EXHIBIT 99.1

ITEM 1. BUSINESS

REGULATION

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

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

As a registered public utility holding company, we, along with our
subsidiaries except Texas Genco, 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 required to
obtain approval from the SEC under the 1935 Act.

We received an order from the SEC under the 1935 Act on June 30, 2003 and
supplemental orders thereafter relating to our financing activities and those of
our regulated subsidiaries, as well as other matters. The orders are effective
until June 30, 2005. As of December 31, 2003, the orders generally permitted us
and our subsidiaries to issue securities to refinance indebtedness outstanding
at June 30, 2003, and authorized us and our subsidiaries to issue certain
incremental external debt securities and common and preferred stock through June
30, 2005, without prior authorization from the SEC. The orders also contain
certain requirements regarding ratings of our securities, interest rates,
maturities, issuance expenses and use of proceeds. The orders require that
CenterPoint Houston and CERC maintain a ratio of common equity to total
capitalization of at least 30%. The SEC has acknowledged that prior to the
monetization of Texas Genco and the securitization of the true-up components,
our common equity as a percentage of total capitalization is expected to remain
less than 30%. In addition, after the securitization, our common equity as a
percentage of total capitalization, including securitized debt, is expected to
be less than 30%, which the SEC has permitted for other companies.

In October 2003, the FERC granted exempt wholesale generator status to
Texas Genco, LP, a wholly owned subsidiary of Texas Genco that owns and operates
our electric generating plants. As a result of the FERC's actions, Texas Genco,
LP is exempt from all provisions of the 1935 Act as long as it remains an exempt
wholesale generator and Texas Genco is no longer a public utility holding
company within the meaning of the 1935 Act.

Pursuant to requirements of the orders, we formed a service company,
CenterPoint Energy Service Company, LLC (Service Company), that began operation
as of January 1, 2004, to provide certain corporate and shared services to our
subsidiaries. Those services are provided pursuant to service arrangements that
are in a form prescribed by the SEC. Services are provided by the Service
Company at cost and are subject to oversight and periodic audit from the SEC.

FEDERAL ENERGY REGULATORY COMMISSION

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

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.

On November 25, 2003, the FERC issued Order No. 2004, the final rule
modifying the Standards of Conduct applicable to electric and natural gas
transmission providers, governing the relationship between regulated
transmission providers and certain of their affiliates. The rule significantly
changes and expands the regulatory burdens of the Standards of Conduct and
applies essentially the same standards to jurisdictional electric transmission
providers and natural gas pipelines. On February 9, 2004, our natural gas
pipeline subsidiaries filed Implementation Plans required under the new rule.
Those subsidiaries are further required to post their Implementation Procedures
on their websites by June 1, 2004, and to be in compliance with the requirements
of the new rule by that date.

CenterPoint Houston is not a "public utility" under the Federal Power Act
and therefore is not generally regulated by the FERC, although certain of its
transactions are subject to limited FERC jurisdiction. Texas Genco makes
electric sales wholly within ERCOT and, as a result, its rates are not subject
to regulation as a "public utility" under the Federal Power Act.

STATE AND LOCAL REGULATION

Electric Transmission and Distribution. 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, typically having a
term of forty years, from the incorporated municipalities in its service
territory. These franchises give CenterPoint Houston the right to construct,
operate and maintain 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 in exchange for
payment of a fee. The franchise for the City of Houston is scheduled to expire
in 2007.

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 for residential customers are based on amounts of energy delivered
whereas distribution rates for a majority of commercial and industrial customers
are based on peak demand. 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, though
franchises in Arkansas are perpetual. None of CERC's material franchises expire
in the near term. CERC expects 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 by its local
distribution divisions are subject to traditional cost-of-service regulation at
rates regulated by the relevant state public utility commissions and, in Texas,
by the Railroad Commission of Texas (Railroad Commission) and municipalities
CERC serves.

In August 2002, a settlement was approved by the APSC that resulted in an
increase in the base rate and service charge revenues of Arkla of approximately
$27 million annually. In addition, the APSC approved a gas
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main replacement surcharge that provided $2 million of additional revenue in
2003 and is expected to provide additional amounts in subsequent years. In
December 2002, a settlement was approved by the Oklahoma Corporation Commission
that resulted in an increase in the base rate and service charge revenues of
Arkla of approximately $6 million annually. In November 2003, Arkla filed a
request with the Louisiana Public Service Commission (LPSC) for a $16 million
increase to its base rate and service charge revenues in Louisiana. The case is
expected to be resolved in mid-2004.

In December 2003, a settlement was approved by the City of Houston that
will result in an increase in the base rate and service charge revenues of Entex
of approximately $7 million annually. Entex has submitted these settlement rates
to the 28 other cities within its Houston Division and the Railroad Commission
of Texas for consideration and approval. If all regulatory approvals are
received from these 29 jurisdictions, Entex's base rate and service charge
revenues are expected to increase by approximately $7 million annually in
addition to the $7 million discussed above. On February 10, 2004, a settlement
was approved by the LPSC that is expected to result in an increase in Entex's
base rate and service charge revenues of approximately $2 million annually.

Our gas distribution divisions generally recover the cost of gas provided
to customers through gas cost adjustment mechanisms prescribed in their tariffs
that are approved by the appropriate regulatory authority. Recently, our Arkla
and Entex divisions have been involved in both litigation and regulatory
proceedings in which parties have challenged the gas costs that have been
recovered from customers. In response to a claim by the City of Tyler, Texas
that excessive costs, ranging from $2.8 million to $39.2 million, may have been
incurred for gas purchased by Entex for resale to residential and small
commercial customers, Entex and the City of Tyler have requested 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. Similarly, a complaint has been filed with the LPSC by a
private party alleging that certain gas costs recovered from Entex customers in
Louisiana were excessive and/or were not properly authorized by the LPSC.
Additionally, certain private litigants have filed suit in Louisiana state
courts, alleging that inappropriate or excessive gas costs have been recovered
from Arkla's customers.

NUCLEAR REGULATORY COMMISSION

Texas Genco is subject to regulation by the United States Nuclear
Regulatory Commission (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 nuclear
decommissioning trusts. The beneficial ownership of the nuclear decommissioning
trusts is held by Texas Genco, as a licensee of the facility. While current
funding levels exceed NRC minimum requirements, no assurance can be given that
the amounts held in trust will be adequate to cover the actual decommissioning
costs of the South Texas Project. Such costs may vary because of changes in the
assumed date of decommissioning and changes in regulatory requirements,
technology and costs of labor, materials and waste burial. In the event that
funds from the 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.

DEPARTMENT OF TRANSPORTATION

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

In December 2003, the Department of Transportation Office of Pipeline
Safety issued the final regulations to implement the Act. These regulations
became effective on February 14, 2004. These regulations provided guidance on,
among other things, the areas that should be classified as HCA.

Our Pipelines and Gathering business segment and our natural gas
distribution companies anticipate that compliance with the new regulations will
require increases in both capital and operating cost. The level of expenditures
required to comply with these regulations will be dependent on several factors,
including the age of the facility, the pressures at which the facility operates
and the number of facilities deemed to be located in areas designated as HCA.
Based on our interpretation of the rules and preliminary technical reviews, we
anticipate compliance will require average annual expenditures of approximately
$15 to $20 million during the initial 10-year period.

ENVIRONMENTAL MATTERS

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

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

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

- noise emissions from our facilities; and

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

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

- construct or acquire new equipment;

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

- modify or replace existing and proposed equipment; and

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

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

Under the federal Comprehensive Environmental Response, Compensation and
Liability Act of 1980 (CERCLA), owners and operators of facilities from which
there has been a release or threatened release of

hazardous substances, together with those who have transported or arranged for
the disposal of those substances, are liable for:

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

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

AIR EMISSIONS

As part of the 1990 amendments to the Federal Clean Air Act, requirements
and schedules for compliance were developed for attainment of health-based
standards. In furtherance of the Act's requirements, standards for NOx
emissions, a product of the combustion process associated with power generation,
have been finalized by the Texas Commission on Environmental Quality (TCEQ).
These TCEQ standards, as well as provisions of the Texas electric restructuring
law, require substantial reductions in NOx emissions from electric generating
units. Texas Genco is currently installing cost-effective controls at its
generating plants to comply with these requirements. As of December 31, 2003,
Texas Genco has invested $664 million for NOx emissions controls and is planning
to make expenditures of $131 million for the remainder of 2004 through 2007.
Further revisions to these NOx standards may result from the TCEQ's future
rules, expected by 2007, implementing more stringent federal eight-hour ozone
standards.

In 1998, the United States became a signatory to the United Nations
Framework Convention on Climate Change (Kyoto Protocol). The Kyoto Protocol
calls for developed nations to reduce their emissions of greenhouse gases.
Carbon dioxide, which is a major byproduct of the combustion of fossil fuel, is
considered to be a greenhouse gas. In 2002, President Bush withdrew the United
States' support for the Kyoto Protocol while endorsing voluntary greenhouse gas
reduction measures. Congress has also explored a number of other alternatives
for regulating domestic greenhouse gas emissions. If the country re-enters and
the United States Senate ultimately ratifies the Kyoto Protocol and/or if the
United States Congress adopts other measures for the control of greenhouse
gases, any resulting limitations on power plant carbon dioxide emissions could
have a material adverse impact on all fossil fuel-fired electric generating
facilities, including those belonging to Texas Genco.

In July 2002, the White House sent to the United States Congress a Bill
proposing the Clear Skies Act, which is designed to achieve long-term reductions
of multiple pollutants produced from fossil fuel-fired power plants. If enacted,
the Clear Skies Act would target reductions averaging 70% for sulfur dioxide
(SO(2)), NOx and mercury emissions and would create a gradually imposed
market-based compliance program that would come into effect initially in 2008
with full compliance required by 2018. Fossil fuel-fired power plants owned by
companies such as Texas Genco would be affected by the adoption of this program,
or other legislation currently pending in Congress addressing similar issues. To
comply with such programs, we and other regulated entities could pursue a
variety of strategies, including the installation of pollution controls,
purchase of emission allowances, or the curtailment of operations. To date,
Congress has taken little action to enact the Clear Skies Act.

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

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

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

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

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

WATER

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

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

NUCLEAR WASTE

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

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 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.

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among some of the defendants in lawsuits filed beginning in August 2001 in Caddo
Parish and Bossier Parish, Louisiana. 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," which was formerly operated by a
predecessor in interest of CERC Corp. 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.

Beginning about 1985, the predecessors of certain CERC Corp. defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they owned or leased. 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. 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 nor operated by CERC, and for which CERC
believes it has no liability.

At December 31, 2003, CERC had accrued $19 million for remediation of
certain Minnesota sites. At December 31, 2003, the estimated range of possible
remediation costs for these sites 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 utilized an environmental
expense tracker mechanism in its rates in Minnesota to recover estimated costs
in excess of insurance recovery. CERC has collected or accrued $12.5 million as
of December 31, 2003 to be used for environmental remediation.

CERC has received notices from the United States Environmental Protection
Agency and others regarding its status as a PRP for other sites. CERC has been
named as a defendant in lawsuits under which contribution is sought for the cost
to remediate former MGP sites based on the previous ownership of such sites by
former affiliates of CERC or its divisions. We are investigating details
regarding these sites and the range of environmental expenditures for potential
remediation. Based on current information, we have not been able to quantify a
range of environmental expenditures for such sites.

Mercury Contamination. Our 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 us at some sites in the past, and we have
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
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
costs of any remediation of these sites will not be material to our financial
condition, results of operations or cash flows.

Other Environmental. From time to time, we have received notices from
regulatory authorities or others regarding our status as a PRP in connection
with sites found to require remediation due to the presence of environmental
contaminants. 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 condition, results of operations or cash flows.

RISK FACTORS

PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES

RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS

CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN RECOVERING THE FULL VALUE OF ITS
TRUE-UP COMPONENTS.

CenterPoint Houston expects to make a filing on March 31, 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 following costs or true-up
components:

- "stranded costs," which consist of the positive excess of the regulatory
net book value of generation assets, as defined, over the market value of
the assets;

- the difference between the Texas Utility Commission's projected market
prices for generation during 2002 and 2003 and the actual market prices
for generation as determined in the state-mandated capacity auctions
during that period;

- the Texas jurisdictional amount reported by the previously vertically
integrated electric utilities as generation-related regulatory assets and
liabilities (offset and adjusted by specified amounts) in their audited
financial statements for 1998;

- final fuel over- or under-recovery; less

- "price to beat" clawback components.

CenterPoint Houston will be required to establish and support the amounts
it seeks to recover in the 2004 True-Up Proceeding. CenterPoint Houston expects
these amounts to be substantial. Third parties will have the opportunity and are
expected to challenge CenterPoint Houston's calculation of these amounts. To the
extent recovery of a portion of these amounts is denied or if we agree to forego
recovery of a portion of the request under a settlement agreement, CenterPoint
Houston would be unable to recover those amounts in the future. Additionally, in
October 2003, a group of intervenors filed a petition asking the Texas Utility
Commission to open a rulemaking proceeding and reconsider certain aspects of its
true-up rules. In November 2003, the Texas Utility Commission voted to deny the
petition. Despite the denial of the petition, we expect that issues could be
raised in the 2004 True-Up Proceeding regarding our compliance with the Texas
Utility Commission's rules regarding ECOM recovery, including whether Texas
Genco has auctioned all capacity it is required to auction in view of the fact
that some capacity has failed to sell in the state-mandated auctions. We believe
Texas Genco has complied with the requirements under the applicable rules,
including re-offering the unsold capacity in subsequent auctions. If events were
to occur during the 2004 True-Up Proceeding that made the recovery of the ECOM
true-up regulatory asset no longer probable, we would write off the
unrecoverable balance of such asset as a charge against earnings.

In the event CenterPoint Houston has not begun to recover the amounts
established in the 2004 True-Up Proceeding prior to its $1.3 billion term loan
maturity date in November 2005, CenterPoint Houston's ability to repay or
refinance this term loan may be adversely affected.

The Texas Utility Commission's ruling that the 2004 True-Up Proceeding
filing will be made on March 31, 2004 means that the calculation of the market
value of a share of Texas Genco common stock for purposes of the Texas Utility
Commission's stranded cost determination will be based on market prices during
the 120 trading days ending on March 30, 2004 plus a control premium, if any, up
to a maximum of 10%. If Texas Genco is sold to a third party at a lower price
than the market value used by the Texas Utility Commission, CenterPoint Houston
would be unable to recover the difference.

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 43 retail electric providers. Adverse economic
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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 on a timely basis. Any delay or default in
payment could adversely affect CenterPoint Houston's cash flows, financial
condition and results of operations. Reliant Resources, through its
subsidiaries, is CenterPoint Houston's largest customer. Approximately 70% of
CenterPoint Houston's $83 million in billed receivables from retail electric
providers at December 31, 2003 was owed by subsidiaries of Reliant Resources.
Pursuant to the Texas electric restructuring law, Reliant Resources will be
obligated to make a "price to beat" clawback payment to CenterPoint Houston in
2004 which is currently estimated by Reliant Resources to be $175 million.
CenterPoint Houston's financial condition may be adversely affected if Reliant
Resources is unable to meet these obligations.

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 that 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.

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 customers of the retail electric providers.
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 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 such 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.

RISK FACTORS AFFECTING 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 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 coal and

lignite fueled generating stations and its interest in the South Texas Project
nuclear generating station. 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.

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 exceeds peak demand (reserve
margin) in the ERCOT market has exceeded 30% since 2001, and the Texas Utility
Commission and the ERCOT Independent System Operator (ISO) have forecasted the
reserve margin for 2004 to continue to exceed 30%. The commencement of
commercial operation of new power generation facilities in the ERCOT market has
increased and will continue to increase the competitiveness of the wholesale
power market, which could have a material adverse effect on 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 has sold entitlements to a significant portion of its available
2004 and 2005 generating capacity in its capacity auctions held to date.
Although Texas Genco's obligation to conduct contractually-

mandated auctions terminated in January 2004, it currently remains obligated to
sell 15% of its installed generation capacity and related ancillary services
pursuant to state-mandated auctions and it expects to conduct future capacity
auctions with respect to all or part of its remaining capacity from time to
time. In these auctions, Texas Genco sold 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, an
unexpected outage at one of Texas Genco's lower-cost facilities could require it
to run one of its higher-cost plants or obtain replacement power from third
parties in the open market in order to satisfy its obligations even though the
energy payments for the dispatched power are based on the cost of its lower-cost
facilities.

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,

- 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 increased costs of operations and reduced
earnings.

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

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 CenterPoint Houston and 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 for 2004 is organized into five
congestion zones. Transmission congestion between the zones could impair Texas
Genco's ability to schedule power for transmission across zonal boundaries,
which are defined by the ERCOT ISO, thereby inhibiting Texas Genco's efforts to
match its facility scheduled outputs with its customer scheduled requirements.
In addition, power generators participating in the ERCOT market could be liable
for congestion costs associated with transferring power between zones.

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. Texas
Genco sells firm entitlements to capacity and ancillary services. Therefore, any
disruption in the delivery of fuel could prevent Texas Genco from operating its
facilities, or force Texas Genco to enter into alternative arrangements at
higher than prevailing market prices, to meet its auction commitments, which
could adversely affect its results of operations, financial condition and cash
flows.

TO DATE, TEXAS GENCO HAS SOLD A SUBSTANTIAL PORTION OF ITS CAPACITY
ENTITLEMENTS TO SUBSIDIARIES OF RELIANT RESOURCES. ACCORDINGLY, TEXAS GENCO'S
RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY
AFFECTED IF RELIANT RESOURCES CEASES TO BE A MAJOR CUSTOMER OR FAILS TO MEET
ITS OBLIGATIONS.

By participating in Texas Genco's contractually-mandated auctions,
subsidiaries of Reliant Resources have purchased entitlements to 79% of Texas
Genco's sold 2004 capacity and 68% of Texas Genco's sold 2005 capacity. Reliant
Resources has made these purchases either through the exercise of its
contractual rights to purchase 50% of the entitlements Texas Genco auctioned in
its prior contractually-mandated auctions or through the submission of bids. In
the event Reliant Resources ceases to be a major customer or fails to meet its
obligations to Texas Genco, Texas Genco's results of operations, financial
condition and cash flows could be adversely affected. As of December 31, 2003,
Reliant Resources' securities ratings are below investment grade. Texas Genco
has been granted a security interest in accounts receivable and/or
securitization notes associated with the accounts receivable of certain
subsidiaries of Reliant Resources to secure up to $250 million in purchase
obligations.

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:

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

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

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

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

TEXAS GENCO'S OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION, INCLUDING
ENVIRONMENTAL REGULATION. IF TEXAS GENCO FAILS TO COMPLY WITH APPLICABLE
REGULATIONS OR TO 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.

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 or with any other regulatory requirements that
apply to its operations, it could be subject to administrative, civil and/or
criminal liability and fines, and regulatory agencies 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.

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 were to occur, 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 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.

TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

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

RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING
BUSINESSES

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

CERC's rates for natural gas distribution are regulated by certain
municipalities and state commissions based on an analysis of its invested
capital and its expenses incurred in a test year. Thus, the rates that CERC is
allowed to charge may not match its expenses at any given time. While rate
regulation is, generally, premised on providing a reasonable opportunity to
recover reasonable and necessary operating expenses and to earn a reasonable
return on invested capital, there can be no assurance that the municipalities
and state commissions will judge all of CERC'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 CERC's costs.

CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND ITS
PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE
TRANSPORTATION AND STORAGE OF NATURAL GAS.

CERC competes primarily with alternate energy sources such as electricity
and other fuel sources. In some areas, intrastate pipelines, other natural 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.

CERC's two interstate pipelines and its 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.

CERC'S NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL
GAS PRICING LEVELS.

CERC is subject to risk associated with price movements of natural gas.
Movements in 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 consumption in CERC's service territory.
Additionally, increasing gas prices could create the need for CERC to provide
collateral in order to purchase gas.

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.

IF CERC WERE TO FAIL TO EXTEND CONTRACTS WITH TWO OF ITS SIGNIFICANT PIPELINE
CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS.

Contracts with two of our significant pipeline customers, CenterPoint
Energy Arkla and Laclede Gas Company, 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, there could be an adverse
effect on CERC's results of operations, financial condition and cash flows.

CERC'S INTERSTATE PIPELINES' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO
FLUCTUATIONS IN THE SUPPLY OF GAS.

CERC's 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 substantial 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.

RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION

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 of December 31, 2003, we had $11.0 billion of outstanding indebtedness
on a consolidated basis. Approximately $3.5 billion principal amount of this
debt must be paid through 2006, excluding principal repayments of approximately
$142 million on transition bonds. In addition, the capital constraints and other
factors 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, adversely affect our financial condition and results of operations
or severely restrict or prohibit distributions from our subsidiaries. The
success of our future financing efforts may depend, at least in part, on:

- our ability to recover the true-up components and to monetize our
investment in Texas Genco;

- 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;

- 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.

Our capital structure and liquidity will be significantly impacted in the
2004/2005 period by our ability to recover the true-up components through the
regulatory process beginning in March 2004. To the extent our recovery is denied
or materially reduced, our liquidity and financial condition will be materially
adversely affected.
16

As of March 1, 2004, our CenterPoint Houston subsidiary has $3.2 billion
principal amount of general mortgage bonds outstanding and $382 million of first
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 $400 million of additional first mortgage bonds
and general mortgage bonds could be issued on the basis of retired bonds and 70%
of property additions as of December 31, 2003, CenterPoint Houston has agreed
under the $1.3 billion collateralized term loan maturing in 2005 to not issue,
subject to certain exceptions, more than $200 million of incremental secured or
unsecured debt. In addition, CenterPoint Houston is 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 Part II 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 MEET OUR PAYMENT OBLIGATIONS, 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. In general, these subsidiaries are separate and distinct legal
entities and have no obligation to provide us with funds for our payment
obligations, whether by dividends, distributions, loans or otherwise. 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.

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.

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

As of December 31, 2003, we had $2.8 billion of outstanding floating-rate
debt owed to third parties. The interest rate spreads on such debt are
substantially above our historical interest rate spreads. 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. An increase in
short-term interest rates could result in higher interest costs and could
adversely affect our results of operations, financial condition and cash flows.

OTHER RISKS

WE AND CENTERPOINT HOUSTON COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES
AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS.

Under some circumstances, we and CenterPoint Houston could incur
liabilities associated with assets and businesses we and CenterPoint Houston no
longer own. These assets and businesses were previously owned by Reliant Energy
directly or through subsidiaries and include:

- those transferred to Reliant Resources or its subsidiaries in connection
with the organization and capitalization of Reliant Resources prior to
its initial public offering in 2001,

- those transferred to Texas Genco in connection with its organization and
capitalization, and

- those transferred to us and CenterPoint Houston in connection with the
August 2002 restructuring of Reliant Energy.

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, us and our subsidiaries, including CenterPoint
Houston, 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 current and historical businesses 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 in circumstances in
which Reliant Energy has not been released from the liability in connection with
the transfer, we or CenterPoint Houston could be responsible for satisfying the
liability.

Reliant Resources reported in its Annual Report on Form 10-K for the year
ended December 31, 2003 that as of December 31, 2003 it had $6.1 billion of
total debt and its unsecured debt ratings are currently below investment grade.
If Reliant Resources were 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.

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 liability of Reliant
Energy as a controlling shareholder of Reliant Resources. We or CenterPoint
Houston could incur liability if claims in one or more of these lawsuits were
successfully asserted against us or CenterPoint Houston and indemnification from
Reliant Resources were determined to be unavailable or if Reliant Resources were
unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco,
Texas Genco assumed liabilities associated with the electric generation assets
Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and
cause the applicable transferee subsidiaries to indemnify, us and our
subsidiaries, including CenterPoint Houston, with respect to liabilities
associated with the transferred assets and businesses. In many cases the
liabilities assumed were held by CenterPoint Houston and CenterPoint Houston was
not released by third parties from these liabilities. The indemnity provisions
were intended generally to place sole financial responsibility on Texas Genco
and its subsidiaries for all liabilities associated with the current and
historical businesses and operations of Texas Genco, regardless of the time
those liabilities arose. If Texas Genco were unable to satisfy a liability that
had been so assumed or indemnified against, and provided Reliant Energy had not
been released from the liability in connection with the transfer, CenterPoint
Houston could be responsible for satisfying the liability.

WE MAY NOT BE ABLE TO MONETIZE TEXAS GENCO ON TERMS WE FIND ACCEPTABLE.

On January 23, 2004, Reliant Resources announced that it would not exercise
its option to purchase the common stock of Texas Genco that we own. We will
continue to operate Texas Genco's facilities and are pursuing an alternative
strategy to monetize Texas Genco, and we have engaged a financial advisor to
assist us in that pursuit. We may not be able to monetize our interest in Texas
Genco under any alternative strategy on terms we find acceptable. In addition,
delays in monetization may increase the risk that the value of the ownership
interest used in the stranded cost determination, which is to be based on market
prices for Texas Genco common stock during the 120 trading days ending on March
30, 2004, will be higher than the proceeds received in the monetization process.

WE, TOGETHER WITH OUR SUBSIDIARIES, EXCLUDING TEXAS GENCO, ARE SUBJECT TO
REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS
IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES.

We and our subsidiaries, excluding Texas Genco, are subject to regulation
by the SEC under the 1935 Act. The 1935 Act, among other things, limits the
ability of a holding company and its regulated subsidiaries to issue debt and
equity securities without prior authorization, restricts the source of dividend
payments to current and retained earnings without prior authorization, regulates
sales and acquisitions of certain assets and businesses and governs affiliate
transactions.

We received an order from the SEC under the 1935 Act on June 30, 2003
relating to our financing activities, which is effective until June 30, 2005. We
must seek a new order before the expiration date. Although authorized levels of
financing, together with current levels of liquidity, are believed to be
adequate during the period the order is effective, unforeseen events could
result in capital needs in excess of authorized amounts, necessitating further
authorization from the SEC. Approval of filings under the 1935 Act can take
extended periods.

If as a result of the 2004 True-Up Proceeding or any other event we are
required to take a charge against our net income, our current earnings could be
reduced below the level which would enable us to pay the quarterly dividend on
our common stock under our current SEC financing order. We expect to file an
application with the SEC under the 1935 Act requesting an order authorizing us,
in the event that we are required to take such a charge against our net income,
to pay quarterly dividends out of capital or unearned surplus.

In addition, we would be required under the 1935 Act to obtain approval
from the SEC to issue and sell securities for purposes of funding Texas Genco's
operations or to guarantee a security of Texas Genco, except in emergency
situations (in which we could provide funding pursuant to applicable SEC rules).
Our failure to obtain approvals under the 1935 Act in a timely manner could
adversely affect our and our subsidiaries' results of operations, financial
condition and cash flows.

The United States Congress is currently considering legislation that has a
provision that would repeal the 1935 Act. We cannot predict at this time whether
this legislation or any variation thereof will be adopted or, if adopted, the
effect of any such law on our business.

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

damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Under the federal Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $10.6 billion as of December 31, 2003. Owners
are required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. 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 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 any of its transmission and distribution properties without
negative impact on its results of operations, financial condition and cash
flows.

ITEM 3. LEGAL PROCEEDINGS

For a brief description of certain legal and regulatory proceedings
affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of
this report and Notes 4 and 12 to our consolidated financial statements, which
information is incorporated herein by reference.

In addition to the matters incorporated herein by reference, the following
matters that we previously reported have been resolved:

In August and October 2003, class action lawsuits were filed against
CenterPoint Houston and Reliant Energy Services in federal court in New York on
behalf of purchasers of natural gas futures contracts on the New York Mercantile
Exchange. A third, similar class action was filed in the same court in November
2003. The complaints alleged that the defendants manipulated the price of
natural gas through their gas trading activities and price reporting practices
in violation of the Commodity Exchange Act during the period January 1, 2000
through December 31, 2002. The plaintiffs sought damages based on the effect of
such alleged manipulation on the value of the gas futures contracts they bought
or sold. In January 2004, the plaintiffs voluntarily dismissed CenterPoint
Houston from these lawsuits.

During 2003, we and Texas Genco were engaged in a dispute with Northwestern
Resources Co. (NWR), the supplier of fuel to the Limestone electric generation
facility, over the terms and pricing at which NWR supplies fuel to that facility
under a 1999 settlement agreement between the parties and under ancillary
obligations. Both sides to the dispute initiated lawsuits, but in January 2004,
NWR and Texas Genco reached a settlement under which they agreed to dismiss
those lawsuits and under which NWR would continue to provide certain quantities
of lignite at specified prices during the period from 2004 through 2007, after
which time the pricing would revert to pricing provided for under the 1999
settlement.

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

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 or be affected by numerous
factors including:

- the timing and outcome of the regulatory process leading to the
determination and recovery of the true-up components and the
securitization of these amounts;

- the timing and results of the monetization of our interest in Texas
Genco;

- 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:

- allowed rates of return;

- rate structures;

- recovery of investments; and

- operation and construction of facilities;

- termination of accruals of ECOM true-up after 2003;

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

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

- changes in interest rates or rates of inflation;

- weather variations and other natural phenomena;

- the timing and extent of changes in the supply of natural gas;

- 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;

- inability of various counterparties to meet their obligations to us;

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

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

- the ability of Reliant Resources to satisfy its obligations to us,
including indemnity obligations and obligations to pay the "price to
beat" clawback; and

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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(2) SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(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:

<Table>
<Caption>
DECEMBER 31,
ESTIMATED USEFUL -----------------
LIVES (YEARS) 2002 2003
---------------- ------- -------
(IN MILLIONS)

Electric transmission & distribution............... 5-75 $ 5,960 $ 6,085
Electric generation................................ 5-60 9,610 9,436
Natural gas distribution........................... 5-50 2,151 2,316
Pipelines and gathering............................ 5-75 1,686 1,722
Other property..................................... 3-40 446 446
------- -------
Total............................................ 19,853 20,005
Accumulated depreciation and amortization.......... (7,738) (8,194)
------- -------
Property, plant and equipment, net............ $12,115 $11,811
======= =======
</Table>

For further information regarding removal costs previously recorded as a
component of accumulated depreciation, see Note 2(n).

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.

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 (in millions, except per share amounts):

<Table>
<Caption>
YEAR ENDED
DECEMBER 31,
2001
------------

Reported income from continuing operations before cumulative
effect of accounting change............................... $ 499
Add: Goodwill amortization, net of tax...................... 49
-----
Adjusted income from continuing operations before cumulative
effect of accounting change............................... $ 548
=====
Basic Earnings Per Share:
Reported income from continuing operations before cumulative
effect of accounting change............................... $1.72
Add: Goodwill amortization, net of tax...................... 0.17
-----
Adjusted income from continuing operations before cumulative
effect of accounting change............................... $1.89
=====
Diluted Earnings Per Share:
Reported income from continuing operations before cumulative
effect of accounting change............................... $1.71
Add: Goodwill amortization, net of tax...................... 0.17
-----
Adjusted income from continuing operations before cumulative
effect of accounting change............................... $1.88
=====
</Table>

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

<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2003
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)

Land Use Rights............................ $61 $(12) $61 $(14)
Other...................................... 19 (2) 38 (5)
--- ---- --- ----
Total.................................... $80 $(14) $99 $(19)
=== ==== === ====
</Table>

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, 2003. 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.

Amortization expense for other intangibles for 2001, 2002 and 2003 was $1
million, $2 million and $4 million, respectively. Estimated amortization expense
for the five succeeding fiscal years is as follows (in millions):

<Table>

2004........................................................ $ 5
2005........................................................ 3
2006........................................................ 2
2007........................................................ 2
2008........................................................ 2
---
Total..................................................... $14
===
</Table>

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

<Table>
<Caption>
DECEMBER 31,
2002 AND 2003
-------------

Natural Gas Distribution.................................... $1,085
Pipelines and Gathering..................................... 601
Other Operations............................................ 55
------
Total..................................................... $1,741
======
</Table>

The Company completed its review during the second quarter of 2003 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.

The Company has engaged a financial advisor to assist in exploring
alternatives for monetizing its 81% interest in Texas Genco, including possible
sale of its ownership interest in Texas Genco. As a result of the Company's
intention to monetize its interest in Texas Genco, the Company performed an
impairment analysis of Texas Genco's assets as of December 31, 2003 in
accordance with the provisions of SFAS No. 144. As of December 31, 2003 no
impairment had been indicated. The fair value of Texas Genco's assets could be
materially affected by a change in the estimated future cash flows for these
assets. Future cash flows for Texas Genco are estimated using a
probability-weighted approach based on the fair value of its common stock,
operating projections and estimates of how long these assets will be retained.
Changes in any of these assumptions could result in an impairment charge.

(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.

The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2002 and 2003:

<Table>
<Caption>
DECEMBER 31,
---------------
2002 2003
------ ------
(IN MILLIONS)

Recoverable Electric Generation-Related Regulatory Assets,
net:
Recoverable electric generation plant mitigation....... $2,051 $2,116
Excess mitigation liability............................ (969) (778)
------ ------
Net electric generation plant mitigation asset.... 1,082 1,338
Excess cost over market (ECOM/capacity auction)
true-up............................................... 697 1,357
Texas Genco distribution/impairment.................... -- 399
Regulatory tax asset................................... 175 119
Final fuel under/(over) recovery balance............... 64 (98)
Other 2004 True-Up Proceeding items.................... 53 119
------ ------
Total Recoverable Electric Generation-Related
Regulatory Assets................................... 2,071 3,234
Securitized regulatory asset................................ 706 682
Unamortized loss on reacquired debt......................... 58 80
Estimated removal costs..................................... -- (647)
Other long-term regulatory assets/liabilities............... 38 38
------ ------
Total..................................................... $2,873 $3,387
====== ======
</Table>

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. Because estimates of the fair value of Texas Genco are
required, the financial impacts of the Texas electric restructuring law with
respect to the final determination of stranded costs 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. See
Note 4 for additional discussion of regulatory assets.

(4) REGULATORY MATTERS

(a) TRUE-UP COMPONENTS AND SECURITIZATION

The Texas Electric Restructuring Law. In June 1999, the Texas legislature
adopted the Texas Electric Choice Plan (the Texas electric restructuring law),
which substantially amended the regulatory structure governing electric
utilities in order to allow and encourage retail competition which began in
January 2002. The Texas electric restructuring law required the separation of
the generation, transmission and distribution, and retail sales functions of
electric utilities into three different units. Under the law, neither the
generation function nor the retail function is subject to traditional cost of
service regulation, and the generation and the retail function are each operated
on a competitive basis.

The transmission and distribution function that CenterPoint Houston
performs remains subject to traditional utility rate regulation. CenterPoint
Houston recovers the cost of its service through an energy delivery charge
approved by the Texas Utility Commission. As a result of these changes, there
are no meaningful comparisons for the Electric Transmission & Distribution and
Electric Generation business segments prior to 2002 when retail sales became
fully competitive.

Under the Texas electric restructuring law, transmission and distribution
utilities in Texas, such as CenterPoint Houston, whose generation assets were
"unbundled" may recover, following a regulatory

proceeding to be held in 2004 (2004 True-Up Proceeding) as further discussed
below in "-- 2004 True-Up Proceeding":

- "stranded costs," which consist of the positive excess of the regulatory
net book value of generation assets, as defined, over the market value of
the assets, taking specified factors into account;

- final fuel over- or under-recovery; less

- "price to beat" clawback components.

The Texas electric restructuring law permits transmission and distribution
utilities to recover the true-up components through transition charges on retail
electric customers' bills, to the extent that such components are established in
certain regulatory proceedings. These transition charges are non-bypassable,
meaning that they must be paid by essentially all customers and cannot, except
in limited circumstances, be avoided by switching to self-generation. The law
also authorizes the Texas Utility Commission to permit those utilities to issue
transition bonds based on the securitization of revenues associated with the
transition charges. CenterPoint Houston recovered a portion of its regulatory
assets in 2001 through the issuance of transition bonds. For a further
discussion of these matters, see "-- Securitization" below.

The Texas electric restructuring law also provides specific regulatory
remedies to reduce or mitigate a utility's stranded cost exposure. 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. CenterPoint Houston undertook
both of these remedies provided in the Texas electric restructuring law, but in
a rate order issued in October 2001, the Texas Utility Commission required
CenterPoint Houston to reverse those actions. For a further discussion of these
matters, see "-- Mitigation" below.

2004 True-Up Proceeding. In 2004, the Texas Utility Commission will
conduct true-up proceedings for investor-owned utilities. The purpose of the
true-up proceeding is to quantify and reconcile the amount of the true-up
components. The true-up proceeding will result in either additional charges
being assessed on, or credits being issued to, retail electric customers.
CenterPoint Houston expects to make the filing to initiate its final true-up
proceeding on March 31, 2004. The Texas electric restructuring law requires a
final order to be issued by the Texas Utility Commission not more than 150 days
after a proper filing is made by the regulated utility, although under its rules
the Texas Utility Commission can extend the 150-day deadline for good cause. Any
delay in the final order date will result in a delay in the securitization of
CenterPoint Houston's true-up components and the implementation of the
non-bypassable charges described above, and could delay the recovery of carrying
costs on the true-up components determined by the Texas Utility Commission.

Following adoption of the true-up rule by the Texas Utility Commission in
2001, CenterPoint Houston appealed the provisions of the rule that permitted
interest to be recovered on stranded costs only from the date of the Texas
Utility Commission's final order in the 2004 True-Up Proceeding, instead of from
January 1,
25

2002 as CenterPoint Houston contends is required by law. On January 30, 2004,
the Texas Supreme Court granted CenterPoint Houston's petition for review of the
true-up rule. Oral arguments were heard on February 18, 2004. The decision by
the Court is pending. The Company has not accrued interest income on stranded
costs in its consolidated financial statements, but estimates such interest
income would be material to the Company's consolidated financial statements.

Stranded Cost Component. CenterPoint Houston will be entitled to recover
stranded costs through a transition charge to its customers if the regulatory
net book value of generating plant assets exceeds the market value of those
assets. 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), any above-market purchased power contracts and
certain other amounts. 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 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. If Texas
Genco is sold to a third party at a lower price than the market value used by
the Texas Utility Commission, CenterPoint Houston would be unable to recover the
difference.

ECOM True-Up Component. The Texas Utility Commission used a computer model
or projection, called an excess cost over market (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 2002 and 2003. Any difference between the Texas Utility Commission's
projected market prices for generation during 2002 and 2003 and the actual
market prices for generation as determined in the state-mandated capacity
auctions during that period will be a component of the 2004 True-Up Proceeding.
In accordance with the Texas Utility Commission's rules regarding the ECOM
True-Up, for the years ended December 31, 2002 and 2003, CenterPoint Energy
recorded approximately $697 million and $661 million, respectively, in non-cash
ECOM True-Up revenue. ECOM True-Up revenue is recorded as a regulatory asset and
totaled $1.4 billion as of December 31, 2003.

In 2003, some parties sought modifications to the true-up rules. Although
the Texas Utility Commission denied that request, the Company expects that
issues could be raised in the 2004 True-Up Proceeding regarding its compliance
with the Texas Utility Commission's rules regarding the ECOM true-up, including
whether Texas Genco has auctioned all capacity it is required to auction in view
of the fact that some capacity has failed to sell in the state-mandated
auctions. The Company believes Texas Genco has complied with the requirements
under the applicable rules, including re-offering the unsold capacity in
subsequent auctions. If events were to occur during the 2004 True-Up Proceeding
that made the recovery of the ECOM true-up regulatory asset no longer probable,
the Company would write off the unrecoverable balance of that asset as a charge
against earnings.

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 in July 2002. This final fuel reconciliation filing
covered reconcilable fuel expense and interest of approximately $8.5 billion
incurred from August 1, 1997 through January 30, 2002. In January 2003, a
settlement agreement was reached, as a result of which certain items totaling
$24 million were written off during the fourth quarter of 2002 and items
totaling $203 million were carried forward for later resolution by the Texas
Utility Commission. In late 2003, a hearing was concluded on those remaining
issues. On March 4, 2004, an Administrative Law Judge (ALJ) recommended that
CenterPoint Houston not be allowed to recover $87 million in fuel expenses
incurred during the reconciliation period. CenterPoint Houston will contest this
recommendation when the Texas Utility Commission considers the ALJ's conclusions
on April 15, 2004. However, since the recovery of this portion of the regulatory
asset is no longer probable, CenterPoint Houston reserved $117 million,
including interest, in the fourth quarter of 2003. The ALJ also recommended that
$46 million be recovered in the 2004 True-Up Proceeding rather than in the fuel
proceeding. The results of the Texas Utility Commission's decision will be a
component of the 2004 True-Up Proceeding.

"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 the "price to beat" in excess of the market price of
electricity if 40% of the "price to beat" load is not served by other retail
electric providers by January 1, 2004. Pursuant to the Texas electric
restructuring law and a master separation agreement entered into in connection
with the September 30, 2002 spin-off of the Company's interest in Reliant
Resources to the Company's shareholders, Reliant Resources is obligated to pay
CenterPoint Houston the clawback component of the true-up. Based on an order
issued on February 13, 2004 by the Texas Utility Commission, the clawback will
equal $150 times the number of residential customers served by Reliant Resources
in CenterPoint Houston's service territory, less the number of residential
customers served by Reliant Resources outside CenterPoint Houston's service
territory, on January 1, 2004. As reported in Reliant Resources' Annual Report
on Form 10-K for the year ended December 31, 2003, Reliant Resources expects
that the clawback payment will be $175 million. The clawback will reduce the
amount of recoverable costs to be determined in the 2004 True-Up Proceeding.

Securitization. The Texas electric restructuring law provides for the use
of special purpose entities to issue transition bonds for the economic value of
generation-related regulatory assets and stranded costs. These transition bonds
will be amortized over a period not to exceed 15 years through non-bypassable
transition charges. In October 2001, a special purpose subsidiary of CenterPoint
Houston issued $749 million of transition bonds to securitize certain
generation-related regulatory assets. These transition bonds have a final
maturity date of September 15, 2015 and are non-recourse to the Company and its
subsidiaries other than to the special purpose issuer. Payments on the
transition bonds are made out of funds from non-bypassable transition charges.

The Company expects that upon completion of the 2004 True-Up Proceeding,
CenterPoint Houston will seek to securitize the amounts established for the
true-up components. Before CenterPoint Houston can securitize these amounts, the
Texas Utility Commission must conduct a proceeding and issue a financing order
authorizing CenterPoint Houston to do so. Under the Texas electric restructuring
law, CenterPoint Houston is entitled to recover any portion of the true-up
balance not securitized by transition bonds through a non-bypassable competition
transition charge.

Mitigation. In an order issued in October 2001, the Texas Utility
Commission established the transmission and distribution rates that became
effective in January 2002. The Texas Utility Commission determined that
CenterPoint Houston had over-mitigated 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 this final order, CenterPoint Houston was required to
reverse the amount of redirected depreciation ($841 million) and accelerated
depreciation ($1.1 billion) taken for regulatory purposes as allowed under the
transition plan and the Texas electric restructuring law. In accordance with the
order, CenterPoint Houston recorded a regulatory liability of $1.1 billion to
reflect the prospective refund of the accelerated depreciation, and in January
2002 CenterPoint Houston began refunding excess mitigation credits, which are to
be refunded over a seven-year period. The annual refund of excess mitigation
credits is approximately $238 million. As of December 31, 2002 and 2003, the
Company had recorded net electric plant mitigation regulatory assets of $1.1
billion and $1.3 billion, respectively, based on the Company's expectation that
these amounts will be recovered in the 2004 True-Up Proceeding as stranded
costs. In the event that the excess mitigation credits prove to have been
unnecessary and CenterPoint Houston is determined to have stranded costs, the
excess mitigation credits will be included in the stranded costs to be
recovered. In June 2003, CenterPoint Houston sought authority from the Texas
Utility Commission to terminate these credits based on then current estimates of
what that final determination would be. The Texas Utility Commission denied the
request in January 2004.

(b) RATE CASES

In August 2002, a settlement was approved by the Arkansas Public Service
Commission (APSC) that resulted in an increase in the base rate and service
charge revenues of CenterPoint Energy Arkla (Arkla) of
27

\
approximately $27 million annually. In addition, the APSC approved a gas main
replacement surcharge that provided $2 million of additional revenue in 2003 and
is expected to provide additional amounts in subsequent years.

In December 2002, a settlement was approved by the Oklahoma Corporation
Commission that resulted in an increase in the base rate and service charge
revenues of Arkla of approximately $6 million annually.

In November 2003, Arkla filed a request with the Louisiana Public Service
Commission (LPSC) for a $16 million increase to its base rate and service charge
revenues in Louisiana. The case is expected to be resolved in mid-2004.

In December 2003, a settlement was approved by the City of Houston that
will result in an increase in the base rate and service charge revenues of
CenterPoint Energy Entex (Entex) of approximately $7 million annually. Entex has
submitted these settlement rates to the 28 other cities within its Houston
Division and the Railroad Commission of Texas for consideration and approval. If
all regulatory approvals are received from these 29 jurisdictions, Entex's base
rate and service charge revenues are expected to increase by approximately $7
million annually in addition to the $7 million increase discussed above.

On February 10, 2004, a settlement was approved by the LPSC that is
expected to result in an increase in Entex's base rate and service charge
revenues of approximately $2 million annually.

Texas Genco is the beneficiary of decommissioning trusts that have 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 Notes 6 and 12(e)). CenterPoint Houston collects through rates or other
authorized charges to its electric utility customers amounts designated for
funding the decommissioning trusts, and deposits these amounts into the
decommissioning trusts. Upon decommissioning of the facility, in the event funds
from the trusts 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.

(d) OTHER REGULATORY PROCEEDINGS

City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas,
asserted that Entex had overcharged residential and small commercial customers
in that city for excessive gas costs under supply agreements in effect since
1992. That dispute has been referred to the Texas Railroad Commission by
agreement of the parties for a determination of 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.

FERC Contract Inquiry. On September 15, 2003, the FERC issued a Show Cause
Order to CenterPoint Energy Gas Transmission Company (CEGT), one of CERC's
natural gas pipeline subsidiaries. In its Show Cause Order, the FERC contends
that CEGT has failed to file with the FERC and post on the internet certain
information relating to negotiated rate contracts that CEGT had entered into
pursuant to 1996 FERC orders. Those orders authorized CEGT to enter into
negotiated rate contracts that deviate from the rates prescribed under its filed
FERC tariffs. The FERC also alleges that certain of the contracts contain
provisions that CEGT was not authorized to negotiate under the terms of the 1996
orders.

Following issuance of the Show Cause Order, CEGT made certain compliance
filings, met with members of the FERC's staff and provided additional
information relating to the FERC's Show Cause Order. On March 4, 2004, the FERC
issued orders accepting CEGT's compliance filings and approving a Stipulation
and

Consent Agreement with CEGT that resolved the issues raised by the Show Cause
Order. The resolution of these issues did not have a material impact on our
results of operations, financial condition and cash flows.

(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.

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 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 2003, 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. 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 "Fuel and Cost
of Gas Sold." 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, 2003, the Company
expects $38 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, 2003, the Company had an
outstanding interest rate swap with a notional amount of $250 million to fix the
interest rate applicable to floating rate short-term debt. This swap, which
expired in January 2004, did not qualify as a cash flow hedge under SFAS No.
133, and was 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, which was recorded in other comprehensive
income and reclassified $36 million and $12 million to interest expense in 2002
and 2003, respectively. The remaining $108 million in other comprehensive income
is being amortized into interest expense in the same period during which the
interest payments are made for the designated fixed-rate debt.

Embedded Derivative. The Company's $575 million of convertible senior
notes, issued May 19, 2003 and $255 million of convertible senior notes, issued
December 17, 2003 (see Note 9), contain contingent interest provisions. The
contingent interest component is an embedded derivative as defined by SFAS No.
133, and accordingly, must be split from the host instrument and recorded at
fair value on the balance sheet. The value of the contingent interest components
was not material at issuance or at December 31, 2003.

(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, 2002 and 2003
(in millions):

<Table>
<Caption>
DECEMBER 31, 2002 DECEMBER 31, 2003
------------------- ----------------------
INVESTMENT INVESTMENT
GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL(3)
----------- ----- ----------- --------

Energy marketers............................. $ 7 $22 $24 $35
Financial institutions....................... 9 9 21 21
Other........................................ -- -- -- 1
--- --- --- ---
Total...................................... $16 $31 $45 $57
=== === === ===
</Table>

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

(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 $35 million non-trading derivative asset includes an $11 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, 2003, Reliant Energy Services did not have an investment grade
rating.

The Company has established a Risk Oversight Committee composed 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.

(7) INDEXED DEBT SECURITIES (ZENS) AND 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 partial
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).
Unrealized gains and losses resulting from changes in the market value of the TW
Common are recorded in the Company's Statements of Consolidated Operations.

(b) ZENS

In September 1999, the Company issued its 2.0% Zero-Premium Exchangeable
Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0
billion. ZENS are exchangeable for cash equal to the market value of a specified
number of shares of TW common. The Company pays interest on the ZENS at an
annual rate of 2% plus the amount of any quarterly cash dividends paid in
respect of the shares of TW Common attributable to the ZENS. The principal
amount of ZENS is subject to being increased to the extent that the annual yield
from interest and cash dividends on the reference shares of TW Common is less
than 2.309%. At December 31, 2003, ZENS having an original principal amount of
$840 million and a contingent principal amount of $848 million were outstanding
and were exchangeable, at the option of the holders, for cash equal to 95% of
the market value of 21.6 million shares of TW Common deemed to be attributable
to the ZENS. At December 31, 2003, the market value of such shares was
approximately $389 million, which would provide an exchange amount of $440 for
each $1,000 original principal amount of ZENS. 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 TW Common, or other securities distributed with
respect to TW Common.

Through December 31, 2003, holders of approximately 16% of the 17.2 million
ZENS originally issued had 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 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 TW Common at an average price
of $10.56 per share. The Company now holds 21.6 million shares of 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.

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 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 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, 2002 and 2003, the Company recorded a loss
of $70 million, a loss of $500 million and a gain of $106 million, respectively,
on the Company's investment in TW Common. During 2001, 2002 and 2003, the
Company recorded a gain of $58 million, a gain of $480 million and a loss of $96
million, respectively, associated with the fair value of the derivative

component of the ZENS obligation. Changes in the fair value of the TW Common
held by the Company are expected to substantially offset changes in the fair
value of the derivative component of the ZENS.

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

<Table>
<Caption>
DEBT DERIVATIVE
TW COMPONENT COMPONENT
INVESTMENT OF ZENS OF ZENS
---------- --------- ----------

Balance at December 31, 2000......................... $897 $1,000 $ --
Transition adjustment from adoption of SFAS No.
133................................................ -- (90) --
Bifurcation of ZENS obligation....................... -- (788) 788
Accretion of debt component of ZENS.................. -- 1 --
Gain on indexed debt securities...................... -- -- (58)
Loss on TW Common.................................... (70) -- --
---- ------ -----
Balance at December 31, 2001......................... 827 123 730
Accretion of debt component of ZENS.................. -- 1 --
Gain on indexed debt securities...................... -- -- (480)
Loss on TW Common.................................... (500) -- --
Liquidation of TW Common............................. (43) -- --
Liquidation of ZENS, net of gain..................... -- (20) (25)
---- ------ -----
Balance at December 31, 2002......................... 284 104 225
Accretion of debt component of ZENS.................. -- 1 --
Loss on indexed debt securities...................... -- -- 96
Gain on TW Common.................................... 106 -- --
---- ------ -----
Balance at December 31, 2003......................... $390 $ 105 $ 321
==== ====== =====
</Table>

(10) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS

(b) PENSION AND POSTRETIREMENT BENEFITS

The Company maintains a non-contributory qualified defined benefit plan
covering substantially all employees, with benefits determined 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 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, healthcare 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.

On January 12, 2004, the FASB issued FSP FAS 106-1. In accordance with FSP
FAS 106-1, the Company's postretirement benefits obligations and net periodic
postretirement benefit cost in the financial statements and accompanying notes
do not reflect the effects of the legislation. Specific authoritative guidance
on the accounting for the legislation is pending and that guidance, when issued,
may require the Company to change previously reported information.

The Company's net periodic cost includes the following components relating
to pension and postretirement benefits:

<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------
2001 2002 2003
------------------------- ------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- -------------- -------- --------------
(IN MILLIONS)

Service cost........... $ 35 $ 5 $ 32 $ 5 $ 37 $ 4
Interest cost.......... 99 31 104 32 102 31
Expected return on plan
assets............... (138) (13) (126) (13) (92) (11)
Net amortization....... (3) 14 16 13 43 13
Curtailment............ (23) 40 -- -- -- --
Benefit enhancement.... 69 -- 9 3 -- --
Settlement............. -- -- -- (18) -- --
----- ---- ----- ---- ---- ----
Net periodic cost...... $ 39 $ 77 $ 35 $ 22 $ 90 $ 37
===== ==== ===== ==== ==== ====
Above amounts reflect
the following net
periodic cost
(benefit) related to
discontinued
operations........... $ 45 $ 42 $ (4) $(16) $ -- $ --
===== ==== ===== ==== ==== ====
</Table>

The Company used the following assumptions to determine net periodic cost
relating to pension and postretirement benefits:

Discount rate.......... 7.50% 7.50% 7.25% 7.25% 6.75% 6.75%
Expected return on plan
assets............... 10.0% 10.0% 9.5% 9.5% 9.0% 9.0%
Rate of increase in
compensation
levels............... 4.1% -- 4.1% -- 4.1% --
</Table>

In determining net periodic benefits cost, the Company uses fair value, as
of the beginning of the year, as its basis for determining expected return on
plan assets.

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 of December 31, 2002 and 2003 for the Company's pension and
postretirement benefit plans:

<Table>
<Caption>
DECEMBER 31,
-------------------------------------------------------------
2002 2003
----------------------------- -----------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
------------ -------------- ------------ --------------
(IN MILLIONS)

CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of
year................................ $ 1,485 $ 456 $ 1,550 $ 479
Service cost.......................... 32 5 37 4
Interest cost......................... 104 32 102 31
Participant contributions............. -- 7 -- 8
Benefits paid......................... (136) (26) (142) (43)
Plan amendments....................... -- -- 4 (5)
Actuarial loss........................ 56 20 141 44
Curtailment, benefit enhancement and
settlement.......................... 9 (15) -- --
------------ ------------ ------------ ------------
Benefit obligation, end of year....... $ 1,550 $ 479 $ 1,692 $ 518
============ ============ ============ ============
CHANGE IN PLAN ASSETS
Plan assets, beginning of year........ $ 1,376 $ 139 $ 1,054 $ 131
Employer contributions................ -- 30 23 34
Participant contributions............. -- 7 -- 8
Benefits paid......................... (136) (26) (142) (43)
Actual investment return.............. (186) (19) 259 20
------------ ------------ ------------ ------------
Plan assets, end of year.............. $ 1,054 $ 131 $ 1,194 $ 150
============ ============ ============ ============
RECONCILIATION OF FUNDED STATUS
Funded status......................... $ (496) $ (348) $ (498) $ (368)
Unrecognized actuarial loss........... 811 27 733 63
Unrecognized prior service cost....... (84) 60 (71) 49
Unrecognized transition (asset)
obligation.......................... -- 87 -- 79
------------ ------------ ------------ ------------
Net amount recognized................. $ 231 $ (174) $ 164 $ (177)
============ ============ ============ ============
AMOUNTS RECOGNIZED IN BALANCE SHEETS
Benefit obligations................... $ (392) $ (174) $ (395) $ (177)
Accumulated other comprehensive
income.............................. 623 -- 559 --
------------ ------------ ------------ ------------
Prepaid (accrued) pension cost........ $ 231 $ (174) $ 164 $ (177)
============ ============ ============ ============
ACTUARIAL ASSUMPTIONS
Discount rate......................... 6.75% 6.75% 6.25% 6.25%
Expected return on plan assets........ 9.0% 9.0% 9.0% 8.5%
Rate of increase in compensation
levels.............................. 4.1% -- 4.1% --
Healthcare cost trend rate assumed for
the next year....................... -- 11.25% -- 10.50%
Rate to which the cost trend rate is
assumed to decline (the ultimate
trend rate)......................... -- 5.5% -- 5.5%
Year that the rate reaches the
ultimate trend rate................. -- 2011 -- 2011
</Table>

ADDITIONAL INFORMATION
Accumulated benefit obligation........ $ 1,446 $ 479 $ 1,589 $ 518
Change in minimum liability included )
in other comprehensive income....... 623 -- (64 --
Measurement date used to determine December 31, December 31, December 31, December 31,
plan obligations and assets......... 2002 2002 2003 2003
</Table>

Assumed healthcare cost trend rates have a significant effect on the
reported amounts for the Company's postretirement benefit plans. A 1% change in
the assumed healthcare cost trend rate would have the following effects:

<Table>
<Caption>
1% 1%
INCREASE DECREASE
-------- --------
(IN MILLIONS)

Effect on total of service and interest cost................ $ 2 $ 2
Effect on the postretirement benefit obligation............. 30 26
</Table>

The following table displays the weighted-average asset allocations as of
December 31, 2002 and 2003 for the Company's pension and postretirement benefit
plans:

<Table>
<Caption>
DECEMBER 31,
-----------------------------------------------------
2002 2003
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------

Domestic equity securities................ 55% 35% 60% 41%
International equity securities........... 12 8 15 9
Debt securities........................... 29 54 22 48
Real estate............................... 4 -- 3 --
Cash...................................... -- 3 -- 2
--- --- --- ---
Total................................... 100% 100% 100% 100%
=== === === ===
</Table>

In managing the investments associated with the benefit plans, the
Company's objective is to preserve and enhance the value of plan assets while
maintaining an acceptable level of volatility. These objectives are expected to
be achieved through an investment strategy, that manages liquidity requirements
while maintaining a long-term horizon in making investment decisions and
efficient and effective management of plan assets.

As part of the investment strategy discussed above, the Company has adopted
and maintains the following weighted average allocation targets for its benefit
plans:

<Table>
<Caption>
PENSION POSTRETIREMENT
BENEFITS BENEFITS
-------- --------------

Domestic equity securities.................................. 50-60% 28-38%
International equity securities............................. 10-20% 5-15%
Debt securities............................................. 20-30% 52-62%
Real estate................................................. 0-5% --
Cash........................................................ 0-2% 0-2%
</Table>

The expected rate of return assumption was developed by reviewing the
targeted asset allocations and historical index performance of the applicable
asset classes over a 15-year period, adjusted for investment fees and
diversification effects.

Equity securities for the pension plan include CenterPoint Energy common
stock in the amounts of $38 million (4.7% of total pension plan assets) and $44
million (3.7% of total pension plan assets) and as of December 31, 2002 and
2003, respectively.

The Company expects to contribute $38 million to its postretirement
benefits plan in 2004. Contributions to the pension plan are not required or
expected in 2004.

In addition to the non-contributory pension plans discussed above, the
Company maintains a non-qualified benefit restoration plan which allows
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, $9 million and $8 million in 2001, 2002 and 2003, 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
$83 million and $75 million at December 31, 2002 and 2003, respectively. In
addition, these accrued benefit liabilities include the recognition of minimum
liability adjustments of $23 million as of December 31, 2002 and $15 million as
of December 31, 2003, which are reported as a component of other comprehensive
income, net of income tax effects.

The following table displays the Company's plans with accumulated benefit
obligations in excess of plan assets:

<Table>
<Caption>
DECEMBER 31,
---------------------------------------------------------------------------------
2002 2003
--------------------------------------- ---------------------------------------
PENSION RESTORATION POSTRETIREMENT PENSION RESTORATION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- ----------- -------------- -------- ----------- --------------
(IN MILLIONS)

Accumulated benefit
obligation................ $1,446 $83 $479 $1,589 $75 $518
Projected benefit
obligation................ 1,550 86 479 1,692 77 518
Plan assets................. 1,054 -- 131 1,194 -- 150
</Table>

(12) COMMITMENTS AND CONTINGENCIES

(a) COMMITMENTS

Environmental Capital Commitments. CenterPoint Energy anticipates
investing up to $131 million in capital and other special project expenditures
between 2004 and 2008 for environmental compliance. CenterPoint Energy
anticipates expenditures to be as follows (in millions):

<Table>

2004........................................................ $ 42
2005........................................................ 32
2006........................................................ 43
2007........................................................ 14
2008(1)..................................................... --
----
Total..................................................... $131
====
</Table>

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

(1) NOx control estimates for 2008 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
and natural gas contracts related to the Company's natural gas distribution
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, 2003 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 and lignite mining and lease agreements that
extend through 2012 are approximately $309 million in 2004, $251 million in
2005, $256 million in 2006, $248 million in 2007 and $162 million in 2008.
Minimum payment obligations for natural gas supply contracts are approximately
$1 billion in 2004, $565 million in 2005, $344 million in 2006, $171 million in
2007 and $24 million in 2008. Purchase commitments related to purchased power
are not material to CenterPoint Energy's operations.

(b) LEASE COMMITMENTS

The following table sets forth information concerning the Company's
obligations under non-cancelable long-term operating leases at December 31,
2003, which primarily consist of rental agreements for building space, data
processing equipment and vehicles, including major work equipment (in millions):

<Table>

2004........................................................ $ 42
2005........................................................ 27
2006........................................................ 24
2007........................................................ 20
2008........................................................ 17
2009 and beyond............................................. 56
----
Total..................................................... $186
====
</Table>

Total lease expense for all operating leases was $45 million, $47 million
and $46 million during 2001, 2002 and 2003, respectively.

Legal Matters

Reliant Resources Indemnified Litigation

The Company, CenterPoint Houston or their predecessor, Reliant Energy, and
certain of their 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, including attorneys' fees and
other costs, arising out of the lawsuits described below under Electricity and
Gas Market Manipulation Cases and Other Class Action Lawsuits. 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.

Electricity and Gas Market Manipulation Cases. A large number of lawsuits
have been filed against numerous market participants and remain pending in both
federal and state courts in California and Nevada in connection with the
operation of the electricity and natural gas markets in California and certain
other western states in 2000-2001, a time of power shortages and significant
increases in prices. These lawsuits, many of which have been filed as class
actions, are based on a number of legal theories, including violation of state
and federal antitrust laws, laws against unfair and unlawful business practices,
the federal Racketeer Influenced Corrupt Organization Act, false claims statutes
and similar theories and breaches of contracts to supply power to governmental
entities. Plaintiffs in these lawsuits, which include state officials and
governmental entities as well as private litigants, are seeking a variety of
forms of relief, including recovery of compensatory damages (in some cases in
excess of $1 billion), a trebling of compensatory damages and punitive damages,
injunctive relief, restitution, interest due, disgorgement, civil penalties and
fines, costs of suit, attorneys' fees and divestiture of assets. To date, some
of these complaints have been dismissed by the trial court and are on appeal,
but most of the lawsuits remain in early procedural stages. Our former
subsidiary, Reliant Resources, was a participant in the California markets,
owning generating plants in the state and participating in both electricity and
natural gas trading in that state and in western power markets generally.
Reliant Resources, some of its subsidiaries and in some cases, corporate
officers of some of those companies, have been named as defendants in these
suits.

The Company, CenterPoint Houston or their predecessor, Reliant Energy, have
also been named in approximately 25 of these lawsuits, which were instituted in
2002 and 2003 and are pending in state courts in San Diego, San Francisco and
Los Angeles Counties and in federal district courts in San Francisco, San Diego,
Los Angeles and Nevada. However, neither the Company nor Reliant Energy was a
participant in the electricity or natural gas markets in California. The Company
and Reliant Energy have been dismissed from certain of the lawsuits, either
voluntarily by the plaintiffs or by order of the court and the Company believes
it is not a proper defendant in the remaining cases and will continue to seek
dismissal from the remaining cases.

Other Class Action Lawsuits. 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 former and current
executive officers are named as defendants. Reliant Energy is also named as a
defendant in seven of the lawsuits. Two of the lawsuits also name as defendants
the underwriters of the initial public offering of Reliant Resources common
stock in May 2001 (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
purchasers of common stock of Reliant Energy or Reliant Resources during certain
time periods ranging from February 2000 to May 2002, including purchasers of
common stock that can be traced 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
January 2004 the trial judge dismissed the plaintiffs' allegations that the
defendants had engaged in fraud, but claims based on alleged misrepresentations
in the registration statement issued in the Reliant Resources Offering remain.

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. In January 2004 the
trial judge ordered dismissal of plaintiffs' claims on the ground that they did
not set forth a claim, but granted the plaintiffs leave to amend their
complaint.

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 on behalf
of the plans and 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 January 2004 the trial judge dismissed the
complaints against a number of defendants, but allowed the case to proceed
against members of the Reliant Energy benefits committee.

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 of Reliant Resources
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. In March 2003, the court
dismissed this case on the grounds that the plaintiff did not make an adequate
demand on the Company before filing suit. Thereafter, the plaintiff sent another
demand asserting the same claims.

The Company's board of directors investigated that demand and similar
allegations made in a June 28, 2002 demand letter sent on behalf of a Company
shareholder. The latter letter demanded that the Company take several actions in
response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June
2003, the Board determined that these proposed actions would not be in the best
interests of the Company.

The Company believes that none of the lawsuits described under "Other Class
Action 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.

Other Legal Matters

Texas Antitrust Action. In July 2003, Texas Commercial Energy filed a
lawsuit against Reliant Energy, Reliant Resources, Reliant Electric Solutions,
LLC, several other Reliant Resources subsidiaries and several other participants
in the ERCOT power market in federal court in Corpus Christi, Texas. The
plaintiff, a retail electricity provider in the Texas market served by ERCOT,
alleges that the defendants conspired to illegally fix and artificially increase
the price of electricity in violation of state and federal antitrust laws and
committed fraud and negligent misrepresentation. The lawsuit seeks damages in
excess of $500 million, exemplary damages, treble damages, interest, costs of
suit and attorneys' fees. In February 2004, this complaint was amended to add
the Company and CenterPoint Houston, as successors to Reliant Energy, and Texas
Genco, LP as defendants. The plaintiff's principal allegations have previously
been investigated by the Texas Utility Commission and found to be without merit.
The Company also believes the plaintiff's allegations are without merit and will
seek their dismissal.

Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton,
Galveston and Pasadena (Three Cities) 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 the Company's predecessor, Reliant Energy) alleging
underpayment of municipal franchise fees. The plaintiffs claimed that they were
entitled to 4% of all receipts of any kind for business conducted within these
cities over the previous four decades. After a jury trial of the original
claimant cities (but not the class of cities), the trial court decertified the
class and reduced the damages awarded by the jury to $1.7 million, including
interest, plus an award of $13.7 million in legal fees. Despite other jury
findings for the plaintiffs, the trial court's judgment was based on the jury's
finding 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. Following this ruling, 45 cities filed
individual suits against Reliant Energy in the District Court of Harris County.

On February 27, 2003, a 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 Three
Cities filed a petition for review at the Texas Supreme Court, which declined to
hear the case, although the time period for the Three Cities to file a motion
for rehearing has not yet expired. The extent to which issues in the Three
Cities case may affect the claims of the other cities served by CenterPoint
Houston cannot be assessed until judgments are final and no longer subject to
appeal.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its
subsidiaries are defendants in a suit filed in 1997 under the Federal False
Claims Act 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. and certain of its subsidiaries are defendants in
two mismeasurement lawsuits against approximately 245 pipeline companies and
their affiliates pending in state court in Stevens County, Kansas. In one case
(originally filed in May 1999 and amended four times), the plaintiffs purport to
represent a class of royalty owners who allege that the defendants have engaged
in systematic mismeasurement of the volume of natural gas for more than 25
years. The plaintiffs amended their petition in this suit in July 2003 in
response to an order from the judge denying certification of the plaintiffs'
alleged class. In the amendment the plaintiffs dismissed their claims against
certain defendants (including two CERC subsidiaries), limited the scope of the
class of plaintiffs they purport to represent and eliminated previously asserted
claims based on mismeasurement of the Btu content of the gas. The same
plaintiffs then filed a second lawsuit, again as representatives of a class of
royalty owners, in which they assert their claims that the defendants have
engaged

in systematic mismeasurement of the Btu content of natural gas for more than 25
years. In both lawsuits, the plaintiffs seek compensatory damages, along with
statutory penalties, treble damages, interest, costs and fees.

Gas Cost Recovery Litigation. 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 Utilities 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 certain 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. In February 2004, another suit was filed against CERC
in Calcasieu Parish, Louisiana, seeking to recover alleged overcharges for gas
or gas services allegedly provided by Entex without advance approval by the
LPSC. The plaintiffs in these cases seek injunctive and declaratory relief,
restitution for the alleged overcharges, exemplary damages or trebling of actual
damages and civil penalties. In these cases, the Company, CERC and Entex Gas
Marketing Company deny that they have overcharged any of their customers for
natural gas and believe that the amounts recovered for purchased gas have been
in accordance with what is permitted by state regulatory authorities.

Environmental Matters

Clean Air Standards. The Texas electric restructuring law and regulations
adopted by the Texas Commission on Environmental Quality (TCEQ) in 2001 require
substantial reductions in emission of oxides of nitrogen (NOx) from electric
generating units. The Company is currently installing cost-effective controls at
its generating plants to comply with these requirements. Through December 31,
2003, the Company has invested $664 million for NOx emission control, and plans
to make expenditures of up to approximately $131 million during the years 2004
through 2007. Further revisions to these NOx standards may result from the
TCEQ's future rules, expected by 2007, implementing more stringent federal
eight-hour ozone standards. 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 cost-effective
option for achieving compliance with applicable air quality standards for the
Company's generating facilities and the final amount for recovery will be
determined in the 2004 True-Up Proceeding.

which CERC believes were neither owned nor operated by CERC, and for which CERC
believes it has no liability.

CERC has received notices from the United States Environmental Protection
Agency and others regarding its status as a PRP for other sites. CERC has been
named as a defendant in lawsuits under which contribution is sought for the cost
to remediate former MGP sites based on the previous ownership of such sites by
former affiliates of CERC or its divisions. The Company is investigating details
regarding these sites and the range of environmental expenditures for potential
remediation. Based on current information, the Company has not been able to
quantify a range of environmental expenditures for such 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.

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.

Other Proceedings

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

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.

(e) NUCLEAR DECOMMISSIONING

CenterPoint Houston contributed $14.8 million in 2001 to trusts established
to fund Texas Genco's share of the decommissioning costs for the South Texas
Project. CenterPoint Houston contributed $2.9 million in both 2002 and 2003 to
these trusts. There are various investment restrictions imposed upon Texas Genco
by the Texas Utility Commission and the United States Nuclear Regulatory
Commission (NRC) relating to Texas Genco's nuclear decommissioning trusts. Texas
Genco and CenterPoint Energy 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 $189 million as of December 31, 2003, of which approximately 37% were
fixed-rate debt securities and the remaining 63% were equity securities. For a
discussion of the accounting treatment for the securities held in the nuclear
decommissioning trust, see Note 2(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. For
information regarding the effect of the business separation plan on funding of
the nuclear decommissioning trust fund, see Note 4(c).