive income of $38 million. The adoption also
increased current assets, long-term assets, current liabilities and long-term
liabilities by approximately $88 million, $5 million, $53 million and $2
million, respectively, in the Company's Consolidated Balance Sheet.

The Company is exposed to various market risks. These risks arise from
transactions entered into in the normal course of business. The Company utilizes
derivative financial instruments such as physical forward contracts, swaps and
options (Energy Derivatives) to mitigate the impact of changes and cash flows of
its natural gas businesses on its operating results and cash flows.

(A) NON-TRADING ACTIVITIES.

Cash Flow Hedges. To reduce the risk from market fluctuations associated
with purchased gas costs, the Company enters into energy derivatives in order to
hedge certain expected purchases and sales of natural gas (non-trading energy
derivatives). The Company applies hedge accounting for its non-trading energy
derivatives utilized in non-trading activities only if there is a high
correlation between price movements in the derivative and the item designated as
being hedged. The Company analyzes its physical transaction portfolio to
determine its net exposure by delivery location and delivery period. Because the
Company's physical transactions with similar delivery locations and periods are
highly correlated and share similar risk exposures, the Company facilitates
hedging for customers by aggregating physical transactions and subsequently
entering into non-trading energy derivatives to mitigate exposures created by
the physical positions.

During 2002, no hedge ineffectiveness was recognized in earnings from
derivatives that are designated and qualify as Cash Flow Hedges. No component of
the derivative instruments' gain or loss was excluded from the assessment of
effectiveness. If it becomes probable that an anticipated transaction will not
occur, the Company realizes in net income the deferred gains and losses
recognized in accumulated other comprehensive loss. During the year ended
December 31, 2002, there was a $0.9 million deferred loss recognized in earnings
as a result of the discontinuance of cash flow hedges because it was no longer
probable that the forecasted transaction would occur. Once the anticipated
transaction occurs, the accumulated deferred gain or loss recognized in
accumulated other comprehensive loss is reclassified and included in the
Company's Statements of Consolidated Operations under the caption "Natural Gas
and Purchased Power." Cash flows resulting from these transactions in
non-trading energy derivatives are included in the Statements of Consolidated
Cash Flows in the same category as the item being hedged. As of December 31,
2002, the Company expects $1 million in accumulated other comprehensive loss to
be reclassified into net income during the next twelve months.

The maximum length of time the Company is hedging its exposure to the
variability in future cash flows for forecasted transactions on existing
financial instruments is primarily two years with a limited amount of exposure
up to five years. The Company's policy is not to exceed five years in hedging
its exposure.

Interest Rate Swaps. As of December 31, 2002, the Company had outstanding
interest rate swaps with an aggregate notional amount of $750 million to fix the
interest rate applicable to floating rate short-term debt. These swaps do not
qualify as cash flow hedges under SFAS No. 133, and are marked to market in the
Company's Consolidated Balance Sheets with changes reflected in interest expense
in the Statements of Consolidated Operations. During the year ended December 31,
2002, the Company settled its forward-starting interest rate swaps having an
aggregate notional amount of $1.5 billion at a cost of $156 million. The Company
has designated and accounted for the forward-interest rate swaps as a cash flow
hedge of the Company's exposure to variability in future interest payments on
fixed rate debt the Company anticipates issuing. Accordingly, the Company
recorded the $156 million cost in other comprehensive income, which will be
amortized into interest expense in the same period during which the forecasted
interest payments affect earnings. The Company assesses and measures the hedging
relationship on a quarterly basis by comparing the
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

critical terms of the forward starting interest rate swaps with the expected
terms of the forecasted debt issuance as well as evaluating the probability of
the underlying interest payments occurring. The Company reclassified
approximately $36 million in 2002 as a result of interest payments it believes
are no longer probable of occurring for certain periods.

(B) CREDIT RISKS.

In addition to the risk associated with price movements, credit risk is
also inherent in the Company's non-trading derivative activities. Credit risk
relates to the risk of loss resulting from non-performance of contractual
obligations by a counterparty. The following table shows the composition of the
non-trading derivative assets of the Company as of December 31, 2001 and 2002:

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

(1) "Investment Grade" is primarily determined using publicly available credit
ratings along with the consideration of credit support (such as parent
company guarantees) and collateral, which encompass cash and standby letters
of credit.

(2) For unrated counterparties, the Company performs financial statement
analysis, considering contractual rights and restrictions and collateral, to
create a synthetic credit rating.

(3) The $22 million non-trading derivative asset includes a $15 million asset
due to trades with Reliant Energy Services, Inc. (Reliant Energy Services)
an affiliate until the date of the Reliant Resources Distribution. As of
December 31, 2002, Reliant Energy Services did not have an Investment Grade
rating.

(C) GENERAL POLICY.

The Company has established a Risk Oversight Committee comprised of
corporate and business segment officers that oversees all commodity price and
credit risk activities, including the Company's trading, marketing, risk
management services and hedging activities. The committee's duties are to
establish the Company's commodity risk policies, allocate risk capital within
limits established by the Company's board of directors, approve trading of new
products and commodities, monitor risk positions and ensure compliance with the
Company's risk management policies and procedures and trading limits established
by the Company's board of directors.

The Company's policies prohibit the use of leveraged financial instruments.
A leveraged financial instrument, for this purpose, is a transaction involving a
derivative whose financial impact will be based on an amount other than the
notional amount or volume of the instrument.

(6) JOINTLY OWNED ELECTRIC UTILITY PLANT

Texas Genco owns a 30.8% interest in the South Texas Project, which
consists of two 1,250 MW nuclear generating units and bears a corresponding
30.8% share of capital and operating costs associated with the project. The
South Texas Project is owned as a tenancy in common among Texas Genco and three
other co-owners, with each owner retaining its undivided ownership interest in
the two generating units and the electrical output from those units. Texas Genco
is severally liable, but not jointly liable, for the expenses and

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

liabilities of the South Texas Project. Texas Genco and the three other
co-owners organized the STP Nuclear Operating company (STPNOC) to operate and
maintain the South Texas Project. STPNOC is managed by a board of directors
comprised of one director appointed by each of the four co-owners, along with
the chief executive officer of STPNOC. Texas Genco's share of direct expenses of
the South Texas Project is included in the corresponding operating expense
categories in the accompanying consolidated financial statements. As of December
31, 2001, the total utility plant in service and construction work in progress
for the total South Texas Project was $5.8 billion and $120 million,
respectively. As of December 31, 2002, the total utility plant in service and
construction work in progress for the total South Texas Project was $5.8 billion
and $158 million, respectively. As of December 31, 2001 and 2002, Texas Genco's
investment in the South Texas Project was $316 million and $323 million,
respectively, (net of $2.2 billion accumulated depreciation which includes an
impairment loss recorded in 1999 of $745 million). For additional information
regarding the impairment loss, see Note 4(a). As of December 31, 2001 and 2002,
Texas Genco's investment in nuclear fuel was $35 million (net of $286 million
amortization) and $42 million (net of $302 million amortization), respectively.

(7) INDEXED DEBT SECURITIES (ACES AND ZENS) AND AOL TIME WARNER SECURITIES

(A) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES

In 1995, the Company sold a cable television subsidiary to Time Warner
Inc.(TW) and received TW convertible preferred stock (TW Preferred) as
consideration. On July 6, 1999, the Company converted its 11 million shares of
TW Preferred into 45.8 million shares of Time Warner common stock (TW Common).
Prior to the conversion, the Company's investment in the TW Preferred was
accounted for under the cost method at a value of $990 million in the Company's
Consolidated Balance Sheets. The TW Preferred which was redeemable after July 6,
2000, had an aggregate liquidation preference of $100 per share (plus accrued
and unpaid dividends), was entitled to annual dividends of $3.75 per share until
July 6, 1999 and was convertible by the Company. Effective on the conversion
date, the shares of TW Common were classified as trading securities under SFAS
No. 115 and an unrealized gain was recorded in the amount of $2.4 billion ($1.5
billion after-tax) to reflect the cumulative appreciation in the fair value of
the Company's investment in Time Warner securities. Unrealized gains and losses
resulting from changes in the market value of the TW Common (now AOL TW Common)
are recorded in the Company's Statements of Consolidated Operations.

(B) ACES

In July 1997, in order to monetize a portion of the cash value of its
investment in TW Preferred, the Company issued 22.9 million of its unsecured 7%
Automatic Common Exchange Securities (ACES) having an original principal amount
of $1.052 billion and maturing July 1, 2000. The market value of ACES was
indexed to the market value of TW Common. On the July 1, 2000 maturity date, the
Company tendered 37.9 million shares of TW Common to fully settle its
obligations in connection with its unsecured 7% ACES having a value of $2.9
billion.

(C) ZENS

On September 21, 1999, the Company issued approximately 17.2 million of its
2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an
original principal amount of $1.0 billion. The principal amount per ZENS will
increase each quarter to the extent that the sum of the quarterly cash dividends
and the interest paid during a quarter on the reference shares attributable to
one ZENS is less than $.045, so that the annual yield to investors is not less
than 2.309%. At December 31, 2002, 14.4 million ZENS were outstanding. At
maturity the holders of the ZENS will receive in cash the higher of the original
principal amount of the ZENS (subject to adjustment as discussed above) or an
amount based on the then-current market value of AOL TW Common, or other
securities distributed with respect to AOL TW Common

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(1.5 shares of AOL TW Common and such other securities, if any, are referred to
as reference shares). Each ZENS has a principal amount of $58.25, and is
exchangeable at any time at the option of the holder for cash equal to 95% (100%
in some cases) of the market value of the reference shares attributable to one
ZENS. The Company pays interest on each ZENS at an annual rate of 2% plus the
amount of any quarterly cash dividends paid in respect of the quarterly interest
period on the reference shares attributable to each ZENS. Subject to some
conditions, the Company has the right to defer interest payments from time to
time on the ZENS for up to 20 consecutive quarterly periods. As of December 31,
2002, no interest payments on the ZENS had been deferred.

In 2002, holders of approximately 16% of the 17.2 million ZENS originally
issued exercised their right to exchange their ZENS for cash, resulting in
aggregate cash payments by CenterPoint Energy of approximately $45 million.

A subsidiary of the Company owns shares of AOL TW Common and elected to
liquidate a portion of such holdings to facilitate the Company's making the cash
payments for the ZENS exchanged in 2002. In connection with the exchanges in
2002, the Company received net proceeds of approximately $43 million from the
liquidation of approximately 4.1 million shares of AOL TW Common at an average
price of $10.56 per share. The Company now holds 21.6 million shares of AOL TW
Common which are classified as trading securities under SFAS No. 115 and are
expected to be held to facilitate the Company's ability to meet its obligation
under the ZENS.

Prior to January 1, 2001, an increase in the market value per share of TW
Common above $58.25 (subject to some adjustments) resulted in an increase in the
Company's liability for the ZENS. However, as the market value per share of TW
Common declined below $58.25 (subject to some adjustments), the liability for
the ZENS did not decline below the original principal amount. Upon adoption of
SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into
a debt component and a derivative component (the holder's option to receive the
appreciated value of AOL TW Common at maturity). The derivative component was
valued at fair value and determined the initial carrying value assigned to the
debt component ($121 million) as the difference between the original principal
amount of the ZENS ($1.0 billion) and the fair value of the derivative component
at issuance ($879 million). Effective January 1, 2001 the debt component was
recorded at its accreted amount of $122 million and the derivative component was
recorded at its fair value of $788 million, as a current liability, resulting in
a transition adjustment pre-tax gain of $90 million ($59 million net of tax).
The transition adjustment gain was reported in the first quarter of 2001 as the
effect of a change in accounting principle. Subsequently, the debt component
accretes through interest charges at 17.5% annually up to the minimum amount
payable upon maturity of the ZENS in 2029 (approximately $915 million) which
reflects exchanges and adjustments to maintain a 2.309% annual yield, as
discussed above. Changes in the fair value of the derivative component are
recorded in the Company's Statements of Consolidated Operations. During 2001 and
2002, the Company recorded a loss of $70 million and $500 million, respectively,
on the Company's investment in AOL TW Common. During 2001 and 2002, the Company
recorded a gain of $58 million and $480 million, respectively, associated with
the fair value of the derivative component of the ZENS obligation. Changes in
the fair value of the AOL TW Common held by the Company are expected to
substantially offset changes in the fair value of the derivative component of
the ZENS.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(8) EQUITY

(A) CAPITAL STOCK

Effective with the Restructuring, all outstanding shares of Reliant Energy
no par value common stock were exchanged for shares of CenterPoint Energy common
stock with a par value of $0.01 per share. The capital accounts of CenterPoint
Energy have been restated as of December 31, 2000 and 2001 to give effect to the
change in par value per share. CenterPoint Energy has 1,020,000,000 authorized
shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value
common stock and 20,000,000 shares of $0.01 par value preferred stock.

(B) PREFERRED STOCK

On December 14, 2001, Reliant Energy redeemed all outstanding shares of its
$4.00 Preferred Stock at $105 per share plus accrued dividends of $0.478 per
share for a total redemption payment of $10.3 million. At December 31, 2001,
Reliant Energy had 10,000,000 authorized shares of cumulative preferred stock,
none of which was outstanding. At December 31, 2002, CenterPoint Energy had
20,000,000 authorized shares of preferred stock, none of which was outstanding.

(C) PREFERENCE STOCK

At December 31, 2001, Reliant Energy had 10,000,000 authorized shares of
preference stock, none of which was outstanding for financial reporting
purposes. At December 31, 2001, Reliant Energy had issued and outstanding shares
of preference stock that were held by various financing subsidiaries of the
Company to

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

support debt obligations of the subsidiaries to third party lenders. The
aggregate amount of debt outstanding at these subsidiaries at December 31, 2001
was $2.9 billion. These shares of preference stock were cancelled in 2002
effective with the extinguishment of debt by the financing subsidiaries.

(D) SHAREHOLDER RIGHTS PLAN

The Company has a Shareholder Rights Plan that states that each share of
its common stock includes one associated preference stock purchase right (Right)
which entitles the registered holder to purchase from the Company a unit
consisting of one-thousandth of a share of Series A Preference Stock. The
Rights, which expire on December 11, 2011, are exercisable upon some events
involving the acquisition of 20% or more of the Company's outstanding common
stock. Upon the occurrence of such an event, each Right entitles the holder to
receive common stock with a current market price equal to two times the exercise
price of the Right. At anytime prior to becoming exercisable, the Company may
repurchase the Rights at a price of $0.005 per Right. There are 700,000 shares
of Series A Preference Stock reserved for issuance upon exercise of the Rights.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(9) LONG-TERM DEBT AND SHORT-TERM BORROWINGS

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

(1) Includes amounts due or exchangeable within one year of the date noted.

(2) In the first quarter of 2002, CERC reduced its trade receivables facility
from $350 million to $150 million. Advances under the receivables facility
aggregating $196 million were repaid in January 2002 with proceeds from the
issuance of commercial paper and from the liquidation of short-term
investments. For further discussion of the receivables facility, see Note
3(i).

(3) The $391 million of other short-term borrowings at December 31, 2001
reflects a note payable to Reliant Resources, which was repaid in 2002.

(4) Upon adoption of SFAS No. 133 effective January 1, 2001, the Company's ZENS
obligation was bifurcated into a debt component and an embedded derivative
component. For additional information regarding ZENS, see Note 7(c). As ZENS
are exchangeable for cash at any time at the option of the holders, these
notes are classified as a current portion of long-term debt.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(5) These series of debt are secured by first mortgage bonds of CenterPoint
Houston.

(6) $527 million of these series of debt is secured by general mortgage bonds
of CenterPoint Houston.

(7) On February 28, 2003, CenterPoint Energy amended and extended the
termination date of its $3.85 billion credit facility to June 30, 2005 as
discussed further below. As a result of this extension, the $3.85 billion
credit facility has been classified as long-term debt as of December 31,
2002 in the Consolidated Balance Sheet.

(8) The December 31, 2001 debt balances have been reclassified to give effect
to the Restructuring, which occurred on August 31, 2002.

(9) For further discussion of the securitization financing, see Note 4(a).

(10) London inter-bank offered rate (LIBOR) has a minimum rate of 3%. This term
loan is secured by general mortgage bonds of CenterPoint Houston.

(11) Debt acquired in business acquisitions is adjusted to fair market value as
of the acquisition date. Included in long-term debt is additional
unamortized premium related to fair value adjustments of long-term debt of
$9 million and $7 million at December 31, 2001 and 2002, respectively,
which is being amortized over the respective remaining term of the related
long-term debt.

During 2002, the Company recorded a $17 million after-tax extraordinary
item related to a loss on the early extinguishment of debt related to
CenterPoint Houston's $850 million term loan and the repurchase of $175 million
of the Company's pollution control bonds.

(a) SHORT-TERM BORROWINGS

Credit Facilities. As of December 31, 2002, CenterPoint Energy and its
subsidiaries had credit facilities that provided for an aggregate of $4.2
billion in committed credit. As of December 31, 2002, such credit facilities
were fully utilized in the form of letters of credit aggregating $2.5 million
and loans. The weighted average interest rate on short-term borrowings at
December 31, 2001 and December 31, 2002 was 2.9% and 5.4%, respectively. These
interest rates exclude facility fees and other fees paid in connection with the
arrangement of the bank facilities. As of December 31, 2002, cash aggregating
$265 million was invested in a money market fund.

In July 2002, the termination dates of facilities aggregating $4.7 billion
were extended from July 12, 2002 to October 10, 2002. Upon the Restructuring,
CenterPoint Energy became the borrower under facilities aggregating $4.3
billion, CenterPoint Houston remained the borrower under its $400 million
facility and CERC Corp. remained both the borrower under its $350 million
revolver and the seller under its $150 million receivables facility. The $150
million receivables facility is not recorded as a financing as it provides for
the sale of receivables to third parties as discussed in Note 3(i) to the
consolidated financial statements.

On October 10, 2002, the agreements relating to $4.3 billion of bank
facilities at CenterPoint Energy and $400 million of bank facilities at
CenterPoint Houston were amended and extended. On November 12, 2002, $850
million of bank facilities were terminated with the proceeds of CenterPoint
Houston's $1.3 billion collateralized term loan as discussed below. The
remaining $3.85 billion of CenterPoint Energy's outstanding bank facilities were
originally scheduled to expire on October 9, 2003, with two $600 million
mandatory principal reduction payments under the facilities due on or prior to
June 30, 2003. On February 28, 2003, the $3.85 billion bank facility was amended
and extended as discussed below. Accordingly, the $3.85 billion of outstanding
bank loans as of December 31, 2002 have been reclassified as long-term debt in
the Consolidated Balance Sheet.

As of December 31, 2002, there was $347 million borrowed under CERC's $350
million revolving credit facility. On February 28, 2003, CERC executed a
commitment letter with a major bank for a $350 million, 180-day bridge facility,
which is subject to the satisfaction of various closing conditions. This
facility will be

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

available for repaying borrowings under CERC's existing $350 million revolving
credit facility that expires on March 31, 2003 in the event sufficient proceeds
are not raised in the capital markets to repay such borrowings on or before
March 31, 2003. Final terms for the bridge facility have not been established,
but it is anticipated that the rates for borrowings under the facility will be
LIBOR plus 450 basis points. CERC paid a commitment fee of 25 basis points on
the commitment amount and will be required to pay a facility fee of 75 basis
points on the amount funded and an additional 100 basis points on the amount
funded and outstanding for more than two months. In connection with this
facility, CERC expects to provide the lender with collateral in the form of a
security interest in the stock it owns in its interstate natural gas pipeline
subsidiaries.

In February 2003, CenterPoint Houston obtained a $75 million revolving
credit facility that terminates on April 30, 2003. A condition precedent to
utilizing the facility is that security in the form of general mortgage bonds
must be delivered to the lender. Rates for borrowings under this facility,
including the facility fee, will be LIBOR plus 250 basis points.

The bank facilities contain various business and financial covenants. The
borrowers are currently in compliance with the covenants under the applicable
credit agreements.

At the beginning of 2002, commercial paper programs aggregated $5 billion.
A reduction in the size of the commercial paper programs occurred in the third
and fourth quarters of 2002 as revolving credit facilities were converted to
term loan facilities. The maximum amount of each issuer's outstanding commercial
paper was limited to the amount of its revolving credit facility less any direct
loans or letters of credit obtained under its revolver. In October 2002, all
commercial paper was repaid with proceeds from bank loans. The extent to which
commercial paper is issued in lieu of bank loans depends, in part, on market
conditions and the credit ratings of the commercial paper issuer. The commercial
paper programs were terminated in December 2002.

(b) LONG-TERM DEBT

On February 28, 2003, the Company reached agreement with a syndicate of
banks on a second amendment to its $3.85 billion bank facility (the "Second
Amendment"). Under the Second Amendment, the maturity date of the bank facility
was extended from October 2003 to June 30, 2005, and the $1.2 billion in
mandatory prepayments that would have been required this year (including $600
million due on February 28, 2003) were eliminated. The facility consists of a
$2.35 billion term loan and a $1.5 billion revolver. Borrowings bear interest
based on LIBOR rates under a pricing grid tied to the Company's credit rating.
At our current credit ratings, the pricing for loans remains the same. The drawn
cost for the facility at our current ratings is LIBOR plus 450 basis points. The
Company has agreed to pay the banks an extension fee of 75 basis points on the
amounts outstanding under the bank facility on October 9, 2003. The Company also
paid $41 million in fees that were due on February 28, 2003, along with $20
million in fees that had been due on June 30, 2003.

In addition, the interest rates will be increased by 25 basis points
beginning May 28, 2003 if the Company does not grant the banks a security
interest in our 81% stock ownership of Texas Genco. Granting the security
interest in the stock of Texas Genco requires approval from the Securities and
Exchange Commission (SEC) under the 1935 Act, which is currently being sought.
That security interest would be released when the Company sells Texas Genco,
which is expected to occur in 2004. Proceeds from the sale will be used to
reduce the bank facility.

Also under the Second Amendment, on or before May 28, 2003, the Company
expects to grant to the banks warrants to purchase up to 10%, on a fully diluted
basis, of our common stock at a price equal to the greater of $6.56 per share or
110% of the closing price on the New York Stock Exchange on the date the
warrants are issued. The warrants would not be exercisable for a year after
issuance but would remain outstanding for four years; provided, that if the
Company reduces the bank facility during 2003 by specified amounts, the warrants
will be extinguished. To the extent that the Company reduces the bank facility
by up to

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

$400 million on or before May 28, 2003, up to half of the warrants will be
extinguished on a basis proportionate to the reduction in the credit facility.
To the extent such warrants are not extinguished on or before May 28, 2003, they
will vest and become exercisable in accordance with their terms. Whether or not
the Company is able to extinguish warrants on or before May 28, 2003, the
remaining 50% of the warrants will be extinguished, again on a proportionate
basis, if the Company reduces the bank facility by up to $400 million by the end
of 2003. The Company plans to eliminate the warrants entirely before they vest
by accessing the capital markets to fund the total payments of $800 million
during 2003; however, because of current financial market conditions and
uncertainties regarding such conditions over the balance of the year, there can
be no assurance that the Company will be able to extinguish the warrants or to
do so on favorable terms.

The warrants and the underlying common stock would be registered with the
SEC and could be exercised either through the payment of the purchase price or
on a "cashless" basis under which the Company would issue a number of shares
equal to the difference between the then-current market price and the warrant
exercise price. Issuance of the warrants is also subject to obtaining SEC
approval under the 1935 Act, which is currently being sought. If that approval
is not obtained on or before May 28, 2003, the Company will provide the banks
equivalent cash compensation over the term that its warrants would have been
exercisable to the extent they are not otherwise extinguished.

In the Second Amendment, the Company also agreed that its quarterly common
stock dividend will not exceed $0.10 per share. If the Company has not reduced
the bank facility by a total of at least $400 million by the end of 2003, of
which at least $200 million has come from the issuance of capital stock or
securities linked to capital stock (such as convertible debt), the maximum
dividend payable during 2004 and for the balance of the term of the facility is
subject to an additional test. Under that test the maximum permitted quarterly
dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of the
Company's net income per share for the 12 months ended on the last day of the
previous quarter.

The Second Amendment provides that proceeds from capital stock or
indebtedness issued or incurred by the Company must be applied (subject to a
$200 million basket for CERC and another $250 million basket for borrowings by
the Company and other limited exceptions) to repay bank loans and reduce the
bank facility. Similarly, cash proceeds from the sale of assets of more than $30
million or, if less, a group of sales aggregating more than $100 million, must
be applied to repay bank loans and reduce the bank facility, except that
proceeds of up to $120 million can be reinvested in the Company's businesses.

On November 12, 2002, CenterPoint Houston entered into a $1.3 billion
collateralized term loan maturing November 2005. The interest rate on the loan
is LIBOR plus 9.75%, subject to a minimum rate of 12.75%. The loan is secured by
CenterPoint Houston's general mortgage bonds. Proceeds from the loan were used
to (1) repay CenterPoint Houston's $850 million term loan, (2) pay costs of
issuance, (3) repay $300 million of debt that matured on November 15, 2002 and
(4) to purchase $100 million of pollution control bonds on December 1, 2002. The
loan agreement contains various business and financial covenants including a
covenant restricting CenterPoint Houston's debt, excluding transition bonds, as
a percent of its total capitalization to 68%. The loan agreement also limits
incremental secured debt that may be issued by CenterPoint Houston to $300
million.

Maturities. The Company's maturities of long-term debt and sinking fund
requirements, excluding the ZENS obligation, are $706 million in 2003 (of which
$500 million may be remarketed by an option holder to a maturity of 2013), $47
million in 2004, $5.6 billion in 2005, $210 million in 2006 and $68 million in
2007. The 2003 and 2004 amounts are net of sinking fund payments that can be
satisfied with bonds that had been acquired and retired as of December 31, 2002.

Liens. CenterPoint Houston's assets are subject to liens securing
approximately $1.2 billion of first mortgage bonds. Sinking or improvement fund
and replacement fund requirements on the first mortgage bonds may be satisfied
by certification of property additions. Sinking fund and replacement fund
requirements

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

for 2000, 2001 and 2002 have been satisfied by certification of property
additions. The replacement fund requirement to be satisfied in 2003 is
approximately $347 million, and the sinking fund requirement to be satisfied in
2003 is approximately $15 million. The Company expects CenterPoint Houston to
meet these 2003 obligations by certification of property additions. CenterPoint
Houston's assets are subject to liens securing approximately $1.8 billion of
general mortgage bonds which are junior to the liens of the first mortgage
bonds.

Securitization. For a discussion of the securitization financing completed
in October 2001, see Note 4(a).

Purchase of Pollution Control Bonds. In the fourth quarter of 2002, the
Company purchased $175 million of pollution control bonds issued on its behalf.
The Company expects to remarket the bonds during the first half of 2003.

Purchase of Convertible Debentures. At December 31, 2001 and 2002, CERC
Corp. had issued and outstanding $86 million and $79 million, respectively,
aggregate principal amount ($82 million and $76 million, respectively, carrying
amount) of its 6% Convertible Subordinated Debentures due 2012 (Subordinated
Debentures). The holders of the Subordinated Debentures receive interest
quarterly and, prior to the Restructuring, had the right at any time on or
before the maturity date thereof to convert each $50 principal amount of
Subordinated Debentures into 0.65 shares of Reliant Energy common stock and
$14.24 in cash. After the Restructuring, but prior to the Reliant Resources
Distribution, each $50 principal amount of Subordinated Debentures was
convertible into 0.65 shares of CenterPoint Energy common stock and $14.24 in
cash. The Reliant Resources Distribution and the Texas Genco stock distribution
changed the conversion rights for each $50 principal amount of Subordinated
Debentures as follows:

During 2002, CERC Corp. purchased $6.6 million aggregate principal amount
of its Subordinated Debentures.

TERM Notes. CERC Corp.'s $500 million aggregate principal amount of 6 3/8%
Term Enhanced ReMarketable Securities (TERM Notes) provide an investment bank
with a call option, that gives it the right to have the TERM Notes tendered to
it by the holders on November 1, 2003 and then remarketed if it chooses to
exercise the option. The TERM Notes are unsecured obligations of CERC Corp. that
bear interest at an annual rate of 6 3/8% through November 1, 2003. On November
1, 2003, the holders of the TERM Notes are required to tender their notes at
100% of their principal amount. The portion of the proceeds attributable to the
call option premium will be amortized over the stated term of the securities. If
the option is not exercised by the investment bank, CERC Corp. will repurchase
the TERM Notes at 100% of their principal amount on November 1, 2003. If the
option is exercised, the TERM Notes will be remarketed on a date, selected by
CERC Corp., within the 52-week period beginning November 1, 2003. CERC Corp. may
elect into this 52-week remarketing window only if its senior unsecured debt
securities are rated at least Baa3 by Moody's Investors Service, Inc. and BBB-
by Standard & Poor's Ratings Services, a division of The McGraw Hill Companies
(unless the investment banker waives that requirement). During this period and
prior to remarketing, the TERM Notes will bear interest at rates, adjusted
weekly, based on an index selected by CERC Corp. CERC Corp. may elect to redeem
the TERM Notes in whole, but not in part, from the investment bank prior to
remarketing. If the TERM Notes are remarketed, the final maturity date of the
TERM Notes will be November 1, 2013, subject to adjustment, and the effective
interest rate on the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

remarketed TERM Notes will be 5.66% plus CERC Corp.'s applicable credit spread
at the time of such remarketing.

Transportation Agreement. A subsidiary of CERC Corp. had an agreement (ANR
Agreement) with ANR Pipeline Company (ANR) that contemplated that this
subsidiary would transfer to ANR an interest in some of CERC Corp.'s pipeline
and related assets. In 2001, this subsidiary was transferred to Reliant
Resources as a result of CenterPoint Energy's planned divestiture of certain
unregulated business operations. However, CERC retained the pipelines covered by
the ANR Agreement. Therefore, the subsequent divestiture of Reliant Resources by
CenterPoint Energy on September 30, 2002, resulted in a conversion of CERC's
obligation to ANR into an obligation to Reliant Resources. As of December 31,
2001, the Company had recorded $41 million in long-term debt and as of December
31, 2002, the Company had recorded $5 million and $36 million in current portion
of long-term debt and long-term debt, respectively, in its Consolidated Balance
Sheets to reflect this obligation for the use of 130 million cubic feet
(Mmcf)/day of capacity in some of CERC's transportation facilities. The volume
of transportation will decline to 100 Mmcf/day in the year 2003 with a refund by
CERC of $5 million to Reliant Resources. The ANR Agreement will terminate in
2005 with a refund of $36 million to Reliant Resources.

(10) TRUST PREFERRED SECURITIES

In February 1997, two Delaware statutory business trusts created by
CenterPoint Energy (HL&P Capital Trust I and HL&P Capital Trust II) issued to
the public (a) $250 million aggregate amount of preferred securities and (b)
$100 million aggregate amount of capital securities, respectively. In February
1999, a Delaware statutory business trust created by CenterPoint Energy (REI
Trust I) issued $375 million aggregate amount of preferred securities to the
public. CenterPoint Energy accounts for REI Trust I, HL&P Capital Trust I and
HL&P Capital Trust II as wholly owned consolidated subsidiaries. Each of the
trusts used the proceeds of the offerings to purchase junior subordinated
debentures issued by CenterPoint Energy having interest rates and maturity dates
that correspond to the distribution rates and the mandatory redemption dates for
each series of preferred securities or capital securities.

The junior subordinated debentures are the trusts' sole assets and their
entire operations. CenterPoint Energy considers its obligations under the
Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and,
where applicable, Agreement as to Expenses and Liabilities, relating to each
series of preferred securities or capital securities, taken together, to
constitute a full and unconditional guarantee by CenterPoint Energy of each
trust's obligations with respect to the respective series of preferred
securities or capital securities.

The preferred securities and capital securities are mandatorily redeemable
upon the repayment of the related series of junior subordinated debentures at
their stated maturity or earlier redemption. Subject to some limitations,
CenterPoint Energy has the option of deferring payments of interest on the
junior subordinated debentures. During any deferral or event of default,
CenterPoint Energy may not pay dividends on its capital stock. As of December
31, 2002, no interest payments on the junior subordinated debentures had been
deferred.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The outstanding aggregate liquidation amount, distribution rate and
mandatory redemption date of each series of the preferred securities or capital
securities of the trusts described above and the identity and similar terms of
each related series of junior subordinated debentures are as follows:

In June 1996, a Delaware statutory business trust created by CERC Corp.
(CERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. CERC Corp. accounts for CERC Trust as a wholly owned
consolidated subsidiary. CERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by CERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent CERC Trust's sole asset and
its entire operations. CERC Corp. considers its obligation under the Amended and
Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the
convertible preferred securities, taken together, to constitute a full and
unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect
to the convertible preferred securities.

The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Effective January 7, 2003, the convertible
preferred securities are convertible at the option of the holder into $33.62 of
cash and 2.34 shares of CenterPoint Energy common stock for each $50 of
liquidation value. As of December 31, 2001 and 2002, $0.4 million liquidation
amount of convertible preferred securities were outstanding. The securities, and
their underlying convertible junior subordinated debentures, bear interest at
6.25% and mature in June 2026. Subject to some limitations, CERC Corp. has the
option of deferring payments of interest on the convertible junior subordinated
debentures. During any deferral or event of default, CERC Corp. may not pay
dividends on its common stock to CenterPoint Energy. As of December 31, 2002, no
interest payments on the convertible junior subordinated debentures had been
deferred.

(11) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS

(a) INCENTIVE COMPENSATION PLANS

The Company has long-term incentive compensation plans (LICP) that provide
for the issuance of stock-based incentives, including performance-based shares,
performance-based units, restricted shares, stock options and stock appreciation
rights to key employees of the Company, including officers. As of December 31,
2002, 344 current and 443 former employees of the Company participate in the
plans. A maximum of approximately 37 million shares of CenterPoint Energy common
stock may be issued under these plans.

Performance-based shares, performance-based units and restricted shares are
granted to employees without cost to the participants. The performance shares
and units vest three years after the grant date based

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

upon the performance of the Company over a three-year cycle, except as discussed
below. The restricted shares vest at various times ranging from immediately to
at the end of a three-year period. Upon vesting, the shares are issued to the
plan participants.

During 2000, 2001 and 2002, the Company recorded compensation expense of
$22 million, $6 million and $2 million, respectively, related to
performance-based shares, performance-based units and restricted share grants.
Included in these amounts is $7 million and $5 million in compensation expense
for 2000 and 2001, respectively, related to Reliant Resources' participants. In
addition, compensation benefit of $1 million was recorded in 2002 related to
Reliant Resources' participants. Amounts for Reliant Resources' participants are
reflected in discontinued operations in the Statements of Consolidated
Operations.

The following table summarizes the Company's performance-based units,
performance-based shares and restricted share grant activity for the years 2000
through 2002:

The maximum value associated with the performance-based units granted in
2001 was $150 per unit.

Effective with the Reliant Resources Distribution which occurred on
September 30, 2002, the Company's compensation committee authorized the
conversion of outstanding CenterPoint Energy performance-based shares for the
performance cycle ending December 31, 2002 to a number of time-based restricted
shares of CenterPoint Energy's common stock equal to the number of
performance-based shares that would have vested if the performance objectives
for the performance cycle were achieved at the maximum level for substantially
all shares. These time-based restricted shares vested if the participant holding
the shares remained employed with the Company or with Reliant Resources and its
subsidiaries through December 31, 2002. On the date of the Reliant Resources
Distribution, holders of these time-based restricted shares received shares of
Reliant Resources common stock in the same manner as other holders of
CenterPoint Energy common stock, but these shares of common stock were subject
to the same time-based vesting schedule, as well as to the terms and conditions
of the plan under which the original performance shares were granted. Thus,
following the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Reliant Resources Distribution, employees who held performance-based shares
under the LICP for the performance cycle ending December 31, 2002 held
time-based restricted shares of CenterPoint Energy common stock and time-based
restricted shares of Reliant Resources common stock, which vested following
continuous employment through December 31, 2002.

Effective with the Reliant Resources Distribution, the Company converted
all outstanding CenterPoint Energy stock options granted prior to the Reliant
Resources Offering to a combination of adjusted CenterPoint Energy stock options
and Reliant Resources stock options. For the converted stock options, the sum of
the intrinsic value of the CenterPoint Energy stock options immediately prior to
the record date of the Reliant Resources Distribution equaled the sum of the
intrinsic values of the adjusted CenterPoint Energy stock options and the
Reliant Resources stock options granted immediately after the record date of the
Reliant Resources Distribution. As such, Reliant Resources employees who do not
work for the Company hold stock options of the Company. Both the number and the
exercise price of all outstanding CenterPoint Energy stock options that were
granted on or after the Reliant Resources Offering were adjusted to maintain the
total intrinsic value of the grants.

During January 2003, due to the distribution of Texas Genco stock, the
Company granted additional CenterPoint Energy shares to participants with
performance-based and time-based shares that had not yet vested as of the record
date of December 20, 2002. These additional shares are subject to the same
vesting schedule and the terms and conditions of the plan under which the
original shares were granted. Also in connection with this distribution, both
the number and the exercise price of all outstanding CenterPoint Energy stock
options were adjusted to maintain the total intrinsic value of the stock option
grants.

Under the Company's plans, stock options generally become exercisable in
one-third increments on each of the first through third anniversaries of the
grant date. The exercise price is the average of the high and low sales price of
the common stock on the New York Stock Exchange on the grant date. The Company
applies APB Opinion No. 25, "Accounting for Stock Issued to Employees" (APB
Opinion No. 25), and related interpretations in accounting for its stock option
plans. Accordingly, no compensation expense has been recognized for these fixed
stock options. The following table summarizes stock option activity related to
the Company for the years 2000 through 2002:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Exercise prices for CenterPoint Energy stock options outstanding held by
Company employees ranged from $5.00 to $40.00. The following tables provide
information with respect to outstanding CenterPoint Energy stock options held by
the Company's employees on December 31, 2002:

The following table provides information with respect to CenterPoint Energy
stock options exercisable at December 31, 2002:

In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation"
(SFAS No. 123), and SFAS No. 148, the Company applies the guidance contained in
APB Opinion No. 25 and discloses the required pro forma effect on net income of
the fair value based method of accounting for stock compensation. The weighted
average fair values at date of grant for CenterPoint Energy options granted
during 2000, 2001 and 2002 were $5.07, $9.25 and $1.40, respectively. The fair
values were estimated using the Black-Scholes option valuation model with the
following weighted-average assumptions:

Pro forma information for 2000, 2001 and 2002 is provided to take into
account the amortization of stock-based compensation to expense on a
straight-line basis over the vesting period. Had compensation costs been

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

determined as prescribed by SFAS No. 123, the Company's net income and earnings
per share would have been as follows:

(B) PENSION AND POSTRETIREMENT BENEFITS

The Company maintains a pension plan which is a non-contributory defined
benefit plan covering substantially all employees using a cash balance formula.
Under the cash balance formula, participants accumulate a retirement benefit
based upon 4% of eligible earnings and accrued interest. Prior to 1999, the
pension plan accrued benefits based on years of service, final average pay and
covered compensation. As a result, certain employees participating in the plan
as of December 31, 1998 are eligible to receive the greater of the accrued
benefit calculated under the prior plan through 2008 or the cash balance
formula.

The Company's funding policy is to review amounts annually in accordance
with applicable regulations in order to achieve adequate funding of projected
benefit obligations. The assets of the pension plans consist principally of
common stocks and interest bearing obligations. Included in such assets are
approximately 4.5 million shares of CenterPoint Energy common stock contributed
from treasury stock during 2001. As of December 31, 2002, the fair value of
CenterPoint Energy common stock was $38 million or 4.7% of the pension plan
assets.

The Company provides certain healthcare and life insurance benefits for
retired employees on a contributory and non-contributory basis. Employees become
eligible for these benefits if they have met certain age and service
requirements at retirement, as defined in the plans. Under plan amendments
effective in early 1999, health care benefits for future retirees were changed
to limit employer contributions for medical coverage.

Such benefit costs are accrued over the active service period of employees.
The net unrecognized transition obligation, resulting from the implementation of
accrual accounting, is being amortized over approximately 20 years.

The Company is required to fund a portion of its obligations in accordance
with rate orders. All other obligations are funded on a pay-as-you-go basis.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The Company's net periodic cost (benefit) includes the following components
relating to pension and postretirement benefits:

The following table displays the change in the benefit obligation, the fair
value of plan assets and the amounts included in the Company's Consolidated
Balance Sheets as December 31, 2001 and 2002 for the Company's pension and
postretirement benefit plans:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

For the year ended December 31, 2001, the assumed health care cost trend
rates were 7.5% for participants under age 65 and 8.5% for participants age 65
and over. For the year ended December 31, 2002, the assumed health cost trend
rate was increased to 12% for all participants. The health care cost trend rates
decline by .75% annually to 5.5% by 2011.

If the health care cost trend rate assumption were increased by 1%, the
accumulated postretirement benefit obligation as of December 31, 2002 would
increase by 2.9%. The annual effect of a 1% increase on the sum of service and
interest cost would be an increase of approximately 2.4%. If the health care
cost trend rate assumption were decreased by 1%, the accumulated postretirement
benefit obligation as of December 31, 2002 would decrease approximately 2.8%.
The annual effect of a 1% decrease on the sum of service and interest cost would
be a decrease of 2.4%.

In addition to the non-contributory pension plans discussed above, the
Company maintains a non-qualified pension plan which allow participants to
retain the benefits to which they would have been entitled under the Company's
non-contributory pension plan except for the federally mandated limits on these
benefits or on the level of compensation on which these benefits may be
calculated. The expense associated with this non-qualified plan was $25 million,
$25 million and $9 million in 2000, 2001 and 2002, respectively. Included in the
net benefit cost in 2001 and 2002 is $17 million and $3 million, respectively,
of expense related to Reliant Resources' participants, which is reflected in
discontinued operations in the Statements of Consolidated Operations. The
accrued benefit liability for the non-qualified pension plan was $99 million and
$83 million at December 31, 2001 and 2002, respectively. In addition, these
accrued benefit liabilities include the recognition of minimum liability
adjustments of $20 million as of December 31, 2001 and $23 million as of
December 31, 2002, which are reported as a component of other comprehensive
income, net of income tax effects. Included in these amounts is $30 million of
accrued benefit liabilities for Reliant Resources' participants as of December
31, 2001. Of these liabilities, $11 million represents the recognition of
minimum

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

liability adjustments, which are reported as discontinued operations on the
Statements of Consolidated Comprehensive Income, net of income tax effects.

(C) SAVINGS PLAN

The Company has an employee savings plan that includes a cash or deferred
arrangement under Section 401(k) of the Internal Revenue Code of 1986, as
amended (the Code). Under the plan, participating employees may contribute a
portion of their compensation, on a pre-tax or after-tax basis, generally up to
a maximum of 16% of compensation. The Company matches 75% of the first 6% of
each employee's compensation contributed. The Company may contribute an
additional discretionary match of up to 50% of the first 6% of each employee's
compensation contributed. These matching contributions are fully vested at all
times. A substantial portion of the Company's match is initially invested in
CenterPoint Energy common stock.

Participating employees may elect to invest all or a portion of their
contributions to the plan in CenterPoint Energy common stock, to have dividends
reinvested in additional shares or to receive dividend payments in cash on any
investment in CenterPoint Energy common stock, and to transfer all or part of
their investment in CenterPoint Energy common stock to other investment options
offered by the plan.

The Company's savings plan includes an Employee Stock Ownership Plan
(ESOP), which contains company stock, a portion of which is encumbered by a
loan. Upon the release from the encumbrance of the loan, the Company may use
released shares to satisfy its obligation to make matching contributions under
the Company's savings plan. Generally, debt service on the loan is paid using
all dividends on shares currently or formerly encumbered by the loan, interest
earnings on funds held in trust and cash contributions by the Company. Shares of
CenterPoint Energy common stock are released from the encumbrance of the loan
based on the proportion of debt service paid during the period.

The Company recognizes benefit expense equal to the fair value of the
shares committed to be released. The Company credits to unearned shares the
original purchase price of shares committed to be released to plan participants
with the difference between the fair value of the shares and the original
purchase price recorded to common stock. Dividends on allocated shares are
recorded as a reduction to retained earnings. Dividends on unallocated shares
are recorded as a reduction of principal or accrued interest on the loan.

Share balances currently or formerly encumbered by a loan at December 31,
2001 and 2002 were as follows:

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

(1) During 2002, unearned shares and total shares were increased by 831,500
shares. This is due to additional shares purchased with proceeds from the
sale of Reliant Resources common stock, which was received in connection
with the Reliant Resources Distribution.

As a result of the ESOP, the savings plan has significant holdings of
CenterPoint Energy common stock. As of December 31, 2002, an aggregate of
32,099,870 shares of CenterPoint Energy's common stock were held by the savings
plan, which represented 30% of its investments. Given the concentration of the
investments in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

CenterPoint Energy's common stock, the savings plan and its participants have
market risk related to this investment.

The Company's savings plan benefit expense was $52 million, $51 million and
$47 million in 2000, 2001 and 2002, respectively. Included in these amounts are
$5 million $16 million and $6 million of savings plan benefit expense for 2000,
2001 and 2002, respectively, related to Reliant Resources' participants, which
is reflected as discontinued operations in the Statements of Consolidated
Operations.

(D) POSTEMPLOYMENT BENEFITS

Net postemployment benefit costs for former or inactive employees, their
beneficiaries and covered dependents, after employment but before retirement
(primarily health care and life insurance benefits for participants in the
long-term disability plan) were $2 million, $6 million and $12 million in 2000,
2001 and 2002, respectively.

The Company's postemployment obligation is presented as a liability in the
Consolidated Balance Sheets under the caption "Benefit Obligations."

(E) OTHER NON-QUALIFIED PLANS

The Company has in effect deferred compensation plans which permit eligible
participants to elect each year to defer a percentage of that year's salary and
up to 100% of that year's annual bonus. In general, employees who attain the age
of 60 during employment and participate in the Company's deferred compensation
plans may elect to have their deferred compensation amounts repaid in (a)
fifteen equal annual installments commencing at the later of age 65 or
termination of employment or (b) a lump-sum distribution following termination
of employment. Interest generally accrues on deferrals at a rate equal to the
average Moody's Long-Term Corporate Bond Index plus 2%, determined annually
until termination when the rate is fixed at the rate in effect for the plan year
immediately prior to that in which a participant attains age 65. During 2000,
2001 and 2002, the Company recorded interest expense related to its deferred
compensation obligation of $14 million, $17 million and $11 million,
respectively. Included in these amounts are $1 million, $4 million and $0.2
million of interest expense for 2000, 2001 and 2002, respectively, related to
Reliant Resources' participants, which is reflected as discontinued operations
in the Statements of Consolidated Operations. The discounted deferred
compensation obligation recorded by the Company was $161 million and $132
million as of December 31, 2001 and 2002, respectively.

The Company's obligations under other non-qualified plans are presented as
a liability in the Consolidated Balance Sheets under the caption "Benefit
Obligations."

(F) OTHER EMPLOYEE MATTERS

As of December 31, 2002, approximately 38% of the Company's employees are
subject to collective bargaining agreements. Three of these agreements, covering
approximately 24% of the Company's employees, will expire in 2003.

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(12) INCOME TAXES

The components of income from continuing operations before income taxes are
as follows:

The Company's current and deferred components of income tax expense
(benefit) were as follows:

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A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

Following are the Company's tax effects of temporary differences between
the carrying amounts of assets and liabilities in the financial statements and
their respective tax bases:

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Tax Attribute Carryforwards. At December 31, 2002, the Company had $7
million and $387 million of federal and state net operating loss carryforwards,
respectively. The losses are available to offset future respective federal and
state taxable income through the year 2022.

In conjunction with the Reliant Resources Distribution, the Company
realized a previously unrecorded capital loss attributable to the excess of the
tax basis over the book carrying value in former subsidiaries sold to Reliant
Resources. The tax benefit of this excess tax basis is recorded under SFAS No.
109, "Accounting for Income Taxes," when realizable under the facts, such as a
loss from a previously deferred taxable disposition that is triggered by a
spin-off. This loss is a capital loss which may be used in the three taxable
years preceding the year of the loss, or the five taxable years following the
year of the loss. Federal tax law only allows utilization of capital losses to
offset capital gains. A valuation allowance is provided against 100% of the
expected benefit due to the uncertainty in the Company's ability to generate
capital gains during the utilization period.

The valuation allowance reflects a net decrease of $32 million in 2001 and
a net increase of $68 million in 2002. These net changes resulted from a
reassessment of the Company's future ability to use federal capital loss
carryforwards and state tax net operating loss carryforwards.

Tax Refunds. In 2000, the Company received refunds from the Internal
Revenue Service totaling $126 million in taxes and interest following audits of
tax returns and refund claims for CenterPoint Energy's 1985, 1986 and 1990
through 1995 tax years, and CERC Corp.'s 1979 through 1993 tax years. The
pre-tax income statement effect of $40 million ($26 million after-tax) was
recorded in 2000 in other income in the Company's Statements of Consolidated
Operations. Of the refunds, $26 million was recorded as a reduction in goodwill.
CenterPoint Energy's consolidated federal income tax returns have been audited
and settled through the 1996 tax year. All of CERC Corp.'s consolidated federal
income tax returns for tax years ending on or prior to CenterPoint Energy's
acquisition of CERC Corp. have been audited and settled.

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(13) COMMITMENTS AND CONTINGENCIES

(a) COMMITMENTS AND GUARANTEES

Environmental Capital Commitments. CenterPoint Energy anticipates
investing up to $131 million in capital and other special project expenditures
between 2003 and 2007 for environmental compliance. CenterPoint Energy
anticipates expenditures to be as follows (in millions):

2003........................................................ $ 98
2004........................................................ 33
2005........................................................ --
2006(1)..................................................... --
2007(1)..................................................... --
----
Total $131
====

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

(1) NOx control estimates for 2006 and 2007 have not been finalized.

Fuel and Purchased Power. Fuel commitments include several long-term coal,
lignite and natural gas contracts related to Texas power generation operations,
which have various quantity requirements and durations that are not classified
as non-trading derivatives assets and liabilities in the Company's Consolidated
Balance Sheets as of December 31, 2002 as these contracts meet the SFAS No. 133
exception to be classified as "normal purchases contracts" or do not meet the
definition of a derivative. Minimum payment obligations for coal and
transportation agreements that extend through 2012 are approximately $292
million in 2003, $165 million in 2004, $169 million in 2005, $174 million in
2006 and $167 million in 2007. Purchase commitments related to lignite mining
and lease agreements and purchased power are not material to CenterPoint
Energy's operations. Prior to January 1, 2002, CenterPoint Houston was allowed
recovery of these costs through rates for electric service. As of December 31,
2002, some of these contracts are above market. CenterPoint Energy anticipates
that stranded costs associated with these obligations will be recoverable
through the stranded cost recovery mechanisms contained in the Texas electric
restructuring law. For information regarding the Texas electric restructuring
law, see Note 4(a).

CenterPoint Energy's other long-term fuel supply commitments, which have
various quantity requirements and durations, are not considered material either
individually or in the aggregate to its results of operations or cash flows.

(b) LEASE COMMITMENTS

The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2002, which primarily consist of rental agreements for building space, data
processing equipment and vehicles, including major work equipment (in millions).

2003........................................................ $ 31
2004........................................................ 28
2005........................................................ 26
2006........................................................ 24
2007........................................................ 23
2008 and beyond............................................. 131
----
Total..................................................... $263
====

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Total lease expense for all operating leases was $46 million, $45 million
and $43 million during 2000, 2001 and 2002, respectively.

(C) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Legal Matters

The Company's predecessor, Reliant Energy, and certain of its former
subsidiaries are named as defendants in several lawsuits described below. Under
a master separation agreement between Reliant Energy and Reliant Resources, the
Company and its subsidiaries are entitled to be indemnified by Reliant Resources
for any losses arising out of the lawsuits described under "California Class
Actions and Attorney General Cases," "Long-Term Contract Class Action,"
"Washington and Oregon Class Actions," "Bustamante Price Reporting Class Action"
and "Trading and Marketing Activities," including attorneys' fees and other
costs. Pursuant to the indemnification obligation, Reliant Resources is
defending the Company and its subsidiaries to the extent named in these
lawsuits. The ultimate outcome of these matters cannot be predicted at this
time.

California Class Actions and Attorney General Cases. Reliant Energy,
Reliant Resources, Reliant Energy Services, Inc.(Reliant Energy Services),
Reliant Energy Power Generation, Inc. (REPG) and several other subsidiaries of
Reliant Resources, as well as two former officers and one present officer of
some of these companies, have been named as defendants in class action lawsuits
and other lawsuits filed against a number of companies that own generation
plants in California and other sellers of electricity in California markets.
While the plaintiffs allege various violations by the defendants of antitrust
laws and state laws against unfair and unlawful business practices, each of the
lawsuits is grounded on the central allegation that the defendants conspired to
drive up the wholesale price of electricity. In addition to injunctive relief,
the plaintiffs in these lawsuits seek treble the amount of damages alleged,
restitution of alleged overpayments, disgorgement of alleged unlawful profits
for sales of electricity, costs of suit and attorneys' fees. All of these suits
originally were filed in state courts in San Diego, San Francisco and Los
Angeles Counties. The suits in San Diego and Los Angeles Counties were
consolidated and removed to the federal district court in San Diego, but on
December 13, 2002, that court remanded the suits to the state courts. Prior to
the remand, Reliant Energy was voluntarily dismissed from two of the suits.
Several parties, including the Reliant defendants, have appealed the judge's
remand decision. The United States court of appeals has entered a briefing
schedule that could result in oral arguments by summer of 2003. Proceedings
before the state court are expected to resume during the first quarter of 2003.

In March and April 2002, the California Attorney General filed three
complaints, two in state court in San Francisco and one in the federal district
court in San Francisco, against Reliant Energy, Reliant Resources, Reliant
Energy Services and other subsidiaries of Reliant Resources alleging, among
other matters, violations by the defendants of state laws against unfair and
unlawful business practices arising out of transactions in the markets for
ancillary services run by the California independent systems operator, charging
unjust and unreasonable prices for electricity, in violation of antitrust laws
in connection with the acquisition in 1998 of electric generating facilities
located in California. The complaints variously seek restitution and
disgorgement of alleged unlawful profits for sales of electricity, civil
penalties and fines, injunctive relief against unfair competition, and undefined
equitable relief. Reliant Resources has removed the two state court cases to the
federal district court in San Francisco where all three cases are now pending.

Following the filing of the Attorney General cases, seven additional class
action cases were filed in state courts in Northern California. Each of these
purports to represent the same class of California ratepayers, assert the same
claims as asserted in the other California class action cases, and in some
instances repeat as well the allegations in the Attorney General cases. All of
these cases have been removed to federal district court in San Diego. Reliant
Resources has not filed an answer in any of these cases. The plaintiffs have
agreed to a stipulated order that would require the filing of a consolidated
complaint by early March 2003 and the filing of the defendants' initial response
to the complaint within 60 days after the consolidated complaint is
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filed. In all of these cases filed before the federal and state courts in
California, the Reliant defendants have filed or intend to file motions to
dismiss on grounds that the claims are barred by federal preemption and the
filed rate doctrine.

Long-Term Contract Class Action. In October 2002, a class action was filed
in state court in Los Angeles against Reliant Energy and several subsidiaries of
Reliant Resources. The complaint in this case repeats the allegations asserted
in the California class actions as well as the Attorney General cases and also
alleges misconduct related to long-term contracts purportedly entered into by
the California Department of Water Resources. None of the Reliant entities,
however, has a long-term contract with the Department of Water Resources. This
case has been removed to federal district court in San Diego.

Washington and Oregon Class Actions. In December 2002, a lawsuit was filed
in Circuit Court of the State of Oregon for the County of Multnomah on behalf of
a class of all Oregon purchasers of electricity and natural gas. Reliant Energy,
Reliant Resources and several Reliant Resources subsidiaries are named as
defendants, along with many other electricity generators and marketers. Like the
other lawsuits filed in California, the plaintiffs claim the defendants
manipulated wholesale power prices in violation of state and federal law. The
plaintiffs seek injunctive relief and payment of damages based on alleged
overcharges for electricity. Also in December 2002, a nearly identical lawsuit
on behalf of consumers in the State of Washington was filed in federal district
court in Seattle. Reliant Resources has removed the Oregon suit to federal
district court in Portland. It is anticipated that before answering the
lawsuits, the defendants will file motions to dismiss on the grounds that the
claims are barred by federal preemption and by the filed rate doctrine.

Bustamante Price Reporting Class Action. In November 2002, California
Lieutenant Governor Cruz Bustamante filed a lawsuit in state court in Los
Angeles on behalf of a class of purchasers of gas and power alleging violations
of state antitrust laws and state laws against unfair and unlawful business
practices based on an alleged conspiracy to report and publish false and
fraudulent natural gas prices with an intent to affect the market prices of
natural gas and electricity in California. Reliant Energy, Reliant Resources and
several Reliant Resources subsidiaries are named as defendants, along with other
market participants and publishers of some of the price indices. The complaint
seeks injunctive relief, compensatory and punitive damages, restitution of
alleged overpayment, disgorgement of all profits and funds acquired by the
alleged unlawful conduct, costs of suit and attorneys' fees. The parties have
stipulated to a schedule that would require the defendants to respond to the
complaint by March 31, 2003. The Reliant defendants intend to deny both their
alleged violation of any laws and their alleged participation in any conspiracy.

Trading and Marketing Activities. Reliant Energy has been named as a party
in several lawsuits and regulatory proceedings relating to the trading and
marketing activities of its former subsidiary, Reliant Resources.

In June 2002, the SEC advised Reliant Resources and Reliant Energy that it
had issued a formal order in connection with its investigation of Reliant
Resources' financial reporting, internal controls and related matters. The
Company understands that the investigation is focused on Reliant Resources'
same-day commodity trading transactions involving purchases and sales with the
same counterparty for the same volume at substantially the same price and
certain structured transactions. These matters were previously the subject of an
informal inquiry by the SEC. Reliant Resources and the Company are cooperating
with the SEC staff.

In connection with the Texas Utility Commission's industry-wide
investigation into potential manipulation of the ERCOT market on and after July
31, 2001, Reliant Energy and Reliant Resources have provided information to the
Texas Utility Commission concerning their scheduling and trading activities.

Fifteen class action lawsuits filed in May, June and July 2002 on behalf of
purchasers of securities of Reliant Resources and/or Reliant Energy have been
consolidated in federal district court in Houston. Reliant Resources and certain
of its executive officers are named as defendants. Reliant Energy is also named
as a
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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

defendant in seven of the lawsuits. Two of the lawsuits also name as defendants
the underwriters of the Reliant Resources Offering. One lawsuit names Reliant
Resources' and Reliant Energy's independent auditors as a defendant. The
consolidated amended complaint seeks monetary relief purportedly on behalf of
three classes: (1) purchasers of Reliant Energy common stock from February 3,
2000 to May 13, 2002; (2) purchasers of Reliant Resources common stock on the
open market from May 1, 2001 to May 13, 2002; and (3) purchasers of Reliant
Resources common stock in the Reliant Resources Offering or purchasers of shares
that are traceable to the Reliant Resources Offering. The plaintiffs allege,
among other things, that the defendants misrepresented their revenues and
trading volumes by engaging in round-trip trades and improperly accounted for
certain structured transactions as cash-flow hedges, which resulted in earnings
from these transactions being accounted for as future earnings rather than being
accounted for as earnings in fiscal year 2001.

In February 2003, a lawsuit was filed by three individuals in federal
district court in Chicago against CenterPoint Energy and certain former and
current officers of Reliant Resources for alleged violations of federal
securities laws. The plaintiffs in this lawsuit allege that the defendants
violated federal securities laws by issuing false and misleading statements to
the public, and that the defendants made false and misleading statements as part
of an alleged scheme to inflate artificially trading volumes and revenues. In
addition, the plaintiffs assert claims of fraudulent and negligent
misrepresentation and violations of Illinois consumer law. The defendants expect
to file a motion to transfer this lawsuit to the federal district court in
Houston and to consolidate this lawsuit with the consolidated lawsuits described
above.

The Company believes that none of these lawsuits has merit because, among
other reasons, the alleged misstatements and omissions were not material and did
not result in any damages to any of the plaintiffs.

In May 2002, three class action lawsuits were filed in federal district
court in Houston on behalf of participants in various employee benefits plans
sponsored by Reliant Energy. Reliant Energy and its directors are named as
defendants in all of the lawsuits. Two of the lawsuits have been dismissed
without prejudice. The remaining lawsuit alleges that the defendants breached
their fiduciary duties to various employee benefits plans, directly or
indirectly sponsored by Reliant Energy, in violation of the Employee Retirement
Income Security Act. The plaintiffs allege that the defendants permitted the
plans to purchase or hold securities issued by Reliant Energy when it was
imprudent to do so, including after the prices for such securities became
artificially inflated because of alleged securities fraud engaged in by the
defendants. The complaints seek monetary damages for losses suffered by a
putative class of plan participants whose accounts held Reliant Energy or
Reliant Resources securities, as well as equitable relief in the form of
restitution.

In October 2002, a derivative action was filed in the federal district
court in Houston, against the directors and officers of the Company. The
complaint sets forth claims for breach of fiduciary duty, waste of corporate
assets, abuse of control and gross mismanagement. Specifically, the shareholder
plaintiff alleges that the defendants caused the Company to overstate its
revenues through so-called "round trip" transactions. The plaintiff also alleges
breach of fiduciary duty in connection with the spin-off and the Reliant
Resources Offering. The complaint seeks monetary damages on behalf of the
Company as well as equitable relief in the form of a constructive trust on the
compensation paid to the defendants. The defendants have filed a motion to
dismiss this case on the ground that the plaintiff did not make an adequate
demand on the Company before filing suit.

A Special Litigation Committee appointed by the Company's board of
directors is investigating similar allegations made in a June 28, 2002 demand
letter sent on behalf of a Company shareholder. The letter states that the
shareholder and other shareholders are considering filing a derivative suit on
behalf of the Company and demands that the Company take several actions in
response to alleged round-trip trades occurring in 1999, 2000, and 2001. The
Special Litigation Committee is reviewing the demands made by the shareholder to
determine if these proposed actions are in the best interests of the Company.

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Reliant Energy Municipal Franchise Fee Lawsuits. In February 1996, the
cities of Wharton, Galveston and Pasadena filed suit, for themselves and a
proposed class of all similarly situated cities in Reliant Energy's electric
service area, against Reliant Energy and Houston Industries Finance, Inc.
(formerly a wholly owned subsidiary of Reliant Energy) alleging underpayment of
municipal franchise fees. The plaintiffs claim that they are entitled to 4% of
all receipts of any kind for business conducted within these cities over the
previous four decades. A jury trial of the original claimant cities (but not the
class of cities) in the 269th Judicial District Court for Harris County, Texas,
ended in April 2000 (the Three Cities case). Although the jury found for Reliant
Energy on many issues, it found in favor of the original claimant cities on
three issues, and assessed a total of $4 million in actual and $30 million in
punitive damages. However, the jury also found in favor of Reliant Energy on the
affirmative defense of laches, a defense similar to a statute of limitations
defense, due to the original claimant cities having unreasonably delayed
bringing their claims during the 43 years since the alleged wrongs began. The
trial court in the Three Cities case granted most of Reliant Energy's motions to
disregard the jury's findings. The trial court's rulings reduced the judgment to
$1.7 million, including interest, plus an award of $13.7 million in legal fees.
In addition, the trial court granted Reliant Energy's motion to decertify the
class. Following this ruling, 45 cities filed individual suits against Reliant
Energy in the District Court of Harris County.

On February 27, 2003, the state court of appeals in Houston rendered an
opinion reversing the judgment against the Company and rendering judgment that
the Three Cities take nothing by their claims. The court of appeals found that
the jury's finding of laches barred all of the Three Cities' claims and that the
Three Cities were not entitled to recovery of any attorneys' fees. The judgment
of the court of appeals is subject to motions for rehearing and an appeal to the
Texas Supreme Court.

The extent to which issues in the Three Cities case may affect the claims
of the other cities served by Reliant Energy cannot be assessed until judgments
are final and no longer subject to appeal. However, the court of appeals' ruling
appears to be consistent with Texas Supreme Court opinions. The Company
estimates the range of possible outcomes for recovery by the plaintiffs in the
Three Cities case to be between $-0- and $18 million inclusive of interest and
attorneys' fees.

Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the
Federal False Claims Act against RERC Corp. (now CERC Corp.) and certain of its
subsidiaries alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.

In addition, CERC Corp., CenterPoint Energy Gas Transmission Company,
CenterPoint Energy Field Services, Inc., and CenterPoint Energy-Mississippi
River Transmission Corporation are defendants in a class action filed in May
1999 against approximately 245 pipeline companies and their affiliates. The
plaintiffs in the case purport to represent a class of natural gas producers and
fee royalty owners who allege that they have been subject to systematic gas
mismeasurement by the defendants for more than 25 years. The plaintiffs seek
compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. The action is currently pending in state court in Stevens
County, Kansas. Motions to dismiss and class certification issues have been
briefed and argued.

City of Tyler, Texas, Gas Costs Review. By letter to CenterPoint Energy
Entex (Entex) dated July 31, 2002, the City of Tyler, Texas, forwarded various
computations of what it believes to be excessive costs ranging from $2.8 million
to $39.2 million for gas purchased by Entex for resale to residential and small
commercial customers in that city under supply agreements in effect since 1992.
Entex's gas costs for its Tyler
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system are recovered from customers pursuant to tariffs approved by the city and
filed with both the city and the Railroad Commission of Texas (the Railroad
Commission). Pursuant to an agreement, on January 29, 2003, Entex and the city
filed a Joint Petition for Review of Charges for Gas Sales (Joint Petition) with
the Railroad Commission. The Joint Petition requests that the Railroad
Commission determine whether Entex has properly and lawfully charged and
collected for gas service to its residential and commercial customers in its
Tyler distribution system for the period beginning November 1, 1992, and ending
October 31, 2002. The Company believes that all costs for Entex's Tyler
distribution system have been properly included and recovered from customers
pursuant to Entex's filed tariffs and that the city has no legal or factual
support for the statements made in its letter.

Gas Cost Recovery Suits. In October 2002, a suit was filed in state
district court in Wharton County, Texas against the Company, CERC, Entex Gas
Marketing Company, and others alleging fraud, violations of the Texas Deceptive
Trade Practices Act, violations of the Texas Utility Code, civil conspiracy and
violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek
class certification, but no class has been certified. The plaintiffs allege that
defendants inflated the prices charged to residential and small commercial
consumers of natural gas. In February 2003, a similar suit was filed against
CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class
of residential or business customers in Louisiana who allegedly have been
overcharged for gas or gas service provided by CERC. The plaintiffs in both
cases seek restitution for the alleged overcharges, exemplary damages and
penalties. The Company denies that CERC has overcharged any of its customers for
natural gas and believes that the amounts recovered for purchased gas have been
in accordance with what is permitted by state regulatory authorities.

Other Proceedings. The Company is involved in other proceedings before
various courts, regulatory commissions and governmental agencies regarding
matters arising in the ordinary course of business. The Company's management
currently believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.

Environmental Matters

Clean Air Standards. Based on current limitations of the Texas Commission
on Environmental Quality regarding NOx emissions in the Houston area, the
Company anticipates it will have invested at least $682 million for emission
control equipment through 2005, including $551 million expended from January 1,
1999 through December 31, 2002, with possible additional expenditures after
2005. NOx control estimates for 2006 and 2007 have not been finalized.

The Texas electric restructuring law provides for stranded cost recovery
for expenditures incurred before May 1, 2003 to achieve the NOx reduction
requirements. Incurred costs include costs for which contractual obligations
have been made. The Texas Utility Commission has determined that the Company's
emission control plan is the most effective control option and that up to $699
million is eligible for cost recovery, the exact amount to be determined in the
2004 true-up proceeding. In addition, the Company is required to provide $16.2
million in funding for certain NOx reduction projects associated with East Texas
pipeline companies. These funds are also eligible for cost recovery.

Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit
against REGT, Reliant Energy Pipeline Services, Inc., RERC Corp., Reliant Energy
Services, other Reliant Energy entities and third parties in the 1st Judicial
District Court, Caddo Parish, Louisiana. The petition has now been supplemented
seven times. As of November 21, 2002, there were 695 plaintiffs, a majority of
whom are Louisiana residents. In addition to the Reliant Energy entities, the
plaintiffs have sued the State of Louisiana through its Department of
Environmental Quality, several individuals, some of whom are present employees
of the State of Louisiana, the Bayou South Gas Gathering Company, L.L.C., Martin
Timber Company, Inc., and several trusts. Additionally on April 4, 2002, two
plaintiffs filed a separate suit with identical allegations against the same
parties in the same court. More recently, on January 6, 2003, two other
plaintiffs filed a third suit of
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similar allegations against the Company, as well as other defendants, in Bossier
Parish (26th Judicial District Court).

The suits allege that, at some unspecified date prior to 1985, the
defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox
Aquifer, which lies beneath property owned or leased by certain of the
defendants and which is the sole or primary drinking water aquifer in the area.
The primary source of the contamination is alleged by the plaintiffs to be a gas
processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo
Facility." This facility was purportedly used for gathering natural gas from
surrounding wells, separating gasoline and hydrocarbons from the natural gas for
marketing, and transmission of natural gas for distribution. This site was
originally leased and operated by predecessors of REGT in the late 1940s and was
operated until Arkansas Louisiana Gas Company ceased operations of the plant in
the late 1970s.

Beginning about 1985, the predecessors of certain Reliant Energy defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they own or lease. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or diminution of value of their
property, and, in addition, seek damages for trespass, punitive, and exemplary
damages. The quantity of monetary damages sought is unspecified. As of December
31, 2002, the Company is unable to estimate the monetary damages, if any, that
the plaintiffs may be awarded in these matters.

Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, remediation has been
completed on two sites, other than ongoing monitoring and water treatment. There
are five remaining sites in CERC's Minnesota service territory, two of which
CERC believes were neither owned or operated by CERC, and for which CERC
believes it has no liability.

At December 31, 2001 and 2002, CERC had accrued $23 million and $19
million, respectively, for remediation of the Minnesota sites. At December 31,
2002, the estimated range of possible remediation costs was $8 million to $44
million based on remediation continuing for 30 to 50 years. The cost estimates
are based on studies of a site or industry average costs for remediation of
sites of similar size. The actual remediation costs will be dependent upon the
number of sites to be remediated, the participation of other potentially
responsible parties (PRP), if any, and the remediation methods used. CERC has an
environmental expense tracker mechanism in its rates in Minnesota. CERC has
collected $12 million at December 31, 2002 to be used for future environmental
remediation.

CERC has received notices from the United States Environmental Protection
Agency and others regarding its status as a PRP for other sites. Based on
current information, the Company has not been able to quantify a range of
environmental expenditures for potential remediation expenditures with respect
to other MGP sites.

Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at these sites. It is possible that
other contaminated sites may exist and that remediation costs may be incurred
for these sites. Although the total amount of these costs cannot be known at
this time, based on experience by the Company and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, the Company believes that the costs of any remediation of these
sites will not be material to the Company's financial condition, results of
operations or cash flows.

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Other Environmental. From time to time the Company has received notices
from regulatory authorities or others regarding its status as a PRP in
connection with sites found to require remediation due to the presence of
environmental contaminants. In addition, the Company has been named as a
defendant in litigation related to such sites and in recent years has been
named, along with numerous others, as a defendant in several lawsuits filed by a
large number of individuals who claim injury due to exposure to asbestos while
working at sites along the Texas Gulf Coast. Most of these claimants have been
workers who participated in construction of various industrial facilities,
including power plants, and some of the claimants have worked at locations owned
by the Company. The Company anticipates that additional claims like those
received may be asserted in the future and intends to continue vigorously
contesting claims which it does not consider to have merit. Although their
ultimate outcome cannot be predicted at this time, the Company does not believe,
based on its experience to date, that these matters, either individually or in
the aggregate, will have a material adverse effect on the Company's financial
condition, results of operations or cash flows.

Department of Transportation

In December 2002, Congress enacted the Pipeline Safety Improvement Act of
2002. This legislation applies to the Company's interstate pipelines as well as
its intra-state pipelines and local distribution companies. The legislation
imposes several requirements related to ensuring pipeline safety and integrity.
It requires companies to assess the integrity of their pipeline transmission and
distribution facilities in areas of high population concentration and further
requires companies to perform remediation activities, in accordance with the
requirements of the legislation, over a 10-year period.

In January 2003, the U.S. Department of Transportation published a notice
of proposed rulemaking to implement provisions of the legislation. The
Department of Transportation is expected to issue final rules by the end of
2003.

While the Company anticipates that increased capital and operating expenses
will be required to comply with the requirements of the legislation, it will not
be able to quantify the level of spending required until the Department of
Transportation's final rules are issued.

Other Matters

The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.

(d) OPERATIONS AGREEMENT WITH CITY OF SAN ANTONIO

Texas Genco has a joint operating agreement with the City Public Service
Board of San Antonio (CPS) to share savings from the joint dispatching of each
party's generating assets. Dispatching the two generating systems jointly
results in savings of fuel and related expenses because there is a more
efficient utilization of each party's lowest cost resources. The two parties
equally share the savings resulting from joint dispatch. The agreement
terminates in 2009.

(e) NUCLEAR INSURANCE

Texas Genco 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

132

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.

Pursuant to the Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $9.3 billion as of December 31, 2002. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. Texas Genco and the other owners of the
South Texas Project currently maintain the required nuclear liability insurance
and participate in the industry retrospective rating plan.

There can be no assurance that all potential losses or liabilities will be
insurable, or that the amount of insurance will be sufficient to cover them. Any
substantial losses not covered by insurance would have a material effect on the
Company's financial condition, results of operations and cash flows.

(f) NUCLEAR DECOMMISSIONING

Texas Genco contributed $14.8 million per year in 2000 and 2001 to trusts
established to fund its share of the decommissioning costs for the South Texas
Project. In 2002, Texas Genco contributed $2.9 million to these trusts. There
are various investment restrictions imposed upon Texas Genco by the Texas
Utility Commission and the NRC relating to Texas Genco's nuclear decommissioning
trusts. Additionally, Texas Genco's board of directors and CenterPoint Energy's
board of directors have each appointed two members to the Nuclear
Decommissioning Trust Investment Committee which establishes the investment
policy of the trusts and oversees the investment of the trusts' assets. The
securities held by the trusts for decommissioning costs had an estimated fair
value of $163 million as of December 31, 2002, of which approximately 49% were
fixed-rate debt securities and the remaining 51% were equity securities. For a
discussion of the accounting treatment for the securities held in the nuclear
decommissioning trust, see Note 3(k). In July 1999, an outside consultant
estimated Texas Genco's portion of decommissioning costs to be approximately
$363 million. While the funding levels currently exceed minimum NRC
requirements, no assurance can be given that the amounts held in trust will be
adequate to cover the actual decommissioning costs of the South Texas Project.
Such costs may vary because of changes in the assumed date of decommissioning
and changes in regulatory requirements, technology and costs of labor, materials
and equipment. Pursuant to the Texas electric restructuring law, costs
associated with nuclear decommissioning that have not been recovered as of
January 1, 2002, will continue to be subject to cost-of-service rate regulation
and will be included in a charge to transmission and distribution customers.
CenterPoint Energy is contractually obligated to indemnify Texas Genco from and
against any obligations relating to the decommissioning not otherwise satisfied
through collections by CenterPoint Houston. For information regarding the effect
of the business separation plan on funding of the nuclear decommissioning trust
fund, see Note 4(b).

(14) ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

The fair values of cash and cash equivalents, investments in debt and
equity securities classified as "available-for-sale" and "trading" in accordance
with SFAS No. 115, and short-term borrowings are estimated to be approximately
equivalent to carrying amounts and have been excluded from the table below. The
fair values of non-trading derivative assets and liabilities are recognized in
the Consolidated Balance

133

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Sheets at December 31, 2001 and 2002 (see Note 5). Therefore, these financial
instruments are stated at fair value and are excluded from the table below.

(15) EARNINGS PER SHARE

The following table reconciles numerators and denominators of the Company's
basic and diluted earnings per share (EPS) calculations:

134

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Options to purchase 442,385, 2,074,437 and 9,709,272 shares were outstanding
for the years ended December 31, 2000, 2001 and 2002, respectively, but were
not included in the computation of diluted EPS because the options' exercise
price was greater than the average market price of the common shares for the
respective years.

(16) UNAUDITED QUARTERLY INFORMATION

The consolidated financial statements have been prepared to reflect the
effect of the Reliant Resources Distribution as described above on the
CenterPoint Energy financial statements. The consolidated financial statements
present the Reliant Resources businesses (previously reported as the Wholesale
Energy, European Energy and Retail Energy business segments and related
corporate costs) as discontinued operations, in accordance with SFAS No. 144.
Accordingly, the consolidated financial statements reflect these operations as
discontinued operations for each of the three years in the period ended December
31, 2002.

135

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Summarized quarterly financial data is as follows:

136

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Quarterly earnings per common share are based on the weighted average number
of shares outstanding during the quarter, and the sum of the quarters may
not equal annual earnings per common share.

(17) REPORTABLE BUSINESS SEGMENTS

The Company's determination of reportable business segments considers the
strategic operating units under which the Company manages sales, allocates
resources and assesses performance of various products and services to wholesale
or retail customers in differing regulatory environments. The accounting
policies of the business segments are the same as those described in the summary
of significant accounting policies except that some executive benefit costs have
not been allocated to business segments. Effective with the deregulation of the
Texas electric industry beginning January 1, 2002, the basis of business segment
reporting has changed for the Company's electric operations. The Texas
generation operations of CenterPoint Energy's former integrated electric
utility, Reliant Energy HL&P, are now a separate reportable business segment,
Electric Generation, whereas they previously had been part of the Electric
Operations business segment. The remaining transmission and distribution
function is now reported separately in the Electric Transmission & Distribution
business segment In 2001, Latin America was a separate business segment, but
beginning in 2002 is reported in the Other Operations business segment.
Reportable business segments for all prior periods presented have been restated
to conform to the 2002 presentation. Reportable business segments presented
herein do not include Wholesale Energy, European Energy, Retail Energy and
related corporate costs as these

137

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

business segments operated within Reliant Resources which is presented as
discontinued operations within these consolidated financial statements. Note
that certain estimates and allocations have been used to separate historical,
(pre-January 1, 2002) Electric Generation business segment data from the
Electric Transmission & Distribution segment data.

Beginning in the first quarter of 2002, the Company began to evaluate
business segment performance on an earnings (loss) before interest expense,
distribution on trust preferred securities, income taxes, extraordinary item and
cumulative effect of accounting change (EBIT) basis. Prior to 2002, the Company
evaluated performance based upon operating income. EBIT, as defined, is shown
because it is a measure we use to evaluate the performance of our business
segments and the Company believes it is a measure of financial performance that
may be used as a means to analyze and compare companies on the basis of
operating performance. The Company expects that some analysts and investors will
want to review EBIT when evaluating the Company. EBIT is not defined under
accounting principles generally accepted in the United States of America (GAAP),
should not be considered in isolation or as a substitute for a measure of
performance prepared in accordance with GAAP and is not indicative of operating
income from operations as determined under GAAP. Additionally, the Company's
computation of EBIT may not be comparable to other similarly titled measures
computed by other companies, because all companies do not calculate it in the
same fashion.

Long-lived assets include net property, plant and equipment, net goodwill
and other intangibles and equity investments in unconsolidated subsidiaries. The
Company accounts for intersegment sales as if the sales were to third parties,
that is, at current market prices.

The Company has identified the following reportable business segments:
Electric Transmission & Distribution, Electric Generation, Natural Gas
Distribution, Pipelines and Gathering and Other Operations. For a description of
the financial reporting business segments, see Note 1. Financial data for
business segments, products and services and geographic areas are as follows:

138

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

(1) Sales to Reliant Resources represented approximately $940 million of
CenterPoint Houston's transmission and distribution revenues since
deregulation began in 2002.

(2) Sales to Reliant Resources represented approximately 66% of Texas Genco's
total revenues in 2002.

139

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

140

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(18) GUARANTOR DISCLOSURES

CenterPoint Energy Gas Resources Corp., CenterPoint Energy Gas Marketing
Company and other wholly owned subsidiaries of CERC Corp. provide comprehensive
natural gas sales and services to industrial and commercial customers who are
primarily located within or near the territories served by the Company's
pipelines and distribution subsidiaries. In order to hedge their exposure to
natural gas prices, these CERC Corp. subsidiaries have entered standard purchase
and sale agreements with various counterparties. CenterPoint Energy and CERC
Corp. have guaranteed the payment obligations of these subsidiaries under
certain of these agreements, typically for one-year terms. As of December 31,
2002, CenterPoint Energy had delivered 14 such guarantees with an aggregate
maximum potential exposure of $133.5 million and an aggregate carrying amount of
$12.1 million. As of December 31, 2002, CERC Corp. had delivered 43 such
guarantees with an aggregate maximum potential exposure of $410 million and an
aggregate carrying amount of $53.7 million.

As part of its normal business operations, Texas Genco, LP, a wholly owned
indirect subsidiary of Texas Genco, has also entered into power purchase and
sale agreements to buy less expensive power than Texas Genco's marginal cost of
generation or to sell power to another party who is willing to pay more than
Texas Genco's marginal cost of generation. Texas Genco has guaranteed the
payment obligations of Texas Genco, LP under certain of these agreements,
typically for a one-year term. As of December 31, 2002, Texas Genco had
delivered 7 such guarantees with an aggregate maximum potential exposure of
$28.2 million and an aggregate carrying amount of $-0-.

CenterPoint Energy has delivered guarantees in support of Texas Genco's
obligations to ERCOT under qualified scheduling entity and transmission
congestion rights agreements. These guarantees expire in October, 2003 and as of
December 31, 2002, have an aggregate maximum potential exposure of $45 million
and an aggregate carrying amount of $-0-.

CenterPoint Energy has delivered a guarantee in favor of the Tennessee
Board for Licensing Contractors to support the contracting activities of
CenterPoint Energy Pipeline Services, Inc. in Tennessee. The term of this
guarantee runs with the two-year license granted by the Tennessee Board and
provides for a maximum potential exposure of $15 million.

CenterPoint Energy has entered standard indemnification agreements with
various surety companies to support the issuance of surety bonds on behalf of
CenterPoint Energy and its subsidiaries. These indemnification agreements vary
in duration to coincide with the term of the bonds issued. As of December 31,
2002, these agreements covered surety bonds in the aggregate amount of $14.5
million. In addition, CenterPoint Energy has provided $8.9 million in cash
deposits to secure its indemnity to one surety company.

141

INDEPENDENT AUDITORS' REPORT

To the Board of Directors and Shareholders of CenterPoint Energy, Inc. and
Subsidiaries:

We have audited the accompanying consolidated balance sheets of CenterPoint
Energy, Inc. and its subsidiaries (the Company) as of December 31, 2001 and
2002, and the related consolidated statements of income, shareholders' equity,
comprehensive income and cash flows for each of the three years in the period
ended December 31, 2002. Our audits also included the financial statement
schedules listed in the Index at Item 15(a)(2). These financial statements and
the financial statement schedules are the responsibility of the Company's
management. Our responsibility is to express an opinion on these financial
statements and the financial statement schedules based on our audits.

We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2001 and 2002, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2002 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedules, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.

As discussed in Note 2 to the consolidated financial statements, the
Company distributed its 83% ownership interest in Reliant Resources, Inc. on
September 30, 2002. The loss on distribution and the results of operations for
Reliant Resources, Inc. for periods prior to the distribution are included in
discontinued operations of the accompanying consolidated financial statements.

As discussed in Note 3(d) to the consolidated financial statements, on
January 1, 2002, the Company changed its method of accounting for goodwill and
certain intangible assets to conform to Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets."

DELOITTE & TOUCHE LLP

Houston, Texas
February 28, 2003

142

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
FINANCIAL DISCLOSURE

None.

PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS

The information called for by Item 10, to the extent not set forth in
"Executive Officers" in Item 1, is or will be set forth in the definitive proxy
statement relating to CenterPoint Energy's 2003 annual meeting of shareholders
pursuant to SEC Regulation 14A. Such definitive proxy statement relates to a
meeting of shareholders involving the election of directors and the portions
thereof called for by Item 10 are incorporated herein by reference pursuant to
Instruction G to Form 10-K.

ITEM 11. EXECUTIVE COMPENSATION

The information called for by Item 11 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 11 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
RELATED STOCKHOLDER MATTERS

The information called for by Item 12 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 12 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

The information called for by Item 13 is or will be set forth in the
definitive proxy statement relating to CenterPoint Energy's 2003 annual meeting
of shareholders pursuant to SEC Regulation 14A. Such definitive proxy statement
relates to a meeting of shareholders involving the election of directors and the
portions thereof called for by Item 13 are incorporated herein by reference
pursuant to Instruction G to Form 10-K.

PART IV

ITEM 14. CONTROLS AND PROCEDURES

Within the 90 days prior to the date of this report, we carried out an
evaluation, under the supervision and with the participation of our management,
including our Chief Executive Officer and Chief Financial Officer, of the
effectiveness of the design and operation of our disclosure controls and
procedures pursuant to Rule 13a-14 of the Securities Exchange Act of 1934. Based
on that evaluation, the Chief Executive Officer and the Chief Financial Officer
concluded that our disclosure controls and procedures are effective in timely
alerting them to material information relating to us (including our consolidated
subsidiaries) required to be included in our periodic SEC filings. Subsequent to
the date of their evaluation, there were no significant changes in our internal
controls or in other factors that could significantly affect the internal
controls, including any corrective actions with regard to significant
deficiencies and material weaknesses.

143

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a)(1) Financial Statements.
Statements of Consolidated Operations for the Three Years
Ended December 31, 2002................................ 77
Statements of Consolidated Comprehensive Income for the
Three Years Ended December 31, 2002.................... 78
Consolidated Balance Sheets at December 31, 2002 and
2001................................................... 79
Statements of Consolidated Cash Flows for the Three Years
Ended December 31, 2002................................ 80
Statements of Consolidated Shareholders' Equity for the
Three Years Ended December 31, 2002.................... 81
Notes to Consolidated Financial Statements................ 82
Independent Auditors' Report.............................. 142
(a)(2) Financial Statement Schedules for the Three Years
Ended December 31, 2002.
I -- Financial Statements of CenterPoint Energy, Inc. .... 146
II -- Reserves............................................ 152

The following schedules are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements:

III, IV and V.

(a)(3) Exhibits.

See Index of Exhibits on page 156, which index also includes the management
contracts or compensatory plans or arrangements required to be filed as exhibits
to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

(g) Reports on Form 8-K.

On October 1, 2002, we filed a Current Report on Form 8-K dated September
30, 2002, announcing that our board of directors had declared a distribution of
all of the shares of Reliant Resources, Inc. common stock owned by us to our
common shareholders on a pro rata basis. The distribution was completed on
September 30, 2002 to our shareholders of record as of the close of business on
September 20, 2002.

On October 11, 2002, we filed a Current Report on Form 8-K dated October
11, 2002, to announce that we had negotiated new, one-year credit facilities
totaling $4.7 billion to replace similar facilities that expired on October 10,
2002.

On October 17, 2002, we filed a Current Report on Form 8-K dated October
17, 2002, relating to the announcement of third quarter 2002 results.

On November 8, 2002, we filed a Current Report on Form 8-K dated November
8, 2002, to announce that we had negotiated a new $1.31 billion senior secured
credit facility at CenterPoint Energy Houston Electric, LLC.

On December 6, 2002, we filed a Current Report on Form 8-K dated December
5, 2002, to announce that our board of directors had declared a stock
distribution of approximately 19% of the 80,000,000 outstanding shares of common
stock of our wholly owned subsidiary, Texas Genco Holdings, Inc., to our
shareholders to be made on January 6, 2003.

On December 12, 2002, we filed a Current Report of Form 8-K dated December
11, 2002, to announce that the Securities and Exchange Commission had declared
Texas Genco's Form 10 registration statement relating to its common stock
effective under the Securities Exchange Act of 1934. Payment of the distribution
had been conditional upon the Securities and Exchange Commission declaring the
Form 10 registration statement effective.

144

On December 23, 2002, we filed a Current Report on Form 8-K dated December
20, 2002, to announce that our board of directors had established the
distribution ratio for the previously declared pro rata distribution of
approximately 19% of the 80,000,000 outstanding shares of Texas Genco common
stock to our shareholders to be made on January 6, 2003.

On January 7, 2003, we filed a Current Report on Form 8-K dated January 6,
2003, announcing that we had distributed approximately 19% of the 80 million
outstanding shares of Texas Genco common stock to our shareholders of record as
of the close of business on December 20, 2002.

On February 13, 2003, we filed a Current Report on Form 8-K dated February
13, 2003, relating to the announcement of fourth quarter 2002 and year-end 2002
results.

On March 3, 2003, we filed a Current Report on Form 8-K dated February 28,
2003, announcing that we had amended and extended our $3.85 billion credit
facility from October 2003 to June 30, 2005.

145

CENTERPOINT ENERGY, INC.

SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC.
STATEMENT OF OPERATIONS

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
146

CENTERPOINT ENERGY, INC.

SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC.
BALANCE SHEETS

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements
in Part II, Item 8

147

CENTERPOINT ENERGY, INC.

SCHEDULE I -- FINANCIAL STATEMENTS OF CENTERPOINT ENERGY, INC.
STATEMENT OF CASH FLOWS

See CenterPoint Energy, Inc. and Subsidiaries Notes to Consolidated Financial
Statements in Part II, Item 8
148

CENTERPOINT ENERGY, INC.

SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS

(1) The condensed parent company financial statements and notes should be
read in conjunction with the consolidated financial statements and notes of
CenterPoint Energy, Inc. (CenterPoint Energy) appearing in the Annual Report on
Form 10-K. CenterPoint Energy, Inc. is a public utility holding company that
became the parent of Reliant Energy, Incorporated (Reliant Energy) and its
subsidiaries on August 31, 2002 as part of a corporate restructuring of Reliant
Energy (the Restructuring). We are a registered public utility holding company
under the 1935 Act. Prior to the Restructuring, Reliant Energy was a public
utility holding company that was exempt from registration under the 1935 Act.
After the Restructuring, an exemption was no longer available for the corporate
structure that the Texas Utility Commission required us to adopt under the Texas
electric restructuring law. CenterPoint Energy did not conduct any activities
other than those incident to its formation until September 1, 2002. Accordingly,
statements of operations and cash flows would not provide meaningful information
and have been omitted for periods prior to September 1, 2002.

(2) As a registered public utility holding company, CenterPoint Energy and
its subsidiaries are subject to a comprehensive regulatory scheme imposed by the
SEC in order to protect customers, investors and the public interest. Although
the SEC does not regulate rates and charges under the 1935 Act, it does regulate
the structure, financing, lines of business and internal transactions of public
utility holding companies and their system companies. In order to obtain
financing, acquire additional public utility assets or stock, or engage in other
significant transactions, CenterPoint Energy is required to obtain approval from
the SEC under the 1935 Act.

Prior to the Restructuring, CenterPoint Energy and Reliant Energy obtained
an order from the SEC that authorized the Restructuring transactions, including
the Reliant Resources Distribution, and granted it certain authority with
respect to system financing, dividends and other matters. The financing
authority granted by that order will expire on June 30, 2003, and CenterPoint
Energy must obtain a further order from the SEC under the 1935 Act, primarily
related to its financing activities subsequent to June 30, 2003.

In the July 2002 order, the SEC limited the aggregate amount of external
borrowings of Texas Genco, CenterPoint Houston and CERC to $500 million, $3.55
billion and $2.7 billion, respectively. In addition, the order restricts
CenterPoint Energy's ability to pay dividends out of capital accounts to the
extent current or retained earnings are insufficient for those dividends. Under
these restrictions, CenterPoint Energy, Texas Genco, CenterPoint Houston and
CERC are permitted to pay dividends in excess of the respective current or
retained earnings in an amount up to $200 million, $100 million, $200 million
and $100 million, respectively.

(3) Effective with the Restructuring, all outstanding shares of Reliant
Energy no par value common stock were exchanged for shares of CenterPoint Energy
common stock with a par value of $0.01 per share. The capital accounts of
CenterPoint Energy have been restated as of December 31, 2000 and 2001 to give
effect to the change in par value per share. CenterPoint Energy has
1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000
shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value
preferred stock.

(4) On September 30, 2002, CenterPoint Energy distributed to its
shareholders 240 million shares of Reliant Resources common stock, which
represented CenterPoint Energy's approximately 83% ownership interest in Reliant
Resources, by means of a tax-free spin-off in the form of a dividend. Holders of
CenterPoint Energy common stock on the record date received 0.788603 shares of
Reliant Resources common stock for each share of CenterPoint Energy stock that
they owned on the record date. The total value of the Reliant Resources
Distribution, after the impairment charge discussed below, was $847 million.

As a result of the spin-off of Reliant Resources, CenterPoint Energy
recorded a non-cash loss on disposal of discontinued operations of $4.4 billion
in 2002. This loss represents the excess of the carrying value of CenterPoint
Energy's net investment in Reliant Resources over the market value of Reliant
Resources' common stock. CenterPoint Energy's financial statements reflect the
reclassifications necessary to present Reliant Resources as discontinued
operations for all periods shown. Through the date of the spin-off, Reliant

149

CENTERPOINT ENERGY, INC.

SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

Resources' assets and liabilities are shown in CenterPoint Energy's Consolidated
Balance Sheets as current and non-current assets and liabilities of discontinued
operations.

(5) CenterPoint Energy distributed approximately 19% of the 80 million
outstanding shares of common stock of Texas Genco to its shareholders on January
6, 2003. As a result of the distribution of Texas Genco common stock,
CenterPoint Energy recorded a pre-tax impairment charge of $396 million, which
will be reflected as a regulatory asset in the Consolidated Balance Sheet in the
first quarter of 2003. This impairment charge represents the excess of the
carrying value of CenterPoint Energy's net investment in Texas Genco over the
market value of Texas Genco's common stock. Additionally, in connection with the
distribution, CenterPoint Energy will record minority interest ownership in
Texas Genco of $146 million in its Consolidated Balance Sheet in the first
quarter of 2003.

(6) On February 28, 2003, the Company reached agreement with a syndicate of
banks on a second amendment to its $3.85 billion bank facility (the "Second
Amendment"). Under the Second Amendment, the maturity date of the bank facility
was extended from October 2003 to June 30, 2005, and the $1.2 billion in
mandatory prepayments that would have been required this year (including $600
million due on February 28, 2003) were eliminated. The facility consists of a
$2.35 billion term loan and a $1.5 billion revolver. Borrowings bear interest
based on LIBOR rates under a pricing grid tied to the Company's credit rating.
At our current credit ratings, the pricing for loans remains the same. The drawn
cost for the facility at our current ratings is LIBOR plus 450 basis points. The
Company has agreed to pay the banks an extension fee of 75 basis points on the
amounts outstanding under the bank facility on October 9, 2003. The Company also
paid $41 million in fees that were due on February 28, 2003, along with $20
million in fees that had been due on June 30, 2003.

In addition, the interest rates will be increased by 25 basis points
beginning May 28, 2003 if the Company does not grant the banks a security
interest in our 81% stock ownership of Texas Genco. Granting the security
interest in the stock of Texas Genco requires approval from the SEC under the
1935 Act, which is currently being sought. That security interest would be
released when the Company sells Texas Genco, which is expected to occur in 2004.
Proceeds from the sale will be used to reduce the bank facility.

Also under the Second Amendment, on or before May 28, 2003, the Company
expects to grant to the banks warrants to purchase up to 10%, on a fully diluted
basis, of its common stock at a price equal to the greater of $6.56 per share or
110% of the closing price on the New York Stock Exchange on the date the
warrants are issued. The warrants would not be exercisable for a year after
issuance but would remain outstanding for four years; provided, that if the
Company reduces the bank facility during 2003 by specified amounts, some or all
of the warrants (or the related rights to equivalent cash compensation) will be
extinguished. To the extent that the Company reduces the bank facility by up to
$400 million on or before May 28, 2003, up to half of the warrants will be
extinguished on a basis proportionate to the reduction in the credit facility.
To the extent such warrants are not extinguished on or before May 28, 2003, they
will vest and become exercisable in accordance with their terms. Whether or not
the Company is able to extinguish warrants on or before May 28, 2003, the
remaining 50% of the warrants will be extinguished, again on a proportionate
basis, if the Company reduces the bank facility by up to $400 million by the end
of 2003. The Company plans to eliminate the warrants entirely before they vest
by accessing the capital markets to fund the total payments of $800 million
during 2003; however, because of current financial market conditions and
uncertainties regarding such conditions over the balance of the year, there can
be no assurance that the Company will be able to extinguish the warrants or to
do so on favorable terms.

The warrants and the underlying common stock would be registered with the
SEC and could be exercised either through the payment of the purchase price or
on a "cashless" basis under which the Company would issue a number of shares
equal to the difference between the then-current market price and the warrant
exercise price. Issuance of the warrants is also subject to obtaining SEC
approval under the 1935 Act, which is currently being sought. If that approval
is not obtained on or before May 28, 2003, the Company will provide

150

CENTERPOINT ENERGY, INC.

SCHEDULE I -- NOTES TO CONDENSED FINANCIAL STATEMENTS -- (CONTINUED)

the banks equivalent cash compensation over the term that its warrants would
have been exercisable to the extent they are not otherwise extinguished.

In the Second Amendment, the Company also agreed that its quarterly common
stock dividend will not exceed $0.10 per share. If the Company has not reduced
the bank facility by a total of at least $400 million by the end of 2003, of
which at least $200 million has come from the issuance of capital stock or
securities linked to capital stock (such as convertible debt), the maximum
dividend payable during 2004 and for the balance of the term of the facility is
subject to an additional test. Under that test the maximum permitted quarterly
dividend will be the lesser of (i) $0.10 per share or (ii) 12.5% of the
Company's net income per share for the 12 months ended on the last day of the
previous quarter.

The Second Amendment provides that proceeds from capital stock or
indebtedness issued or incurred by the Company must be applied (subject to a
$200 million basket for CERC and its subsidiaries and another $250 million
basket for borrowings by the Company and its other subsidiaries and other
limited exceptions) to repay bank loans and reduce the bank facility. Similarly,
cash proceeds from the sale of assets of more than $30 million or, if less, a
group of sales aggregating more than $100 million, must be applied to repay bank
loans and reduce the bank facility, except that proceeds of up to $120 million
can be reinvested in the Company's businesses.

151

CENTERPOINT ENERGY, INC.

SCHEDULE II -- RESERVES
FOR THE THREE YEARS ENDED DECEMBER 31, 2002
(IN THOUSANDS)

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

(1) Deductions from reserves represent losses or expenses for which the
respective reserves were created. In the case of the uncollectible accounts
reserve, such deductions are net of recoveries of amounts previously written
off.

152

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the 10th day of March, 2003.

CENTERPOINT ENERGY, INC.
(Registrant)

By: /s/ DAVID M. MCCLANAHAN
------------------------------------
David M. McClanahan,
President and Chief Executive
Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 10, 2003.

153

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this annual report on Form 10-K of CenterPoint
Energy, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this quarterly report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 10, 2003

By: /s/ DAVID M. MCCLANAHAN
-----------------------------------------------------------
David M. McClanahan
President and Chief Executive Officer

154

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this annual report on Form 10-K of CenterPoint
Energy, Inc.;

2. Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact
necessary to make the statements made, in light of the circumstances
under which such statements were made, not misleading with respect to
the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all
material respects the financial condition, results of operations and
cash flows of the registrant as of, and for, the periods presented in
this annual report;

4. The registrant's other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as
defined in Exchange Act Rules 13a-14 and 15d-14) for the registrant
and we have:

a) designed such disclosure controls and procedures to ensure that
material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this
annual report is being prepared;

b) evaluated the effectiveness of the registrant's disclosure
controls and procedures as of a date within 90 days prior to the
filing date of this annual report (the "Evaluation Date"); and

c) presented in this annual report our conclusions about the
effectiveness of the disclosure controls and procedures based on
our evaluation as of the Evaluation Date;

5. The registrant's other certifying officers and I have disclosed,
based on our most recent evaluation, to the registrant's auditors and
the audit committee of registrant's board of directors (or persons
performing the equivalent function):

a) all significant deficiencies in the design or operation of
internal controls which could adversely affect the registrant's
ability to record, process, summarize and report financial data
and have identified for the registrant's auditors any material
weaknesses in internal controls; and

b) any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrant's
internal controls; and

6. The registrant's other certifying officers and I have indicated in
this annual report whether or not there were significant changes in
internal controls or in other factors that could significantly affect
internal controls subsequent to the date of our most recent
evaluation, including any corrective actions with regard to
significant deficiencies and material weaknesses.

Date: March 10, 2003

By: /s/ GARY L. WHITLOCK
-----------------------------------------------------------
Gary L. Whitlock
Executive Vice President and
Chief Financial Officer

155

CENTERPOINT ENERGY, INC.

EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
FOR FISCAL YEAR ENDED DECEMBER 31, 2002

INDEX OF EXHIBITS

Exhibits not incorporated by reference to a prior filing are designated by
a cross (+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated. Exhibits designated by an asterisk (*) are
management contracts or compensatory plans or arrangements required to be filed
as exhibits to this Form 10-K by Item 601(b)(10)(iii) of Regulation S-K.

156

157

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy
has not filed as exhibits to this Form 10-K certain long-term debt instruments,
including indentures, under which the total amount of securities authorized do
not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on
a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any
such instrument to the SEC upon request.

158

159

160

161

162

163

164

165