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

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, 2004, 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 in specified amounts, 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
generally require that CenterPoint Houston and CERC maintain a ratio of common
equity to total capitalization of at least 30%. We intend to file an application
for approval of our post-June 30, 2005 financing activities.

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.

The United States Congress from time to time considers legislation 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.

FEDERAL ENERGY REGULATORY COMMISSION

The FERC has jurisdiction under the Natural Gas Act and the Natural Gas
Policy Act of 1978, as amended, to regulate the transportation of natural gas in
interstate commerce and natural gas sales for resale in intrastate commerce that
are not first sales. The FERC regulates, 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. During 2004, the FERC
Order was amended three times. 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 were
further required to post their Implementation Procedures on their websites by
September 22, 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.

STATE AND LOCAL REGULATION

Electric Transmission & 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 50 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 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 2004, the City of Houston, 28 other cities and the Railroad Commission
approved a settlement that increased Houston Gas' base rate and service charge
revenues by approximately $14 million annually.

In February 2004, the Louisiana Public Service Commission (LPSC) approved a
settlement that increased Southern Gas Operations' base rate and service charge
revenues in its South Louisiana Division by approximately $2 million annually.

In July 2004, Minnesota Gas filed an application for a general rate
increase of $22 million with the Minnesota Public Utilities Commission (MPUC).
Minnesota Gas and the Minnesota Department of Commerce have agreed to a
settlement of all issues, including an annualized increase in the amount of $9
million, subject to approval by the MPUC. A final decision on this rate relief
request is expected from the MPUC in the second quarter of 2005. Interim rates
of $17 million on an annualized basis became effective on October 1, 2004,
subject to refund.

In July 2004, the LPSC approved a settlement that increased Southern Gas
Operations' base rate and service charge revenues in its North Louisiana
Division by approximately $7 million annually.

In October 2004, Southern Gas Operations filed an application for a general
rate increase of approximately $3 million with the Railroad Commission for rate
relief in the unincorporated areas of its Beaumont, East Texas and South Texas
Divisions. The Railroad Commission staff has begun its review of the request,
and a decision is anticipated in April 2005.

In November 2004, Southern Gas Operations filed an application for a
general rate increase of approximately $34 million with the Arkansas Public
Service Commission (APSC). The APSC staff has begun its review of the request,
and a decision is anticipated in the second half of 2005.

In December 2004, the OCC approved a settlement that increased Southern Gas
Operations' base rate and service charge revenues in Oklahoma by approximately
$3 million annually.

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 and provided guidance on, among other
things, the areas that should be classified as HCA. Our interstate pipelines
developed and implemented a written pipeline integrity management program in
2004, meeting the Depart-

ment of Transportation Office of Pipeline Safety requirement of having the
program in place by December 17, 2004.

Our interstate and intrastate pipelines 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

Our operations are subject to stringent and complex laws and regulations
pertaining to health, safety and the environment. As an owner or operator of
natural gas pipelines, gas gathering and processing systems, and electric
transmission and distribution systems we must comply with these laws and
regulations at the federal, state and local levels. These laws and regulations
can restrict or impact our business activities in many ways, such as:

- restricting the way we can handle or dispose of our wastes;

- limiting or prohibiting construction activities in sensitive areas such
as wetlands, coastal regions, or areas inhabited by endangered species;

- requiring remedial action to mitigate pollution conditions caused by our
operations, or attributable to former operations; and

- enjoining the operations of facilities deemed in non-compliance with
permits issued pursuant to such environmental laws and regulations.

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 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.

Failure to comply with these laws and regulations may trigger a variety of
administrative, civil and criminal enforcement measures, including the
assessment of monetary penalties, the imposition of remedial requirements, and
the issuance of orders enjoining future operations. Certain environmental
statutes impose strict, joint and several liability for costs required to clean
up and restore sites where hazardous substances have been disposed or otherwise
released. Moreover, it is not uncommon for neighboring landowners and other
third parties to file claims for personal injury and property damage allegedly
caused by the release of hazardous substances or other waste products into the
environment.

The trend in environmental regulation is to place more restrictions and
limitations on activities that may affect the environment, and thus there can be
no assurance as to the amount or timing of future expenditures for environmental
compliance or remediation, and actual future expenditures may be different from
the amounts we currently anticipate. We try to anticipate future regulatory
requirements that might be imposed and plan accordingly to remain in compliance
with changing environmental laws and regulations and to minimize the costs of
such compliance.

We do not believe that compliance with federal, state or local
environmental laws and regulations will have a material adverse effect on our
business, financial position or results of operations. In addition, we

believe that the various environmental remediation activities in which we are
presently engaged will not materially interrupt or diminish our operational
ability. We cannot assure you, however, that future events, such as changes in
existing laws, the promulgation of new laws, or the development or discovery of
new facts or conditions will not cause us to incur significant costs. The
following is a discussion of all material environmental and safety laws and
regulations that relate to our operations. We believe that we are in substantial
compliance with all of these environmental laws and regulations.

AIR EMISSIONS

Our operations are subject to the federal Clean Air Act and comparable
state laws and regulations. These laws and regulations regulate emissions of air
pollutants from various industrial sources, including our processing plants and
compressor stations, and also impose various monitoring and reporting
requirements. Such laws and regulations may require that we obtain pre-approval
for the construction or modification of certain projects or facilities expected
to produce air emissions or result in the increase of existing air emissions,
obtain and strictly comply with air permits containing various emissions and
operational limitations, or utilize specific emission control technologies to
limit emissions. Our failure to comply with these requirements could subject us
to monetary penalties, injunctions, conditions or restrictions on operations,
and potentially criminal enforcement actions. We may be required to incur
certain capital expenditures in the future for air pollution control equipment
in connection with obtaining and maintaining operating permits and approvals for
air emissions. We believe, however, that our operations will not be materially
adversely affected by such requirements, and the requirements are not expected
to be any more burdensome to us than to any other similarly situated companies.

WATER DISCHARGES

Our operations are subject to the Federal Water Pollution Control Act of
1972, as amended, also known as the Clean Water Act, and analogous state laws
and regulations. These laws and regulations impose detailed requirements and
strict controls regarding the discharge of pollutants into waters of the United
States. The unpermitted discharge of pollutants, including discharges resulting
from a spill or leak incident, is prohibited. The Clean Water Act and
regulations implemented thereunder also prohibit discharges of dredged and fill
material in wetlands and other waters of the United States unless authorized by
an appropriately issued permit. Any unpermitted release of petroleum or other
pollutants from our pipelines or facilities could result in fines or penalties
as well as significant remedial obligations.

HAZARDOUS WASTE

Our operations generate wastes, including some hazardous wastes, that are
subject to the federal Resource Conservation and Recovery Act (RCRA), and
comparable state laws, which impose detailed requirements for the handling,
storage, treatment and disposal of hazardous and solid waste. RCRA currently
exempts many natural gas gathering and field processing wastes from
classification as hazardous waste. Specifically, RCRA excludes from the
definition of hazardous waste produced waters and other wastes associated with
the exploration, development, or production of crude oil and natural gas.
However, these oil and gas exploration and production wastes are still regulated
under state law and the less stringent non-hazardous waste requirements of RCRA.
Moreover, ordinary industrial wastes such as paint wastes, waste solvents,
laboratory wastes, and waste compressor oils may be regulated as hazardous
waste. The transportation of natural gas in pipelines may also generate some
hazardous wastes that are subject to RCRA or comparable state law requirements.

LIABILITY FOR REMEDIATION

The Comprehensive Environmental Response, Compensation and Liability Act of
1980, as amended (CERCLA), also known as "Superfund," and comparable state laws
impose liability, without regard to fault or the legality of the original
conduct, on certain classes of persons responsible for the release of hazardous
substances into the environment. Such classes of persons include the current and
past owners or operators of sites where a hazardous substance was released, and
companies that disposed or arranged for disposal of

hazardous substances at offsite locations such as landfills. Although petroleum
as well as natural gas is excluded from CERCLA's definition of "hazardous
substance," in the course of our ordinary operations we generate wastes that may
fall within the definition of a "hazardous substance." CERCLA authorizes the
United States Environmental Protection Agency (EPA) and, in some cases, third
parties to take actions in response to threats to the public health or the
environment and to seek to recover from the responsible classes of persons the
costs they incur. Under CERCLA, we could be subject to joint and several
liability for the costs of cleaning up and restoring sites where hazardous
substances have been released, for damages to natural resources, and for the
costs of certain health studies.

LIABILITY FOR PREEXISTING CONDITIONS

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among 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. We believe the ultimate cost associated with resolving this matter will
not have a material impact on our financial condition or results of operations
or that of CERC.

Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed
remediation on two sites, other than ongoing monitoring and water treatment.
There are five remaining sites in CERC's Minnesota service territory. CERC
believes that it has no liability with respect to two of these sites.

At December 31, 2004, CERC had accrued $18 million for remediation of
certain Minnesota sites. At December 31, 2004, the estimated range of possible
remediation costs for these sites was $7 million to $42 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. As of December 31, 2004, CERC has collected or
accrued $13 million from insurance companies and ratepayers to be used for
future environmental remediation.

In addition to the Minnesota sites, the EPA and other regulators have
investigated MGP sites that were owned or operated by CERC or may have been
owned or operated by one of its former affiliates. CERC has not been named by
these agencies as a PRP for any of those 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. However, CERC believes it is not liable as a former owner or
operator of those sites under CERCLA and applicable state statutes, and is
vigorously contesting those suits.

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.

Asbestos. A number of facilities that we own contain significant amounts
of asbestos insulation and other asbestos-containing materials. We or our
subsidiaries have been named, along with numerous others, as a defendant in
lawsuits filed by a large number of individuals who claim injury due to exposure
to asbestos. Most claimants in such litigation have been workers who
participated in construction of various industrial facilities, including power
plants. Some of the claimants have worked at locations we own, but most existing
claims relate to facilities previously owned by us but currently owned by Texas
Genco LLC. We anticipate that additional claims like those received may be
asserted in the future. Under the terms of the separation agreement between us
and Texas Genco, ultimate financial responsibility for uninsured losses relating
to these claims has been assumed by Texas Genco, but under the terms of our
agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to
defend such claims to the extent they are covered by insurance we maintain,
subject to reimbursement of the costs of such defense from Texas Genco LLC.
Although their ultimate outcome cannot be predicted at this time, we intend to
continue vigorously contesting claims that we do not consider to have merit and
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.

REGULATORY AND ENVIRONMENTAL MATTERS RELATING TO DISCONTINUED OPERATIONS

Nuclear Regulatory Commission. Texas Genco is subject to regulation by the
NRC with respect to the operation of the South Texas Project nuclear facility.
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 by the transaction agreement with Texas Genco LLC 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.

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). In January 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.

In conjunction with Texas Genco's 30.8% ownership interest in the South
Texas Project, Texas Genco bears a proportionate share of responsibility
associated with the proper handling and disposal of high-level radioactive waste
(spent nuclear fuel) as well as low-level radioactive waste. The South Texas
Project has on-site storage facilities with the capability to store the spent
nuclear fuel, and currently does store such waste on-site, per the requirements
established by the NRC. There is adequate on-site storage at the South Texas
Project for high-level radioactive waste over the licensed life of the two
generating units.

The 1980 Federal Low-Level Radioactive Waste Policy Act directed states to
assume responsibility for the disposal of low-level radioactive waste generated
within their borders. Texas does not currently have any waste disposal locations
available for low-level radioactive waste. Private waste management companies
are seeking to develop sites in Texas but Texas Genco cannot predict when such a
site may be available. South Carolina and New Mexico operate low-level
radioactive waste disposal sites that accept low-level radioactive waste from
Texas. The South Texas Project disposes of its low-level radioactive waste in
both South Carolina and New Mexico under short-term annual agreements. In the
event that both South Carolina and New Mexico stop accepting waste in the
future, and until a Texas site is functional, the South Texas Project has
storage for at least five years of low-level radioactive waste generated by the
project.

RISK FACTORS

RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS

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

On March 31, 2004, CenterPoint Houston filed the final true-up application
required by the Texas electric restructuring law with the Texas Utility
Commission. CenterPoint Houston's requested true-up balance was $3.7 billion,
excluding interest and net of the retail clawback payable to CenterPoint Houston
by a former affiliate. In December 2004, the Texas Utility Commission approved a
final order in CenterPoint Houston's true-up proceeding authorizing CenterPoint
Houston to recover $2.3 billion including interest through August 31, 2004,
subject to adjustments to reflect the benefit of certain deferred taxes and the
accrual of interest and payment of excess mitigation credits after August 31,
2004. In January 2005, we appealed certain aspects of the final order seeking to
increase the true-up balance ultimately recovered by CenterPoint Houston. Other
parties have also appealed the order, seeking to reduce the amount authorized
for CenterPoint Houston's recovery. Although we believe we have meritorious
arguments and that the other parties' appeals are without merit, no prediction
can be made as to the ultimate outcome or timing of such appeals. A failure by
CenterPoint Houston to recover the full value of its true-up components may have
an adverse impact on CenterPoint Houston's results of operations, financial
condition and cash flows.

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 56 retail electric providers. Adverse economic
conditions, structural problems in the market served by ERCOT 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. RRI, through its subsidiaries, is
CenterPoint Houston's largest customer. Approximately 69% of CenterPoint
Houston's $102 million in billed receivables from retail electric providers at
December 31, 2004 was owed by subsidiaries of RRI.

RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY
CENTERPOINT HOUSTON'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER
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 an 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 regulatory process in
which rates are determined will always result in rates that will produce full
recovery of CenterPoint Houston's costs and enable CenterPoint Houston to earn a
reasonable return on its invested capital.

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 significant 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 NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING
BUSINESSES

RATE REGULATION OF CERC'S BUSINESS MAY DELAY OR DENY CERC'S ABILITY TO EARN A
REASONABLE RETURN AND FULLY RECOVER ITS COSTS.

CERC's rates for its local distribution companies 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 in the applicable jurisdictions is, generally, premised on providing
an opportunity to recover reasonable and necessary operating expenses and to
earn a reasonable return on invested capital, there can be no assurance that the
regulatory process in which rates are determined will always result in rates
that will produce full recovery of CERC's costs and enable CERC to earn a
reasonable return on its invested capital.

CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND ITS
PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE
TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING 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, on the regulated side, 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 the areas in
which CERC operates and increase the risk that CERC's suppliers or customers
fail or are unable to meet their obligations. Additionally, increasing gas
prices could create the need for CERC to provide collateral in order to purchase
gas.

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

CERC's contract with Laclede Gas Company, one of its pipeline customers, is
currently scheduled to expire in 2007. To the extent the pipeline is unable to
extend this contract or the contract is renegotiated at rates substantially less
than the rates provided in the current contract, there could be an adverse
effect on CERC's results of operations, financial condition and cash flows.

A DECLINE IN CERC'S CREDIT RATING COULD RESULT IN CERC'S HAVING TO PROVIDE
COLLATERAL IN ORDER TO PURCHASE GAS.

If CERC's credit rating were to decline, it might be required to post cash
collateral in order to purchase natural gas. If a credit rating downgrade and
the resultant cash collateral requirement were to occur at a time when CERC was
experiencing significant working capital requirements or otherwise lacked
liquidity, CERC might be unable to obtain the necessary natural gas to meet its
contractual distribution obligations, and its results of operations, financial
condition and cash flows would be adversely affected.

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

CERC's interstate pipelines and natural gas gathering and processing
business 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 is 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 AFFECTING TEXAS GENCO

Until the closing of the merger of Texas Genco with a subsidiary of Texas
Genco LLC, which is expected to occur during the first half of 2005 following
receipt of approval from the NRC, Texas Genco's operations at the South Texas
Project nuclear generating station will continue to be a part of our business.
The application for approval is currently pending before the NRC.

TEXAS GENCO HAS SOLD FORWARD A SUBSTANTIAL PORTION OF ITS SHARE OF THE POWER
GENERATED BY THE SOUTH TEXAS PROJECT TO TEXAS GENCO LLC. ACCORDINGLY, TEXAS
GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE
ADVERSELY AFFECTED IF TEXAS GENCO LLC FAILS TO MEET ITS PURCHASE OBLIGATIONS.

In connection with the sale of Texas Genco's fossil generation assets to
Texas Genco LLC, Genco LP entered into a power purchase and sale agreement with
Texas Genco LLC, which we refer to as the back-to-back power purchase agreement.
Under this agreement, Genco LP has sold forward a substantial portion of Genco
LP's share of the energy from the South Texas Project through December 31, 2008.
In the event Texas Genco LLC fails to meet its purchase obligations under the
back-to-back power purchase agreement, Texas Genco's results of operations,
financial condition and cash flows could be adversely affected. As of December
31, 2004, Texas Genco LLC's securities ratings were below investment grade.

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

Although Texas Genco has already sold forward a substantial portion of its
share of the energy from the South Texas Project, it currently remains obligated
to sell 15% of its share of installed generation capacity from the South Texas
Project and related ancillary services pursuant to PUC-mandated auctions. In
these auctions, Texas Genco will be required to sell firm entitlements on a
forward basis to capacity and ancillary services dispatched within specified
operational constraints. In addition to its capacity auctions, Texas Genco may
from time to time sell any excess capacity or energy generated by the South
Texas Project forward on a firm or interruptible basis. Accordingly,
unanticipated unit outages or other problems with the South Texas Project could
result in Texas Genco's firm capacity and ancillary services commitments under
its future capacity auctions or other future sales exceeding its available
generation capacity. As a result, an unexpected outage at the South Texas
Project could require Texas Genco to obtain replacement power from third parties

in the open market in order to satisfy its obligations. The cost of any such
replacement power would likely exceed the cost of generating power at the South
Texas Project.

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 associated with
future sales depend, in part, upon prevailing market prices for electricity in
the ERCOT market. Market prices for electricity, generation capacity, energy and
ancillary services may fluctuate substantially. The gross margins generated by
Texas Genco's future sales will be directly impacted by natural gas prices.
Because the South Texas Project's fuel costs are largely fixed under 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. As a result, the price customers are
willing to pay for entitlements to Texas Genco's future capacity not sold
forward under the back-to-back power purchase agreement will generally rise and
fall 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 or other 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.

IF THE SALE OF TEXAS GENCO TO TEXAS GENCO LLC IS NOT COMPLETED, TEXAS GENCO
MAY BE OBLIGATED TO PAY LIQUIDATED DAMAGES TO TEXAS GENCO LLC RELATING TO
COSTS INCURRED BY TEXAS GENCO LLC AS A RESULT OF ENERGY FROM THE SOUTH TEXAS
PROJECT BEING UNAVAILABLE AND THE PRICING OF ENERGY TEXAS GENCO SELLS UNDER
THE BACK-TO-BACK POWER PURCHASE AGREEMENT WILL BE REDUCED IN THE FUTURE.

During the period from December 15, 2004 until the closing of the sale of
Texas Genco to Texas Genco LLC, the price for the energy sold by Texas Genco
under the back-to-back power purchase agreement will be the weighted-average
price achieved by Texas Genco LLC on its firm forward sales in the South ERCOT
zone. However, in the event the sale does not close, Genco LP will be obligated
to pay Texas Genco LLC 50% of the economic cost (i.e. liquidated damages payable
to third parties or cost of cover) Texas Genco LLC incurs as a result of energy
from the South Texas Project being unavailable to meet the contract quantity
during the period from December 15, 2004 to the termination of the agreement
governing the sale of Texas Genco. In addition, after any termination of this
sale agreement, the pricing for the energy sold under the back-to-back power
purchase agreement will be 90% of such weighted-average price, with no
contingent payment for economic costs. The sale agreement may be terminated
under various circumstances, including a failure to close the second step of the
sale transaction by April 30, 2005 (which date may be extended by either party
for up to two consecutive 90-day periods if NRC approval has not yet been
obtained or is being

contested and all other closing conditions are capable of being satisfied). We
currently expect to obtain NRC approval in the first half of 2005.

THERE COULD BE A SIGNIFICANT DISRUPTION IN TEXAS GENCO'S OPERATIONS IF TEXAS
GENCO LLC FAILS TO PERFORM ITS OBLIGATIONS UNDER THE SERVICES AGREEMENT.

In connection with the sale of Texas Genco's fossil generation assets to
Texas Genco LLC, Genco LP entered into a services agreement with Texas Genco LLC
under which Texas Genco LLC has agreed to, among other things, provide energy
scheduling services to Genco LP, administer Genco LP's PUC-mandated capacity
auctions and administer Genco LP's energy sales transactions. In the event Texas
Genco LLC fails to perform its obligations under the services agreement or the
services agreement is terminated, Texas Genco will be required to engage another
service provider or develop the infrastructure to resume the functions being
performed by Texas Genco LLC under the services agreement. If Texas Genco is
unable to do so, there could be a significant disruption in its operations.

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

The South Texas Project is owned as a tenancy in common among Genco LP and
other co-owners. Each co-owner has an undivided ownership interest in the two
nuclear-fueled generating units and the electrical output from those units.
Genco LP currently owns a 30.8% interest in the South Texas Project and
currently bears a corresponding 30.8% share of the capital and operating costs
associated with the project. This interest is subject to increase by up to an
additional 25.2% pursuant to Texas Genco's exercise of its right of first
refusal as described under "Our Business -- Discontinued Operations -- Texas
Genco -- Right of First Refusal." This purchase may occur prior to the
completion of the sale of Texas Genco to Texas Genco LLC. Genco LP and the other
co-owners have organized the STP Nuclear Operating Company (STPNOC) to operate
and maintain the South Texas Project. STPNOC is managed by a board of directors
composed of one director appointed by each of the co-owners, along with the
chief executive officer of STPNOC. The ownership of an interest in and operation
of the South Texas Project are subject to various risks, any of which could
adversely affect Texas Genco's revenues, costs, results of operations, financial
condition and cash flows. 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;

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

- breakdown or failure of equipment or processes;

- operating performance below expected levels of output or efficiency;

- 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;

- governmental action, including on a preemptive basis;

- violations of permit limitations;

- operator error; and

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

The South Texas Project may require significant capital expenditures to
keep it operating at high efficiency and to meet regulatory requirements and 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.

THE POWER GENERATED BY THE SOUTH TEXAS PROJECT IS TRANSMITTED THROUGH POWER
TRANSMISSION AND DISTRIBUTION FACILITIES THAT TEXAS GENCO DOES NOT OWN OR
CONTROL. IF TRANSMISSION SERVICE IS DISRUPTED DUE TO A FORCE MAJEURE EVENT,
TEXAS GENCO LLC WILL NOT BE OBLIGATED TO PURCHASE POWER FROM GENCO LP UNDER
THE BACK-TO-BACK POWER PURCHASE AGREEMENT DURING THE COURSE OF SUCH OUTAGE.

The power generated by the South Texas Project is transmitted through
transmission and distribution facilities owned and operated by CenterPoint
Houston and by others. If transmission service is disrupted due to a force
majeure event, Texas Genco LLC will not be obligated to purchase power from
Genco LP under the back-to-back power purchase agreement during the course of
such outage, which would adversely impact Texas Genco's results of operations,
financial condition and cash flows.

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

The South Texas Project satisfies its fuel supply requirements by acquiring
uranium concentrates, converting uranium concentrates into uranium hexafluoride,
enriching uranium hexafluoride, and fabricating nuclear fuel assemblies under a
number of contracts covering a portion of the fuel requirements of the South
Texas Project for uranium, conversion services, enrichment services and fuel
fabrication. Other than a fuel fabrication agreement that extends for the life
of the South Texas Project, these contracts have varying expiration dates, and
most are short to medium term (less than seven years). We believe that
sufficient capacity for nuclear fuel supplies and processing currently exists to
permit normal operations of the South Texas Project's nuclear powered generating
units, however, any disruption in fuel supplies or processing services could
adversely affect Texas Genco's results of operations, financial condition and
cash flows.

TEXAS GENCO'S OPERATIONS ALSO ARE SUBJECT TO EXTENSIVE REGULATION, INCLUDING
ENVIRONMENTAL REGULATIONS. 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. 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.

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 were to fail
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.

STPNOC 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 STPNOC fails to obtain and
comply with them, it may not be able to operate the South Texas Project or it
may be required to incur additional costs. Texas Genco is generally responsible
for its proportionate share of on-site liabilities associated with the
environmental condition of the South Texas Project, regardless of when the
liabilities arose and whether the liabilities are known or unknown. These
liabilities may be substantial.

RISK FACTORS ASSOCIATED WITH OUR CONSOLIDATED FINANCIAL CONDITION

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

As of December 31, 2004, we had $9.0 billion of outstanding indebtedness on
a consolidated basis. As of March 7, 2005, approximately $1.9 billion principal
amount of this debt must be paid through 2006, excluding principal repayments of
approximately $101 million on transition bonds. The success of our future
financing efforts may depend, at least in part, on:

- the timing and amount of our recovery of the true-up components and our
ability to monetize our remaining interest 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 RRI in connection with its indemnification obligations
arising in connection with its separation from us;

- provisions of relevant tax and securities laws; and

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

As of March 1, 2005, our CenterPoint Houston subsidiary had $3.3 billion
principal amount of general mortgage bonds outstanding and $253 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 $500 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, 2004, CenterPoint Houston has agreed
under the $1.3 billion collateralized term loan maturing in November 2005 to not
issue, subject to certain exceptions, more than $200 million of any incremental
secured or unsecured debt. In addition, CenterPoint Houston is contractually
prohibited, subject to certain exceptions, from issuing additional first
mortgage bonds. CenterPoint Houston's $1.3 billion credit facility requires that
proceeds from the issuance of transition bonds and certain new net indebtedness
for borrowed money issued by CenterPoint Houston in excess of $200 million be
used to repay borrowings under such facility.

Our capital structure and liquidity will be affected significantly by the
securitization of approximately $1.8 billion of costs authorized for recovery in
our proceeding regarding the transition to competitive retail markets in Texas.
In addition, we will receive an additional $700 million from the sale of Texas
Genco and its remaining operations, which is scheduled to occur in the first
half of 2005 but remains subject to various conditions, including approval of
the NRC.

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.

IF THE SALE OF CENTERPOINT ENERGY'S INTEREST IN TEXAS GENCO TO TEXAS GENCO LLC
DOES NOT CLOSE, CENTERPOINT ENERGY MAY PURSUE OTHER MEANS FOR MONETIZING ITS
REMAINING INTEREST IN TEXAS GENCO AND NO ASSURANCE CAN BE GIVEN THAT SUCH
EFFORTS WOULD BE SUCCESSFUL.

On December 15, 2004, Texas Genco completed the sale of its fossil
generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for
$2.813 billion in cash, of which $2.231 billion was distributed to CenterPoint
Energy. The sale was part of the first step of the transaction previously
announced in July 2004 in which Texas Genco LLC (formerly known as GC Power
Acquisition LLC), an entity owned in equal parts by affiliates of The Blackstone
Group, Hellman & Friedman LLC, Kohlberg Kravis Roberts & Co. L.P. and Texas
Pacific Group, agreed to acquire Texas Genco for approximately $3.65 billion in
cash. The second step of the transaction, in which Texas Genco is expected to
merge with a subsidiary of Texas Genco LLC in exchange for an additional cash
payment to CenterPoint Energy of $700 million, is expected to close during the
first half of 2005 following receipt of approval from the NRC. The closing of
the second step of the overall sale transaction is subject to various closing
conditions, including receipt of approval from the NRC. If the conditions are
not satisfied and the second step does not close, CenterPoint Energy will not
receive the $700 million it currently expects Texas Genco LLC to pay as
consideration for CenterPoint Energy's interest in Texas Genco. In such an
event, CenterPoint Energy may pursue other means for monetizing its remaining
interest in Texas Genco and no assurance can be given that such efforts would be
successful.

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 all our operating income from, and hold 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
AND EARNINGS.

As of December 31, 2004, we had $1.5 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.

THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL
COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR
RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES.

We and our subsidiaries use derivative instruments, such as swaps, options,
futures and forwards, to manage our commodity and financial market risks. We and
our subsidiaries could recognize financial losses as a result of volatility in
the market values of these contracts, or if a counterparty fails to perform. In
the absence of actively quoted market prices and pricing information from
external sources, the valuation of these financial instruments can involve
management's judgment or use of estimates. As a result, changes in the
underlying assumptions or use of alternative valuation methods could affect the
reported fair value of these contracts.

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,
Incorporated directly or through subsidiaries and include:

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

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

In connection with the organization and capitalization of RRI, RRI and its
subsidiaries assumed liabilities associated with various assets and businesses
transferred to them. RRI 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 RRI and its subsidiaries for all liabilities
associated with the current and historical businesses and operations of RRI,
regardless of the time those liabilities arose. If RRI is unable to satisfy a
liability that has been so assumed in circumstances in which Reliant Energy,
Incorporated has not been released from the liability in connection with the
transfer, we or CenterPoint Houston could be responsible for satisfying the
liability.

RRI reported in its Annual Report on Form 10-K for the year ended December
31, 2004 that as of December 31, 2004 it had $5.2 billion of total debt and its
unsecured debt ratings are currently below investment grade. If RRI were unable
to meet its obligations, it would need to consider, among various options,
restructuring under the bankruptcy laws, in which event RRI might not honor its
indemnification obligations and claims by RRI's creditors might be made against
us as its former owner.

Reliant Energy, Incorporated and RRI 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 RRI, claims against Reliant Energy, Incorporated have been
made on grounds that include the effect of RRI's financial results on Reliant
Energy, Incorporated's historical financial statements and liability of Reliant
Energy, Incorporated as a controlling shareholder of RRI. 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
RRI were determined to be unavailable or if RRI 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, Incorporated 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. In connection with the sale of Texas Genco's fossil
generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the
separation agreement we entered into with Texas Genco in connection with the
organization and capitalization of Texas Genco was amended to provide that all
of Texas Genco's rights and obligations under the separation agreement relating
to its fossil generation assets, including Texas Genco's obligation to indemnify
us with respect to liabilities associated with the fossil generation assets and
related business, were assigned to and assumed by Texas Genco LLC. In addition,
under the amended separation agreement, Texas Genco is no longer liable for, and
CenterPoint Energy has assumed and agreed to indemnify Texas Genco LLC against,
liabilities that Texas Genco originally assumed in connection with its
organization to the extent, and only to the extent, that such liabilities are
covered by certain insurance policies or other similar agreements held by
CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a
liability that had been so assumed or indemnified against, and provided Reliant
Energy, Incorporated had not been released from the liability in connection with
the transfer, CenterPoint Houston could be responsible for satisfying the
liability.

WE, TOGETHER WITH OUR SUBSIDIARIES, 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 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 affiliated service, sales and
construction contracts.

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.
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.

We must seek a new financing order under the 1935 Act for approval of our
post-June 30, 2005 financing activities before the current financing order
expires on June 30, 2005. If we are unable to obtain a new financing order, we
would generally be unable to engage in any financing transactions, including the
refinancing of existing obligations after June 30, 2005.

If our earnings for subsequent quarters are insufficient to pay dividends
from current earnings, additional authority would be required from the SEC for
payment of the quarterly dividend from capital or unearned surplus, but there
can be no assurance that the SEC would authorize such payments.

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.

Texas Genco and the other owners of the South Texas Project maintain
nuclear property and nuclear liability insurance coverage as required by law and
periodically review available limits and coverage for additional protection. The
owners of the South Texas Project currently maintain $2.75 billion in property
damage insurance coverage, which is above the legally required minimum, but is
less than the total amount of insurance currently available for such losses.
Under the federal Price Anderson Act, the maximum liability to the public of
owners of nuclear power plants was $10.8 billion as of December 31, 2004. 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 11(c) to our consolidated financial statements,
which information is incorporated herein by reference.

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 amount of our recovery of the true-up components;

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

- state and federal legislative and regulatory actions or developments,
including deregulation, re-regulation, 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;

- 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 financing 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 RRI;

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

- the ability of RRI to satisfy its obligations to us, including indemnity
obligations;

- our ability to control costs;

- the investment performance of our employee benefit plans;

- our internal restructuring or other restructuring options that may be
pursued;

- our potential business strategies, including acquisitions or dispositions
of assets or businesses, which cannot be assured to be completed or
beneficial to us; and

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

MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF
OPERATIONS

OTHER SIGNIFICANT MATTERS

Pension Plan. As discussed in Note 9(b) to our consolidated financial
statements, we maintain a non-contributory pension plan covering substantially
all employees. Employer contributions are based on actuarial computations that
establish the minimum contribution required under the Employee Retirement Income
Security Act of 1974 (ERISA) and the maximum deductible contribution for income
tax purposes. At December 31, 2004, the projected benefit obligation exceeded
the market value of plan assets by $53 million; however, the market value of the
plan assets exceeded the accumulated benefit obligation by $22 million. Changes
in interest rates and the market values of the securities held by the plan
during 2005 could materially, positively or negatively, change our funded status
and affect the level of pension expense and required contributions in 2006 and
beyond.

In connection with the sale of our 81% interest in Texas Genco, a separate
pension plan was established for Texas Genco on September 1, 2004 and we
transferred a net pension liability of approximately $68 million to Texas Genco.
In October 2004, Texas Genco received an allocation of assets from our pension
plan pursuant to rules and regulations under ERISA.

During 2003 and 2004, we have not been required to make contributions to
our pension plan. We have made voluntary contributions of $23 million and $476
million in 2003 and 2004, respectively.

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

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

Pension costs were $35 million, $90 million and $80 million for 2002, 2003
and 2004, respectively. For 2002, a pension benefit of $4 million was recorded
related to RRI's participants. Pension benefit for RRI's participants is
reflected in the Statement of Consolidated Operations as discontinued
operations. In addition, included in the costs for 2002, 2003 and 2004 are $15
million, $17 million and $11 million, respectively, of expense related to Texas
Genco participants. Pension expense for Texas Genco participants is reflected in
the Statement of Consolidated Operations as discontinued operations.

Additionally, we maintain a non-qualified benefit restoration plan which
allows participants to retain the benefits to which they would have been
entitled under our non-contributory pension plan except for the federally
mandated limits on qualified plan benefits or on the level of compensation on
which qualified plan benefits may be calculated. The expense associated with
this non-qualified plan was $9 million, $8 million and $6 million in 2002, 2003
and 2004, respectively. Included in the cost for 2002 is $3 million of expense
related to RRI's participants, which is reflected in discontinued operations in
the Statements of Consolidated Operations.

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

As of December 31, 2004, the expected long-term rate of return on plan
assets was 8.5%, a reduction from the 9.0% rate assumed as of December 31, 2003.
We believe that our actual asset allocation, on average, will approximate the
targeted allocation and the estimated return on net assets. We regularly review
our actual asset allocation and periodically rebalance plan assets as
appropriate.

As of December 31, 2004, the projected benefit obligation was calculated
assuming a discount rate of 5.75%, which is a 0.5% decline from the 6.25%
discount rate assumed in 2003. The discount rate was determined by reviewing
yields on high-quality bonds that receive one of the two highest ratings given
by a recognized rating agency and the expected duration of pension obligations
specific to the characteristics of our plan.

Pension expense for 2005, including the benefit restoration plan, is
estimated to be $37 million based on an expected return on plan assets of 8.5%
and a discount rate of 5.75% as of December 31, 2004. If the expected return
assumption were lowered by 0.5% (from 8.5% to 8.0%), 2005 pension expense would
increase by approximately $8 million.

Due to significant funding that occurred during 2004, pension plan assets
(excluding the unfunded benefit restoration plan) exceed the accumulated benefit
obligation, which enabled us to reverse a charge to comprehensive income of $350
million, net of tax. However, if the discount rate were lowered by 0.5% (from
5.75% to 5.25%), the assumption change would increase our projected benefit
obligation, accumulated benefit obligation and 2005 pension expense by
approximately $106 million, $100 million and $7 million, respectively. In
addition, the assumption change would have significant impacts on our
Consolidated Balance Sheet by changing the pension asset recorded as of December
31, 2004 of $610 million to a pension liability of $78 million, offset by a
charge to comprehensive income in 2004 of $447 million, net of tax.

For the benefit restoration plan, if the discount rate were lowered by 0.5%
(from 5.75% to 5.25%), the assumption change would increase our projected
benefit obligation, accumulated benefit obligation and 2005 pension expense by
approximately $4 million, $3 million, and less than $1 million, respectively. In
addition, the assumption change would result in a charge to comprehensive income
of approximately $2 million.

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

In October 2004, the American Jobs Creation Act (AJCA) was signed into law.
The AJCA made significant changes in the taxation of nonqualified deferred
compensation with new Code Section 409A. Non-compliance with Section 409A can
result in increased federal income taxes on nonqualified deferred compensation
for employees. We are currently analyzing the impact of Section 409A and related
guidance issued by the Treasury Department and the Internal Revenue Service, on
our non-qualified plans and agreements that provide for deferred compensation.
Such plans or agreements may require amendment or modification to comply with
the new law.

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) 2003 2004
---------------- ------ ------
(IN MILLIONS)

Electric transmission & distribution................. 5-75 $6,085 $6,245
Natural gas distribution............................. 5-50 2,316 2,494
Pipelines and gathering.............................. 5-75 1,722 1,767
Other property....................................... 3-40 446 457
------ ------
Total.............................................. 10,569 10,963
Accumulated depreciation and amortization............ (2,484) (2,777)
------ ------
Property, plant and equipment, net.............. $8,085 $8,186
====== ======
</Table>

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

<Table>
<Caption>
DECEMBER 31, 2003 DECEMBER 31, 2004
----------------------- -----------------------
CARRYING ACCUMULATED CARRYING ACCUMULATED
AMOUNT AMORTIZATION AMOUNT AMORTIZATION
-------- ------------ -------- ------------
(IN MILLIONS)

Land Use Rights............................ $55 $(12) $55 $(12)
Other...................................... 20 (4) 21 (6)
--- ---- --- ----
Total.................................... $75 $(16) $76 $(18)
=== ==== === ====
</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, 2004 other than goodwill discussed below. 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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

Amortization expense for other intangibles for 2002, 2003 and 2004 was $2
million in each year. Estimated amortization expense for the five succeeding
fiscal years is as follows (in millions):

<Table>

2005........................................................ $ 2
2006........................................................ 2
2007........................................................ 3
2008........................................................ 3
2009........................................................ 3
---
Total..................................................... $13
===
</Table>

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

<Table>
<Caption>
DECEMBER 31,
2003 AND 2004
-------------

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

The Company completed its annual evaluation of goodwill for impairment as
of January 1, 2004 and no impairment was indicated.

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.

As a result of the Company's decision to sell its interest in Texas Genco
in July 2004, the Company recorded an after-tax loss of approximately $253
million in the third quarter of 2004. In the fourth quarter of 2004, the Company
reduced the expected loss on the sale of its interest in Texas Genco by $39
million to $214 million. For further discussion, see Note 3.

(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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

The following is a list of regulatory assets/liabilities reflected on the
Company's Consolidated Balance Sheets as of December 31, 2003 and 2004:

<Table>
<Caption>
DECEMBER 31,
---------------
2003 2004
------ ------
(IN MILLIONS)

Recoverable electric generation-related regulatory assets... $3,226 $1,946
Securitized regulatory asset................................ 682 647
Unamortized loss on reacquired debt......................... 80 80
Estimated removal costs..................................... (647) (677)
Other long-term regulatory assets/liabilities............... 46 47
------ ------
Total..................................................... $3,387 $2,043
====== ======
</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. During 2004, the Company
wrote-off net regulatory assets of $1.5 billion in response to the Texas Utility
Commission's order on CenterPoint Houston's final true-up application. For
further discussion of regulatory assets, see Note 4.

The Company's rate-regulated businesses recognize removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2003 and 2004, these removal costs of $647 million and $677
million, respectively, are classified as regulatory liabilities in the
Consolidated Balance Sheets. The Company has also identified other asset
retirement obligations that cannot be estimated because the assets associated
with the retirement obligations have an indeterminate life.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(4) REGULATORY MATTERS

(a) 2004 TRUE-UP PROCEEDING

In March 2004, CenterPoint Houston filed the final true-up application
required by the Texas electric restructuring law with the Public Utility
Commission of Texas (Texas Utility Commission) (2004 True-Up Proceeding).
CenterPoint Houston's requested true-up balance was $3.7 billion, excluding
interest and net of the retail clawback from RRI described below. In June, July
and September 2004, the Texas Utility Commission conducted hearings on, and held
public meetings addressing, CenterPoint Houston's true-up application. In
December 2004, the Texas Utility Commission approved a final order in
CenterPoint Houston's true-up proceeding (2004 Final Order) authorizing
CenterPoint Houston to recover $2.3 billion including interest through August
31, 2004, subject to adjustments to reflect the benefit of certain deferred
taxes and the accrual of interest and payment of excess mitigation credits after
August 31, 2004. As a result of the 2004 Final Order, the Company wrote-off net
regulatory assets of $1.5 billion and recorded a related income tax benefit of
$526 million, resulting in an after-tax charge of $977 million, which is
reflected as an extraordinary loss in the Company's Statements of Consolidated
Operations. The Company recorded an expected loss of $894 million in the third
quarter of 2004 and increased this amount by $83 million in the fourth quarter
of 2004 based on the Company's assessment of the amounts ultimately recoverable.
In January 2005, CenterPoint Houston appealed certain aspects of the final order
seeking to increase the true-up balance ultimately recovered by CenterPoint
Houston. Other parties have also appealed the order, seeking to reduce the
amount authorized for CenterPoint Houston's recovery. Although CenterPoint
Houston believes it has

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

meritorious arguments and that the other parties' appeals are without merit, no
prediction can be made as to the ultimate outcome or timing of such appeals.

The Company has recorded as a regulatory asset a return of $374 million on
the true-up balance for the period from January 1, 2002 through December 31,
2004 as allowed by the Texas Utility Commission's 2004 Final Order. The Company,
under the 2004 Final Order, will continue to accrue a return until the true-up
balance is recovered by the Company, either from rate payers or through a
securitization offering as discussed below. The rate of return is based on
CenterPoint Houston's cost of capital, established in the Texas Utility
Commission's final order issued in October 2001 (2001 Final Order), which is
derived from CenterPoint Houston's cost to finance assets and an allowance for
earnings on shareholders' investment. Accordingly, in accordance with SFAS No.
92, "Regulated Enterprises -- Accounting for Phase-in Plans." the rate of return
has been bifurcated into components representing a return of costs to finance
assets and an allowance for earnings on shareholders' investment. The component
representing a return of costs to finance assets of $226 million has been
recognized in the fourth quarter of 2004 and is included in other income in the
Company's Statements of Consolidated Operations. The component representing a
return of costs to finance assets will continue to be recognized as earned going
forward. The component representing an allowance for earnings on shareholders'
investment of $148 million has been deferred and will be recognized as it is
collected through rates in the future.

In November 2004, RRI paid $177 million to the Company, representing the
"retail clawback" determined by the Texas Utility Commission in the 2004 True-Up
Proceeding. The Texas electric restructuring law requires the Texas Utility
Commission to determine the retail clawback if the formerly integrated utility's
affiliated retail electric provider retained more than 40 percent of its
residential price-to-beat customers within the utility's service area as of
January 1, 2004 (offset by new customers added outside the service territory).
That retail clawback is a credit against the stranded costs the utility is
entitled to recover and was reflected in the $2.3 billion recovery authorized.
Under the terms of a master separation agreement between RRI and the Company,
RRI agreed to pay the Company the amount of the retail clawback determined by
the Texas Utility Commission. The payment was used by the Company to reduce
outstanding indebtedness.

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 solely out of funds from non-bypassable transition
charges.

In December 2004, CenterPoint Houston filed for approval of a financing
order to issue transition bonds to securitize its true-up balance. On March 9,
2005, the Texas Utility Commission issued a financing order allowing CenterPoint
Houston to securitize approximately $1.8 billion and requiring that the benefit
of certain deferred taxes be reflected as a reduction in the competition
transition charge. The Company anticipates that a new special purpose subsidiary
of CenterPoint Houston will issue bonds in one or more series through an
underwritten offering. Depending on market conditions and the impact of possible
appeals of the financing order, among other factors, the Company anticipates
completing such an offering in 2005.

In January 2005, CenterPoint Houston filed an application for a competition
transition charge to recover its true-up balance. CenterPoint Houston will
adjust the amount sought through that charge to the extent that it is able to
securitize any of such amount. Under the Texas Utility Commission's rules, the
unrecovered true-up balance to be recovered through the competition transition
charge earns a return until fully recovered.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In the 2001 Final Order, the Texas Utility Commission established the
transmission and distribution rates that became effective in January 2002. Based
on its 2001 revision of the 1998 stranded cost estimates, 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 1998
transition plan and the Texas electric restructuring law. In the 2001 Final
Order, CenterPoint Houston was required to reverse the amount of redirected
depreciation and accelerated depreciation taken for regulatory purposes as
allowed under the 1998 transition plan and the Texas electric restructuring law.
In accordance with the 2001 Final Order, CenterPoint Houston recorded a
regulatory liability to reflect the prospective refund of the accelerated
depreciation, and in January 2002 CenterPoint Houston began paying excess
mitigation credits, which were to be paid over a seven-year period with interest
at 7 1/2% per annum. The annual payment of excess mitigation credits is
approximately $264 million. In its December 2004 final order in the 2004 True-Up
Proceeding, the Texas Utility Commission found that CenterPoint Houston did, in
fact, have stranded costs (as originally estimated in 1998). Despite this
ruling, the Texas Utility Commission denied CenterPoint Houston recovery of
approximately $180 million of the interest portion of the excess mitigation
credits already paid by CenterPoint Houston and refused to terminate future
excess mitigation credits. In January 2005, CenterPoint Houston filed a writ of
mandamus petition with the Texas Supreme Court asking that court to order the
Texas Utility Commission to terminate immediately the payment of all excess
mitigation credits and to ensure full recovery of all excess mitigation credits.
Although CenterPoint Houston believes it has meritorious arguments, a writ of
mandamus is an extraordinary remedy and no prediction can be made as to the
ultimate outcome or timing of the mandamus petition. If the Supreme Court denies
CenterPoint Houston's mandamus petition, it will continue to pursue this issue
through regular appellate mechanisms. On March 1, 2005, a non-unanimous
settlement was filed in Docket No. 30774, which involves the adjustment of RRI's
Price-to-Beat. Under the terms of that settlement, the excess mitigation credits
being paid by CenterPoint Houston would be terminated as of April 29, 2005. The
Texas Utility Commission approved the settlement on March 9, 2005.

(b) FINAL FUEL RECONCILIATION

On March 4, 2004, an Administrative Law Judge (ALJ) issued a Proposal for
Decision (PFD) relating to CenterPoint Houston's final fuel reconciliation.
CenterPoint Houston reserved $117 million, including $30 million of interest, in
the fourth quarter of 2003 reflecting the ALJ's recommendation. On April 15,
2004, the Texas Utility Commission affirmed the PFD's finding in part, reversed
in part, and remanded one issue back to the ALJ. On May 28, 2004, the Texas
Utility Commission approved a settlement of the remanded issue and issued a
final order which reduced the disallowance. As a result of the final order, the
Company reversed $23 million, including $8 million of interest, of the $117
million reserve recorded in the fourth quarter of 2003. The results of the Texas
Utility Commission's final decision are a component of the 2004 True-Up
Proceeding. The Company has appealed certain portions of the Texas Utility
Commission's final order involving a disallowance of approximately $67 million
relating to the final fuel reconciliation plus interest of $10 million. Briefs
on this issue were filed on January 5, 2005, and a hearing on this issue is
scheduled for April 22, 2005.

In 2004, the City of Houston, 28 other cities and the Railroad Commission
of Texas (Railroad Commission) approved a settlement that increased Houston Gas'
base rate and service charge revenues by approximately $14 million annually.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

In July 2004, the LPSC approved a settlement that increased Southern Gas
Operations' base rate and service charge revenues in its North Louisiana
Division by approximately $7 million annually.

In December 2004, the Oklahoma Corporation Commission approved a settlement
that increased Southern Gas Operations' base rate and service charge revenues by
approximately $3 million annually.

(d) CITY OF TYLER, TEXAS DISPUTE

In July 2002, the City of Tyler, Texas, asserted that Southern Gas
Operations had overcharged residential and small commercial customers in that
city for gas costs under supply agreements in effect since 1992. That dispute
has been referred to the Railroad Commission by agreement of the parties for a
determination of whether Southern Gas Operations has properly charged and
collected for gas service to its residential and commercial customers in its
Tyler distribution system in accordance with lawful filed tariffs during the
period beginning November 1, 1992, and ending October 31, 2002. In December
2004, the Railroad Commission conducted a hearing on the matter and is expected
to issue a ruling in March or April of 2005. In a parallel action now in the
Court of Appeals in Austin, Southern Gas Operations is challenging the scope of
the Railroad Commission's inquiry which goes beyond the issue of whether
Southern Gas Operations had properly followed its tariffs to include a review of
Southern Gas Operations' historical gas purchases. The Company believes such a
review is not permitted by law and is beyond what the parties requested in the
joint petition that initiated the proceeding at the Railroad Commission. The
Company believes that all costs for Southern Gas Operations' Tyler distribution
system have been properly included and recovered from customers pursuant to
Southern Gas Operations' filed tariffs.

(5) DERIVATIVE INSTRUMENTS

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 in 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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 2004, hedge ineffectiveness of $0.4 million was recognized in
earnings from derivatives that are designated and qualify as Cash Flow Hedges,
and in 2003 and 2002, no hedge ineffectiveness was recognized. 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 "Natural Gas."
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, 2004, the Company expects $5
million in accumulated other comprehensive income 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.

Other Derivative Financial Instruments. The Company also has natural gas
contracts which are derivatives which are not hedged. Load following services
that the Company offers its natural gas customers create an inherent tendency to
be either long or short natural gas supplies relative to customer purchase
commitments. The Company measures and values all of its volumetric imbalances on
a real time basis to minimize its exposure to commodity price and volume risk.
The aggregate Value at Risk (VaR) associated with these operations is calculated
daily and averaged $0.2 million with a high of $1 million during 2004. The
Company does not engage in proprietary or speculative commodity trading.
Unhedged positions are accounted for by adjusting the carrying amount of the
contracts to market and recognizing any gain or loss in operating income, net.
During 2004, the Company recognized net gains related to unhedged positions
amounting to $7 million and as of December 31, 2004 had recorded short-term risk
management assets and liabilities of $4 million and $5 million, respectively,
included in other current assets and other current liabilities, respectively.

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, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No.
133), and was marked to market in the Company's Consolidated Balance Sheets with
changes in market value reflected in interest expense in the Statements of
Consolidated Operations.

During 2002, the Company settled 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 is being amortized into
interest expense over the life of the designated fixed-rate debt. Amortization
of amounts deferred in accumulated other comprehensive income for 2003 and 2004
was $12 million and $25 million, respectively. As of December 31, 2004, the
Company expects $31 million in accumulated other comprehensive income to be
reclassified into net income during the next twelve months.

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 8), 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

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

balance sheet. The value of the contingent interest components was not material
at issuance or at December 31, 2004.

(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, 2003 and 2004
(in millions):

<Table>
<Caption>
DECEMBER 31, 2003 DECEMBER 31, 2004
------------------- ----------------------
INVESTMENT INVESTMENT
GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL(3)
----------- ----- ----------- --------

Energy marketers............................. $24 $35 $10 $17
Financial institutions....................... 21 21 50 50
Other........................................ -- 1 1 1
--- --- --- ---
Total...................................... $45 $57 $61 $68
=== === === ===
</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 $17 million non-trading derivative asset includes a $6 million asset due
to trades with Reliant Energy Services, Inc. (Reliant Energy Services), an
affiliate until the date of the RRI Distribution. As of December 31, 2004,
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.

(6) 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).
The Company currently owns 21.6 million shares of 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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(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, 2004, ZENS having an original principal amount of
$840 million and a contingent principal amount of $851 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, 2004, the market value of such shares was
approximately $421 million, which would provide an exchange amount of $476 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.

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

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 through 2004. In connection with the
exchanges, 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. 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 2002, 2003 and 2004, the Company
recorded a loss of $500 million, a gain of $106 million and a gain of $31
million, respectively, on the Company's investment in TW Common. During 2002,
2003 and 2004, the Company recorded a gain of $480 million, a loss of $96
million and a loss of $20 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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 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
Accretion of debt component of ZENS.................. -- 2 --
Loss on indexed debt securities...................... -- -- 20
Gain on TW Common.................................... 31 -- --
----- ---- -----
Balance at December 31, 2004......................... $ 421 $107 $ 341
===== ==== =====
</Table>

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(9) 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. Participants are 100% vested in their benefit after
completing five years of service.

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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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

<Table>
<Caption>
YEAR ENDED DECEMBER 31,
---------------------------------------------------------------------------------
2002 2003 2004
------------------------- ------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- -------------- -------- --------------
(IN MILLIONS)

Service cost................ $ 32 $ 5 $ 37 $ 4 $ 40 $ 4
Interest cost............... 104 32 102 31 102 31
Expected return on plan
assets.................... (126) (13) (92) (11) (103) (13)
Net amortization............ 16 13 43 13 37 13
Curtailment................. -- -- -- -- -- 17
Benefit enhancement......... 9 3 -- -- 4 2
Settlement.................. -- (18) -- -- -- --
----- ---- ---- ---- ----- ----
Net periodic cost........... $ 35 $ 22 $ 90 $ 37 $ 80 $ 54
===== ==== ==== ==== ===== ====
Above amounts reflect the
following net periodic
cost (benefit) related to
discontinued operations... $ 11 $ (9) $ 17 $ 4 $ 11 $ 20
===== ==== ==== ==== ===== ====
</Table>

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

<Table>
<Caption>
DECEMBER 31,
---------------------------------------------------------------------------------
2002 2003 2004
------------------------- ------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- -------------- -------- --------------

Discount rate.................... 7.25% 7.25% 6.75% 6.75% 6.25% 6.25%
Expected return on plan assets... 9.5% 9.5% 9.0% 9.0% 9.0% 8.5%
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.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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, 2003 and 2004 for the Company's pension and
postretirement benefit plans:

<Table>
<Caption>
DECEMBER 31,
-----------------------------------------------------
2003 2004
------------------------- -------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
-------- -------------- -------- --------------
(IN MILLIONS)

CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of year............. $1,550 $ 479 $1,692 $ 518
Service cost...................................... 37 4 40 4
Interest cost..................................... 102 31 102 31
Participant contributions......................... -- 8 -- 6
Benefits paid..................................... (142) (43) (124) (42)
Plan amendments................................... 4 (5) -- (20)
Divestitures...................................... -- -- (165) --
Actuarial loss.................................... 141 44 161 36
Curtailment, benefit enhancement and settlement... -- -- 4 2
------ ----- ------ -----
Benefit obligation, end of year................... $1,692 $ 518 $1,710 $ 535
====== ===== ====== =====
CHANGE IN PLAN ASSETS
Plan assets, beginning of year.................... $1,054 $ 131 $1,194 $ 150
Employer contributions............................ 23 34 476 27
Participant contributions......................... -- 8 -- 6
Benefits paid..................................... (142) (43) (124) (42)
Divestitures...................................... -- -- (40) --
Actual investment return.......................... 259 20 151 15
------ ----- ------ -----
Plan assets, end of year.......................... $1,194 $ 150 $1,657 $ 156
====== ===== ====== =====
RECONCILIATION OF FUNDED STATUS
Funded status..................................... $ (498) $(368) $ (53) $(379)
Unrecognized actuarial loss....................... 733 63 714 96
Unrecognized prior service cost................... (71) 49 (51) 14
Unrecognized transition (asset) obligation........ -- 79 -- 65
------ ----- ------ -----
Net amount recognized............................. $ 164 $(177) $ 610 $(204)
====== ===== ====== =====
AMOUNTS RECOGNIZED IN BALANCE SHEETS
Benefit obligations............................... $ (395) $(177) $ 610 $(204)
Accumulated other comprehensive income............ 559 -- -- --
------ ----- ------ -----
Prepaid (accrued) benefit cost.................... $ 164 $(177) $ 610 $(204)
====== ===== ====== =====
</Table>

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

ACTUARIAL ASSUMPTIONS
Discount rate..................................... 6.25% 6.25% 5.75% 5.75%
Expected return on plan assets.................... 9.0% 8.5% 8.5% 8.0%
Rate of increase in compensation levels........... 4.1% -- 4.6% --
Healthcare cost trend rate assumed for the next
year............................................ -- 10.50% -- 9.75%
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>

<Table>
<Caption>
DECEMBER 31,
-------------------------------------------------------------
2003 2004
----------------------------- -----------------------------
PENSION POSTRETIREMENT PENSION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS
------------ -------------- ------------ --------------
(IN MILLIONS)

ADDITIONAL INFORMATION
Accumulated benefit obligation... $1,589 $518 $1,635 $535
Change in minimum liability
included in other comprehensive
income......................... (64) -- (559) --
Measurement date used to
determine plan obligations and
assets......................... December 31, December 31, December 31, December 31,
2003 2003 2004 2004
</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............. 39 33
</Table>

The following table displays the weighted-average asset allocations as of
December 31, 2003 and 2004 for the Company's pension and postretirement benefit
plans:

Domestic equity securities........................ 60% 41% 57% 34%
International equity securities................... 15 9 15 11
Debt securities................................... 22 48 26 54
Real estate....................................... 3 -- 2 --
Cash.............................................. -- 2 -- 1
--- --- --- ---
Total........................................... 100% 100% 100% 100%
=== === === ===
</Table>

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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.................................. 45-55% 28-38%
International equity securities............................. 7-13% 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 $44 million (3.7% of total pension plan assets) as of
December 31, 2003. The pension plan did not include any holdings of CenterPoint
Energy common stock as of December 31, 2004.

Although funding for the Company's pension and postretirement plans was not
required during 2004, the Company contributed $56 million to its pension plan in
September 2004 and $420 million in December 2004, which effectively brought the
Company's pension plan assets and accumulated benefit obligation into balance
and increased shareholders' equity by $350 million as a result of the
elimination of the related minimum benefit liability. Additionally, the Company
contributed $27 million to its postretirement benefits plan in 2004.

Contributions to the pension plan are not required in 2005; however, the
Company expects to make a contribution. The Company expects to contribute
approximately $29 million to its postretirement benefits plan in 2005.

The following benefit payments are expected to be paid by the pension and
postretirement benefit plans:

<Table>
<Caption>
PENSION POSTRETIREMENT
BENEFITS BENEFITS
-------- --------------
(IN MILLIONS)

2005........................................................ $108 $ 38
2006........................................................ 112 40
2007........................................................ 114 42
2008........................................................ 118 44
2009........................................................ 120 46
2010-2014................................................... 627 240
</Table>

In connection with the Company's sale of its 81% interest in Texas Genco as
discussed in Note 3, a separate pension plan was established for Texas Genco on
September 1, 2004 and the Company transferred a net pension liability of
approximately $68 million to Texas Genco. In October 2004, Texas Genco received
an allocation of assets from the Company's pension plan pursuant to rules and
regulations under the Employee Retirement Income Security Act of 1974.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 qualified plan benefits or on the level of compensation on which
qualified plan benefits may be calculated. The expense associated with this
non-qualified plan was $9 million, $8 million and $6 million in 2002, 2003 and
2004, respectively. Included in the net benefit cost in 2002 is $3 million of
expense related to RRI's participants, which is reflected in discontinued
operations in the Statements of Consolidated Operations. The accrued benefit
liability for the non-qualified pension plan was $75 million and $69 million at
December 31, 2003 and 2004, respectively. In addition, these accrued benefit
liabilities include the recognition of minimum liability adjustments of $15
million as of December 31, 2003 and $10 million as of December 31, 2004, which
are reported as a component of other comprehensive income, net of income tax
effects.

The following table displays the Company's plans that have or have had
accumulated benefit obligations in excess of plan assets:

<Table>
<Caption>
DECEMBER 31,
---------------------------------------------------------------------------------
2003 2004
--------------------------------------- ---------------------------------------
PENSION RESTORATION POSTRETIREMENT PENSION RESTORATION POSTRETIREMENT
BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS BENEFITS
-------- ----------- -------------- -------- ----------- --------------
(IN MILLIONS)

Accumulated benefit
obligation......... $1,589 $75 $518 $1,635 $69 $535
Projected benefit
obligation......... 1,692 77 518 1,710 81 535
Plan assets.......... 1,194 -- 150 1,657 -- 156
</Table>

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(11) COMMITMENTS AND CONTINGENCIES

(a) FUEL COMMITMENTS

Fuel commitments, excluding Texas Genco, include 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, 2004 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 natural gas supply contracts are
approximately $807 million in 2005, $401 million in 2006, $193 million in 2007,
$29 million in 2008 and $1 million in 2009.

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

(b) LEASE COMMITMENTS

The following table sets forth information concerning the Company's
obligations, excluding Texas Genco, under non-cancelable long-term operating
leases at December 31, 2004, which primarily consist of rental agreements for
building space, data processing equipment and vehicles (in millions):

<Table>

2005........................................................ $ 25
2006........................................................ 21
2007........................................................ 18
2008........................................................ 14
2009........................................................ 6
2010 and beyond............................................. 26
----
Total..................................................... $110
====
</Table>

Total lease expense for all operating leases was $36 million, $35 million
and $32 million during 2002, 2003 and 2004, respectively.

Legal Matters

RRI 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 the Company and
RRI, the Company and its subsidiaries are entitled to be indemnified by RRI 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, RRI 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,
several of which dismissals have been affirmed by the appellate courts, but most
of the lawsuits remain in early procedural stages. The Company's former
subsidiary, RRI, 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. RRI, 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 or its predecessor, Reliant Energy, have been named in
approximately 30 of these lawsuits, which were instituted between 2001 and 2004
and are pending in California state courts in Alameda County, Los Angeles
County, San Francisco County, San Mateo County and San Diego County, in Nevada
state court

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

in Clark County, in federal district courts in San Francisco, San Diego, Los
Angeles, Fresno, Sacramento and Nevada and before the Ninth Circuit Court of
Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not
participants 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 such remaining cases. On July 6, 2004 and on October 12,
2004, the Ninth Circuit affirmed the Company's removal to federal district court
of two electric cases brought by the California Attorney General and affirmed
the federal court's dismissal of these cases based upon the filed rate doctrine
and federal preemption.

Other Class Action Lawsuits. Fifteen class action lawsuits filed in May,
June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant
Energy have been consolidated in federal district court in Houston. RRI and
certain of its former and current executive officers are named as defendants.
The consolidated complaint also names RRI , Reliant Energy, the underwriters of
the initial public offering of RRI's common stock in May 2001 (RRI Offering),
and RRI's and Reliant Energy's independent auditors as defendants. The
consolidated amended complaint seeks monetary relief purportedly on behalf of
purchasers of common stock of Reliant Energy or RRI during certain time periods
ranging from February 2000 to May 2002, and purchasers of common stock that can
be traced to the RRI 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 RRI
Offering remain. In June 2004, the plaintiffs filed a motion for class
certification, which the court granted in February 2005. The defendants have
appealed the court's order certifying the class.

In February 2003, a lawsuit was filed by three individuals in federal
district court in Chicago against CenterPoint Energy and certain former officers
of RRI 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 artificially
inflate 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. The plaintiffs filed
an amended complaint in March 2004, which the defendants asked the court to
dismiss. On August 18, 2004, the court granted the defendants' motion to dismiss
with prejudice.

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. Two of the lawsuits have been dismissed without
prejudice. Reliant Energy and certain current and former members of its benefits
committee are the remaining defendants in the third lawsuit. That 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 of 1974. 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 complaint seeks monetary damages for losses
suffered on behalf of the plans and a putative class of plan participants whose
accounts held Reliant Energy or RRI securities, as well as restitution. In July
2004, another class action suit was filed in federal court on behalf of the
Reliant Energy Savings Plan and a class consisting of participants in that plan
against Reliant Energy and the Reliant Energy Benefits Committee. The
allegations and the relief sought in the new suit are substantially similar to
those in the previously pending suit; however, the new suit also alleges that
Reliant Energy and its Benefits Committee breached their fiduciary duties to the
Savings Plan and its participants by investing plan funds in

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Reliant Energy stock when Reliant Energy or its subsidiaries were allegedly
manipulating the California energy market. On October 14, 2004, the plaintiff
voluntarily dismissed the newly filed lawsuit.

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 set forth claims for breach of fiduciary duty, waste of corporate
assets, abuse of control and gross mismanagement. Specifically, the shareholder
plaintiff alleged that the defendants caused the Company to overstate its
revenues through so-called "round trip" transactions. The plaintiff also alleged
breach of fiduciary duty in connection with the spin-off of RRI and the RRI
Offering. The complaint sought monetary damages on behalf of the Company as well
as equitable relief in the form of a constructive trust on the compensation paid
to the defendants. The 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 second 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. 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 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 the plaintiffs.

Other Legal Matters

Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in
federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the
Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI,
Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of
other participants in the Electric Reliability Council of Texas (ERCOT) power
market. The plaintiff, a retail electricity provider with the ERCOT market,
alleged 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 sought damages in
excess of $500 million, exemplary damages, treble damages, interest, costs of
suit and attorneys' fees. The plaintiff's principal allegations had previously
been investigated by the Texas Utility Commission and found to be without merit.
In June 2004, the federal court dismissed the plaintiff's claims and in July
2004, the plaintiff filed a notice of appeal. The Company is vigorously
contesting the appeal. The ultimate outcome of this matter cannot be predicted
at this time.

In February 2005, Utility Choice Electric filed in federal court in
Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint
Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP
and a number of other participants in the ERCOT power market. The plaintiff, a
retail electricity provider with the ERCOT market, alleged that the defendants
conspired to illegally fix and artificially increase the price of electricity in
violation of state and federal antitrust laws, intentionally interfered with
prospective business relationships and contracts, and committed fraud and
negligent misrepresentation. The plaintiff's principal allegations had
previously been investigated by the Texas Utility Commission and found to be
without merit. The Company intends to vigorously defend the case. The ultimate
outcome of this matter cannot be predicted at this time.

Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton,
Galveston and Pasadena (Three Cities) filed suit in state district court in
Harris County, Texas 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

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involving the Three Cities' claims (but not the class of cities), the trial
court entered a judgment on the Three Cities' breach of contract claims for $1.7
million, including interest, plus an award of $13.7 million in legal fees. It
also decertified the class. 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 held that
all of the Three Cities' claims were barred by the jury's finding of laches, a
defense similar to the statute of limitations, due to the Three Cities' having
unreasonably delayed bringing their claims during the more than 30 years since
the alleged wrongs began. The court also held that the Three Cities were not
entitled to recover any attorneys' fees. The Three Cities filed a petition for
review to the Texas Supreme Court, which declined to hear the case. Thus, the
Three Cities' claims have been finally resolved in the Company's favor, but the
individual claims of the 45 cities remain pending in the same court.

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 brought 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. CERC and its
subsidiaries believe that there has been no systematic mismeasurement of gas and
that the suits are without merit. CERC does not expect that the ultimate outcome
will have a material impact on the financial condition or results of operations
of either the Company or CERC.

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 certain non-affiliated companies 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 with respect to rates charged to certain consumers of natural gas
in the State of Texas. Subsequently the plaintiffs added as defendants
CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company,
United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy
Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation
Group, Inc. The plaintiffs allege that defendants inflated the prices charged to
certain consumers of natural gas. In February 2003, a similar suit was filed in
state court in Caddo Parish, Louisiana against CERC with respect to rates
charged to a purported class of certain consumers of natural gas and gas service
in the State of Louisiana. In February 2004, another suit was filed in

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

state court in Calcasieu Parish, Louisiana against CERC seeking to recover
alleged overcharges for gas or gas services allegedly provided by Southern Gas
Operations to a purported class of certain consumers of natural gas and gas
service without advance approval by the LPSC. In October 2004, a similar case
was filed in district court in Miller County, Arkansas against the Company,
CERC, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company,
CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc.,
Mississippi River Transmission Corp. and other non-affiliated companies alleging
fraud, unjust enrichment and civil conspiracy with respect to rates charged to
certain consumers of natural gas in at least the states of Arkansas, Louisiana,
Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo
and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with
the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu
Parish cases have been stayed pending the resolution of the respective
proceedings by the LPSC. The plaintiffs in the Miller County case seek class
certification, but the proposed class has not been certified. In November 2004,
the Miller County case was removed to federal district court in Texarkana,
Arkansas. In February 2005, the Wharton County case was removed to federal
district court in Houston, Texas, and in March 2005, the plaintiffs in the
Wharton County case moved to dismiss the case and agreed not to refile the
claims asserted unless the Miller County case is not certified as a class action
or is later decertified. The range of relief sought by the plaintiffs in these
cases includes injunctive and declaratory relief, restitution for the alleged
overcharges, exemplary damages or trebling of actual damages, civil penalties
and attorney's fees. In these cases, the Company, CERC and their affiliates 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. The Company and CERC do not
anticipate that the outcome of these matters will have a material impact on the
financial condition or results of operations of either the Company or CERC.

Texas Genco Shareholder Litigation. On July 23, 2004, two plaintiffs, both
Texas Genco shareholders, filed virtually identical lawsuits in Harris County,
Texas district court. These suits, purportedly brought on behalf of holders of
Texas Genco common stock, name Texas Genco and each of that company's directors
as defendants. Both plaintiffs allege, among other things, self-dealing and
breach of fiduciary duty by the defendants in entering into the July 2004
agreement to sell Texas Genco. As part of their allegations of self-dealing,
both plaintiffs claim that the board of directors of Texas Genco is controlled
by CenterPoint Energy, that the defendants improperly concealed results of Texas
Genco's results of operations for the second quarter of 2004 until after the
transaction agreement was announced and that, in order to aid CenterPoint
Energy, the Texas Genco board only searched for acquirers who would offer
all-cash consideration. Plaintiffs seek to enjoin the transaction or,
alternatively, rescind the transaction and/or recover damages in the event that
the transaction is consummated. In August 2004, the cases were consolidated in
state district court in Harris County, Texas. Although the defendants continue
to deny liability, in February 2005, all parties entered into a Memorandum of
Understanding to settle the lawsuit based upon supplemental disclosures made by
Texas Genco and the extension of the deadline for the exercise of shareholder
dissenters' rights. The settlement is subject to the parties' preparation of a
stipulation of settlement and court approval of the settlement.

ENVIRONMENTAL MATTERS

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

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 Company believes the ultimate cost associated with resolving this
matter will not have a material impact on the financial condition or results of
operations of either the Company or CERC.

In addition to the Minnesota sites, the United States Environmental
Protection Agency and other regulators have investigated MGP sites that were
owned or operated by CERC or may have been owned by one of its former
affiliates. CERC has not been named by these agencies as a PRP for any of those
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. However, CERC believes it
is not liable as a former owner or operator of those sites under the
Comprehensive Environmental, Response, Compensation and Liability Act of 1980,
as amended, and applicable state statutes, and is vigorously contesting those
suits.

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.

Asbestos. A number of facilities owned by the Company contain significant
amounts of asbestos insulation and other asbestos-containing materials. The
Company or its subsidiaries have been named, along with numerous others, as a
defendant in lawsuits filed by a large number of individuals who claim injury
due to exposure to asbestos. Most claimants in such litigation have been workers
who participated in construction of various industrial facilities, including
power plants. Some of the claimants have worked at locations owned by the
Company, but most existing claims relate to facilities previously owned by the
Company but currently owned by Texas Genco LLC. The Company anticipates that
additional claims like those received may be

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED)

asserted in the future. Under the terms of the separation agreement between the
Company and Texas Genco, ultimate financial responsibility for uninsured losses
relating to these claims has been assumed by Texas Genco, but under the terms of
its agreement to sell Texas Genco to Texas Genco LLC, the Company has agreed to
continue to defend such claims to the extent they are covered by insurance
maintained by the Company, subject to reimbursement of the costs of such defense
from Texas Genco LLC. Although their ultimate outcome cannot be predicted at
this time, the Company intends to continue vigorously contesting claims that it
does not consider to have merit and 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 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 from time to
time as a defendant in litigation related to such sites. Although the ultimate
outcome of such matters 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.

TEXAS GENCO MATTERS

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.

Under the Price Anderson Act, the maximum liability to the public of owners
of nuclear power plants was $10.8 billion as of December 31, 2004. Owners are
required under the Price Anderson Act to insure their liability for nuclear
incidents and protective evacuations. Texas Genco and the other owners 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 reactor per year per
incident.

There can be no assurance that all potential losses or liabilities
associated with the South Texas Project will be insurable, or that the amount of
insurance will be sufficient to cover them. Any substantial losses not covered
by insurance would have a material effect on Texas Genco's financial condition,
results of operations and cash flows.

Nuclear Decommissioning. CenterPoint Houston, as collection agent for the
nuclear decommissioning charge assessed on its transmission and distribution
customers, contributed $2.9 million in 2004 to trusts established to fund Texas
Genco's share of the decommissioning costs for the South Texas Project, and
expects to contribute $2.9 million in 2005. There are various investment
restrictions imposed upon Texas

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Genco by the Texas Utility Commission and the NRC relating to Texas Genco's
nuclear decommissioning trusts. Texas Genco and CenterPoint Houston 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 $216 million as of December
31, 2004, of which approximately 36% were fixed-rate debt securities and the
remaining 64% were equity securities. In May 2004, an outside consultant
estimated Texas Genco's portion of decommissioning costs to be approximately
$456 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 were not recovered as of January 1,
2002, will continue to be subject to cost-of-service rate regulation and will be
charged to transmission and distribution customers of CenterPoint Houston or its
successor.