Exhibit 99(c)

ITEM 1. BUSINESS

REGULATION

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

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

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

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

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

In 2002, we obtained authority from each state in which such authority was
required to restructure in a manner that would allow CenterPoint Energy to claim
an exemption from registration under the 1935 Act. CenterPoint Energy has
concluded that a restructuring would not be beneficial and has elected to remain
a registered holding company under the 1935 Act.

FEDERAL ENERGY REGULATORY COMMISSION

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

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

In February 2000, the FERC issued Order No. 637, which introduced several
measures to increase competition for interstate pipeline transportation
services. Order No. 637 authorizes interstate pipelines to propose
term-differentiated and peak/off-peak rates, and requires pipelines to make
tariff filings to expand pipeline service options for customers. Both of our
natural gas pipeline subsidiaries made two Order No. 637

compliance filings in 2000, and both obtained uncontested settlements filed with
the FERC in 2001. In 2002, the FERC issued orders accepting both settlements,
subject to certain modifications. The FERC has denied requests for rehearing and
clarification of the orders and has accepted, with modification, the compliance
tariff filed under one of the orders and ordered additional revised tariff
sheets to be filed under the other order.

STATE AND LOCAL REGULATION

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

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

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

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

City of Tyler, Texas, Gas Costs Review. By letter to Entex dated July 31,
2002, the City of Tyler, Texas, forwarded various computations of what it
believes to be excessive costs ranging from $2.8 million to $39.2 million for
gas purchases by Entex for resale to residential and small commercial customers
in that city under supply agreements in effect since 1992. Entex's gas costs for
its Tyler system are recovered from customers pursuant to tariffs approved by
the city and filed with both the city and the Railroad Commission. Pursuant to
an agreement, on January 29, 2003, Entex and the city filed a Joint Petition for
Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission.
The Joint Petition requests that the Railroad Commission determine whether Entex
has properly and lawfully charged and collected for gas service to its
residential and commercial customers in its Tyler distribution system for the
period beginning November 1, 1992, and ending October 31, 2002. We believe that
all costs for Entex's Tyler distribution system have been properly included and
recovered from customers pursuant to Entex's filed tariffs and that the city has
no legal or factual support for the statements made in its letter.

DEPARTMENT OF TRANSPORTATION

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

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

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

ENVIRONMENTAL MATTERS

GENERAL ENVIRONMENTAL ISSUES

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

Our facilities are subject to state and federal laws and regulations
governing the discharge of pollutants into the air and waterways. In many cases
we must obtain permits or other governmental authorizations that prescribe the
parameters for discharges from our facilities. There are ongoing efforts to
modify standards relating to both the discharge of pollutants into streams and
waterways and to air quality. These efforts may result in more restrictive
regulations and permit terms applicable to our facilities in the future.

We anticipate no significant capital and other special project expenditures
between 2002 and 2006 for environmental compliance. If we do not comply with
environmental requirements that apply to our operations, regulatory agencies
could seek to impose on us civil, administrative and/or criminal liabilities as
well as seek to curtail our operations. Under some statutes, private parties
could also seek to impose civil fines or liabilities for property damage,
personal injury and possibly other costs.

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

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

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

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

LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION

Manufactured Gas Plant Sites. We and our predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, remediation has been
completed on two sites, other than ongoing monitoring and water treatment. There
are five remaining sites in our Minnesota service territory, two of which we
believe were neither owned nor operated by us, and for which we believe we have
no liability.

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

We have received notices from the United States Environmental Protection
Agency and others regarding our status as a PRP for sites in other states. Based
on current information, we have not been able to quantify a range of
environmental expenditures for potential remediation expenditures with respect
to other MGP sites.

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

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

RISK FACTORS

RISKS RELATED TO OUR CORPORATE AND FINANCIAL STRUCTURE

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

As a result of several recent events occurring in 2001 and 2002, including
the September 11, 2001 terrorist attacks, the bankruptcy of Enron Corp., the
downgrading of our credit rating and the credit ratings of several energy
companies and the unusual volatility in the U.S. financial markets, the
availability and cost of capital for our business have been adversely affected.
If we are unable to obtain affiliate or external financing on reasonable terms
to meet our future capital requirements on terms that are acceptable to us, our
financial condition and future results of operations could be materially
adversely affected. As of December 31, 2002, we had $2.3 billion of outstanding
indebtedness and trust preferred securities, including $850 million of debt that
must be refinanced in 2003. In addition, capital constraints impacting our
parent company's and our businesses over the next year may require our future
indebtedness to include terms that are more restrictive or

burdensome than those of our current indebtedness. These terms may negatively
impact our ability to operate our business. The success of our future financing
efforts may depend, at least in part, on:

- general economic and capital market conditions;

- credit availability from financial institutions and other lenders;

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

- maintenance of acceptable credit ratings by us and CenterPoint Energy;

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

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

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

- provisions of relevant tax and securities laws; and

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

Our current credit ratings are discussed in "Management's Narrative
Analysis of Results of Operations -- Liquidity -- Impact on Liquidity of a
Downgrade in Credit Ratings" in Item 7 of this report. We cannot assure you that
these ratings will remain in effect for any given period of time or that one or
more of these ratings will not be lowered or withdrawn entirely by a rating
agency. We note that these credit ratings are not recommendations to buy, sell
or hold our securities. 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.

THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR
ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION.

Our ratings and credit may be impacted by CenterPoint Energy's credit
standing. CenterPoint Energy and its subsidiaries other than us have
approximately $293 million of debt, including capital leases, required to be
paid in 2003. We cannot assure you that CenterPoint Energy and its other
subsidiaries will be able to pay or refinance these amounts. If CenterPoint
Energy were to experience a deterioration in its credit standing or liquidity
difficulties, our access to credit and our ratings could be adversely affected.

WE ARE A WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY. CENTERPOINT ENERGY CAN
EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY AND BUSINESS AND
OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO OUR INTERESTS.

We are managed by officers and employees of CenterPoint Energy. Our
management will make determinations with respect to the following:

- our payment of dividends;

- decisions on our financings and our capital raising activities;

- mergers or other business combinations; and

- our acquisition or disposition of assets.

There are no contractual restrictions on our ability to pay dividends to
CenterPoint Energy. Our management could decide to increase our dividends to
CenterPoint Energy to support its cash needs. This could adversely affect our
liquidity. Under the 1935 Act, our ability to pay dividends is restricted by the
SEC's requirement that common equity as a percentage of total capitalization
must be at least 30% after the payment of any dividend. In addition, the order
restricts our ability to pay dividends out of capital accounts to the extent
current or retained earnings are insufficient for those dividends. Under these
restrictions, we are permitted to pay dividends in excess of the respective
current or retained earnings in an amount up to $100 million.

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

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

RISK FACTORS AFFECTING THE RESULTS OF OUR BUSINESSES

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

We compete primarily with alternate energy sources such as electricity and
other fuel sources. In some areas, intrastate pipelines, other gas distributors
and marketers also compete directly with us 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 our 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 us as a result of competition may have an
adverse impact on our results of operations, financial condition and cash flows.

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

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

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

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

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

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

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

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

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

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

OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

A portion of our revenues are derived from natural gas sales and
transportation. Thus, our 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.

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

We have insurance covering certain of our facilities, including property
damage insurance and public liability insurance in amounts that we consider
appropriate. Where we have such insurance policies in place, they are subject to
certain limits and deductibles and do not include business interruption
coverage. We cannot assure you that insurance coverage will be available in the
future on commercially reasonable terms or that the insurance proceeds received
for any loss of or any damage to any of our facilities will be sufficient to
restore the loss or damage without negative impact on our results of operations,
financial condition and cash flows. The costs of our insurance coverage have
increased significantly in recent months and may continue to increase in the
future.

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

The cost of repairing damage to our facilities due to storms, natural
disasters, wars, terrorist acts and other catastrophic events, in excess of
reserves established for such repairs, may adversely impact our results of
operations, financial condition and cash flows. The occurrence or risk of
occurrence of future terrorist activity may impact our results of operations and
financial condition in unpredictable ways. These actions could also result in
adverse changes in the insurance markets and disruptions of power and fuel
markets. In addition, our natural gas distribution and pipelines and gathering
facilities could be directly or indirectly harmed by future terrorist activity.
The occurrence or risk of occurrence of future terrorist attacks or related acts
of war could also adversely affect the United States economy. A lower level of
economic activity could result in a decline in energy consumption, which could
adversely affect our revenues and margins and limit our future growth prospects.
Also, these risks could cause instability in the financial markets and adversely
affect our ability to access capital.

ITEM 3. LEGAL PROCEEDINGS

For a brief descriptions of certain legal and regulatory proceedings
affecting us, see "Regulation" and "Environmental Matters" in Item 1 of this
report and Notes 10(c) and 10(d) to our consolidated financial statements.

ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF
CENTERPOINT ENERGY RESOURCES CORP. AND ITS CONSOLIDATED SUBSIDIARIES

The following narrative analysis should be read in combination with our
consolidated financial statements and notes contained in Item 8 of this report.

Because we are an indirect wholly owned subsidiary of CenterPoint Energy,
Inc. (CenterPoint Energy), our determination of reportable segments considers
the strategic operating units under which CenterPoint Energy manages sales,
allocates resources and assesses performance of various products and services to
wholesale or retail customers in differing regulatory environments. We have
identified the following reportable business segments: Natural Gas Distribution,
Pipelines and Gathering and Other Operations. Prior to 2001, we also conducted
business in the Wholesale Energy and European Energy business segments.
Wholesale Energy included wholesale energy trading, marketing, power origination
and risk management services in North America but excluded the operations of
Reliant Energy Power Generation, Inc., a wholly owned subsidiary of Reliant
Resources, Inc. (Reliant Resources) and formerly an indirect wholly owned
subsidiary of CenterPoint Energy's predecessor, Reliant Energy, Incorporated
(Reliant Energy). European Energy included the energy trading and marketing
operations initiated in the fourth quarter of 1999 in the Netherlands and other
countries in Europe but excluded Reliant Energy Power Generation Benelux N.V., a
Dutch power company.

Reliant Energy completed the separation of the generation, transmission and
distribution, and retail sales functions of its Texas electric operations
pursuant to the following steps, which occurred on August 31, 2002 (the
Restructuring):

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

- Reliant Energy and its subsidiaries, including us, became subsidiaries of
CenterPoint Energy; and

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

After the Restructuring, CenterPoint Energy distributed to its shareholders
the shares of common stock of Reliant Resources that it owned (the Distribution)
in a tax-free transaction.

Contemporaneous with the Restructuring, CenterPoint Energy registered and
became subject, with its subsidiaries, to regulation as a registered holding
company system under the Public Utility Holding Company Act of 1935 (1935 Act).
The 1935 Act directs the Securities and Exchange Commission (SEC) to regulate,
among other things, transactions among affiliates, sales or acquisitions of
assets, issuances of securities, distributions and permitted lines of business.

On December 31, 2000, CERC Corp. transferred all of the outstanding capital
stock (collectively, Stock Transfer) of Reliant Energy Services International,
Inc. (RESI), Arkla Finance Corporation (Arkla Finance) and Reliant Energy Europe
Trading & Marketing, Inc. (RE Europe Trading), all of which were wholly owned
subsidiaries of CERC Corp., to Reliant Resources. Both CERC Corp. and Reliant
Resources were wholly owned subsidiaries of Reliant Energy at that time. As a
result of the Stock Transfer, RESI, Arkla Finance and RE Europe Trading each
became a wholly owned subsidiary of Reliant Resources.

Also, on December 31, 2000, a wholly owned subsidiary of Reliant Resources
merged with and into Reliant Energy Services, a wholly owned subsidiary of CERC
Corp., with Reliant Energy Services as the surviving corporation (Merger). As a
result of the Merger, Reliant Energy Services became a wholly owned subsidiary
of Reliant Resources. As consideration for the Stock Transfer and the Merger,
Reliant Resources paid $94 million to CERC Corp.

Reliant Energy Services, together with RESI and RE Europe Trading,
conducted the Wholesale Energy business segment's trading, marketing, power
origination and risk management business and operations of Reliant Energy prior
to the formation of CenterPoint Energy. Arkla Finance is a company that holds an
investment in marketable equity securities.

The Stock Transfer and the Merger were part of the Restructuring. We are
reporting the results of RE Europe Trading as discontinued operations for all
periods presented in our consolidated financial statements in accordance with
Accounting Principles Board (APB) Opinion No. 30, "Reporting the Results of
Operations -- Reporting the Effects of Disposal of a Segment of a Business, and
Extraordinary, Unusual and Infrequently Occurring Events and Transactions" (APB
Opinion No. 30). The transfer of the operations of Reliant Energy Services, RESI
and Arkla Finance did not result in the disposal of a segment of business as
defined under APB NO. 30. For additional information regarding the operating
results of the entities transferred to Reliant Resources, please read Note 14 to
our consolidated financial statements.

CONSOLIDATED RESULTS OF OPERATIONS

Our results of operations are affected by seasonal fluctuations in the
demand for natural gas and price movements of energy commodities. Our results of
operations are also affected by, among other things, the actions of various
federal and state governmental authorities having jurisdiction over rates we
charge, competition in our various business operations, debt service costs and
income tax expense.

The following table sets forth selected financial data for the years ended
December 31, 2000, 2001 and 2002, followed by a discussion of our consolidated
results of operations based on earnings from continuing operations before
interest expense, distribution on trust preferred securities and income taxes
(EBIT). EBIT, as defined, is shown because it is a financial measure we use to
evaluate the performance of our business segments and we believe it is a measure
of financial performance that may be used as a means to analyze and compare
companies on the basis of operating performance. We expect that some analysts
and investors will want to review EBIT when evaluating our company. EBIT is not
defined under accounting principles generally accepted in the United States
(GAAP), should not be considered in isolation or as a substitute for a measure
of performance prepared in accordance with GAAP and is not indicative of
operating income from operations as determined under GAAP. Additionally, our
computation of EBIT may not be comparable to other similarly titled measures
computed by other companies, because all companies do not calculate it in the
same fashion. We consider operating income to be a comparable measure under
GAAP. We believe the difference between operating income and EBIT on both a
consolidated and business segment basis is not material. We have provided a
reconciliation of consolidated operating income to EBIT and EBIT to net income
below.

SELECTED FINANCIAL RESULTS

<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2000(1) 2001 2002
------- ------ ------
(IN MILLIONS)

Operating Revenues........................................ $21,589 $5,044 $4,208
------- ------ ------
Operating Expenses:
Natural gas and fuel.................................... 13,030 3,781 2,901
Purchased power......................................... 7,141 -- --
Operation and maintenance............................... 759 657 667
Depreciation and amortization........................... 214 207 167
Taxes other than income taxes........................... 113 133 120
------- ------ ------
Total operating expenses........................ 21,257 4,778 3,855
------- ------ ------
Operating Income.......................................... 332 266 353
Other Income, net......................................... 2 14 8
------- ------ ------
EBIT...................................................... 334 280 361
Interest Expense and Distribution on Trust Preferred
Securities.............................................. (143) (155) (153)
------- ------ ------
Income Before Income Taxes................................ 191 125 208
Income Tax Expense........................................ (93) (58) (88)
------- ------ ------
Income from Continuing Operations......................... 98 67 120
Loss from Discontinued Operations......................... (24) -- --
------- ------ ------
Net Income...................................... $ 74 $ 67 $ 120
======= ====== ======
</Table>

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

(1) The 2000 selected financial results include the results of operations of
Reliant Energy Services, RESI and Arkla Finance. For further discussion,
please read Notes 13 and 14 to our consolidated financial statements.

2002 Compared to 2001. We reported EBIT for 2002 of $361 million compared
to $280 million in 2001. The $81 million increase was primarily due to:

- a $31 million increase in EBIT primarily as a result of improved
operating margins (revenues less fuel costs) from rate increases in 2002,
a 5% increase in throughput and changes in estimates of unbilled revenues
and deferred gas costs, which reduced operating margins in 2001; and

- a $49 million increase in EBIT as a result the discontinuance of goodwill
amortization in accordance with Statement of Financial Accounting
Standards (SFAS) SFAS No. 142, "Goodwill and Other Intangible Assets"
(SFAS No. 142) in 2002.

Operation and maintenance expenses increased $10 million in 2002 as
compared to 2001 primarily due to project work consisting of construction
management, material acquisition, engineering, project planning and other
services as well as increased benefit costs and higher general and
administrative expenses. These increases were partially offset by a reduction in
bad debt expense in 2002 as a result of improved collections and lower gas
prices.

Depreciation and amortization expense decreased $40 million in 2002 as
compared to 2001 primarily as a result of the discontinuance of goodwill
amortization in accordance with SFAS No. 142 as further discussed in Note 3(d)
to our consolidated financial statements. Goodwill amortization was $49 million
for the year ended December 31, 2001. This was partially offset by an increase
in depreciation expense due to an increase in the asset base.

Taxes other than income taxes decreased $13 million in 2002 as compared to
2001 due primarily to reduced franchise fees as a result of decreased revenues.

Other income decreased $6 million in 2002 as compared to 2001 primarily due
to decreased interest income from affiliated parties.

Our effective tax rates for 2002 and 2001 were 42.2% and 46.4%,
respectively. The decrease in the effective rate for 2002 compared to 2001 was
primarily the result of the discontinuance of goodwill amortization in
accordance with SFAS No. 142, offset by an increase in state income taxes.

2001 Compared to 2000. We reported EBIT for 2001 of $280 million compared
to $334 million in 2000. The $54 million decrease was primarily due to:

- a $106 million decrease in EBIT resulting from the transfer of Reliant
Energy Services to Reliant Resources pursuant to the Merger discussed
above;

- a $24 million increase in EBIT primarily resulting from increased
operating margins (revenues less fuel costs) due to increased volumes in
the first quarter of 2001 due to the effect of colder weather, partially
offset by changes in estimates of unbilled revenues and recoverability of
deferred gas accounts and other items; and

- a $33 million increase in EBIT primarily resulting from a $27 million
impairment loss on marketable equity securities classified as "available
for sale" in 2000.

Operation and maintenance expenses decreased $102 million in 2001 as
compared to 2000 primarily due to the transfer of Reliant Energy Services to
Reliant Resources pursuant to the Merger discussed above. This decrease was
partially offset by increased customer growth and usage and reduced operating
expenses due to exiting certain non-rate regulated retail gas markets outside of
our established market areas during 2000 in our Natural Gas Distribution
segment.

Depreciation and amortization expense decreased $7 million in 2001 as
compared to 2000 primarily as a result of the transfer of Reliant Energy
Services to Reliant Resources, offset by an increase in depreciation expense due
to an increase in the asset base.

Taxes other than income taxes increased $20 million in 2001 as compared to
2000 due primarily to increased franchise fees, state franchise taxes and state
gross receipts taxes.

Other income increased $12 million in 2001 as compared to 2000 primarily
due to a $27 million impairment loss on marketable equity securities classified
as "available for sale" in 2000, partially offset by a $17 million reduction in
interest income in 2001.

Interest expense increased $12 million in 2001 as compared to 2000
primarily due to increased long-term borrowings.

Our effective tax rates for 2001 and 2000 were 46.4% and 48.7%,
respectively. The decrease in the effective tax rate for 2001 compared to 2000
was primarily due to a decrease in state income taxes.

Loss from discontinued operations includes the results of RE Europe Trading
for all periods presented in our consolidated financial statements in accordance
with APB Opinion No. 30. For additional information, please read Note 14 to our
consolidated financial statements.

FLUCTUATIONS IN COMMODITY PRICES AND DERIVATIVE INSTRUMENTS

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

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

- state and federal legislative and regulatory actions or developments,
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;

- timely rate increases including recovery of costs;

- the successful and timely completion of our capital projects;

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

- our pursuit of potential business strategies, including acquisitions or
dispositions of assets;

- changes in business strategy or development plans;

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

- changes in interest rates or rates of inflation;

- unanticipated changes in operating expenses and capital expenditures;

- weather variations and other natural phenomena;

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

- commercial bank and financial market conditions, our access to capital,
the costs of such capital and the results of our financing and
refinancing efforts, including availability of funds in the debt capital
markets;

- actions by rating agencies;

- legal and administrative proceedings and settlements;

- changes in tax laws;

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

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

- changes in technology;

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

- significant changes in critical accounting policies;

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

- the availability and price of insurance;

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

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

LIQUIDITY

Long-Term Debt and Trust Preferred Securities. Of the $1.96 billion of
debt outstanding at December 31, 2002, approximately $1.8 billion principal
amount is senior and unsecured and, approximately $79.4 million principal amount
with a final maturity of 2012 is subordinated. In addition, the debentures
relating to $0.4 million of trust preferred securities issued by our statutory
business-trust subsidiary are subordinated.

The issuance of secured debt by us is limited under an indenture relating
to approximately $145 million principal amount of debt maturing in 2006 which
provides for equal and ratable security for such debt in the event debt secured
by "principal property" (as defined in the indenture) is issued. Other than this
indenture, agreements relating to the issuance of long-term debt do not restrict
the issuance of secured debt. Additionally, our $350 million credit agreement
expiring in March 2003 prohibits the issuance of debt secured by "principal
property". The definition is similar to that contained in the indenture
described above. Finally, our ability to issue secured debt may be limited under
the terms of agreements entered into by CenterPoint Energy. The assets that may
be pledged as security for our debt may be limited by the SEC because our parent
is a registered holding company.

On February 28, 2003, CenterPoint Energy reached agreement with a syndicate
of banks on a second amendment to its existing $3.85 billion bank facility. The
amendment provides that proceeds from capital stock or indebtedness issued or
incurred by us must be applied (subject to a $200 million basket for us and
another $250 million basket for borrowings by CenterPoint Energy and other
limited exceptions) to repay bank loans and reduce the bank facility. Cash
proceeds from issuances of indebtedness to refinance indebtedness existing on
October 10, 2002 are not subject to this limitation.

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

<Table>
<Caption>
TOTAL
COMMITTED
TYPE OF FACILITY TERMINATION DATE CREDIT
- ---------------- ----------------- -------------
(IN
MILLIONS)

Revolver............................................. March 31, 2003 $350
Receivables.......................................... November 14, 2003 150
----
$500
====
</Table>

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

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

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

On December 31, 2002, we had $74 million borrowed from affiliates. We
participate in a "money pool" through which we and certain of our affiliates can
borrow or invest on a short-term basis. Funding needs are aggregated and
external borrowing or investing is based on the net cash position. The money
pool's net funding requirements are generally met by borrowings of CenterPoint
Energy. The terms of the money pool are in accordance with requirements
applicable to registered public utility holding companies under the 1935 Act.
The money pool may not provide sufficient funds to meet our cash needs.

Capital Requirements. We anticipate investing up to an aggregate $1.3
billion in capital expenditures in the years 2003 through 2007, including
approximately $264 million and $279 million in 2003 and 2004, respectively.

Cash Requirements in 2003. Our liquidity and capital requirements are
affected primarily by our results of operations, capital expenditures, debt
service requirements, and working capital needs. Our principal cash requirements
during 2003 include the following:

- approximately $264 million of capital expenditures;

- the refinancing of borrowings under our $350 million bank facility; and

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

We expect to meet our capital requirements with cash flows from operations,
short-term borrowings and proceeds from debt offerings. We believe that our
current liquidity, along with anticipated cash flows from operations and
proceeds from short-term borrowings, including the renewal, extension or
replacement of existing bank facilities, and anticipated sales of securities in
the capital markets will be sufficient to meet our cash needs. However,
disruptions in our ability to access the capital markets on a timely basis could
adversely affect our liquidity. In addition, the cost of our debt issuances may
be high. Please read "Risk Factors -- Risks Related to Our Corporate and
Financial Structure -- If we are unable to arrange future financings on
reasonable terms, our ability to fund future capital expenditures and refinance
existing indebtedness could be limited" in Item 1 of this report.

Prior to the Restructuring, Reliant Energy obtained an order from the SEC
that granted Reliant Energy certain authority with respect to financing,
dividends and other matters. The financing authority granted by that order will
expire on June 30, 2003, and CenterPoint Energy must obtain a further order from
the SEC under the 1935 Act in order for it and its subsidiaries, including us,
to engage in financing activities subsequent to that date.

We have registered $50 million principal amount of debt securities with the
SEC for future issuance. These debt securities may be sold in a public offering.
The amount of any debt issuance, whether registered or unregistered, is expected
to be affected by the market's perception of our creditworthiness, general
market

conditions and factors affecting our industry. Proceeds from the sales of
securities are expected to be used primarily to refinance existing long-term and
short-term debt.

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

<Table>
<Caption>
2008 AND
CONTRACTUAL OBLIGATIONS TOTAL 2003 2004 2005 2006 2007 THEREAFTER
- ----------------------- ------ ---- ---- ---- ---- ---- ----------

Long-term debt......................... $1,959 $518 $ 1 $368 $152 $ 7 $ 913
Short-term borrowings, including credit
facilities........................... 347 347 -- -- -- -- --
Trust preferred securities............. 1 -- -- -- -- -- 1
Operating lease payments(1)............ 126 15 12 10 8 7 74
Non-trading derivative liabilities..... 11 10 1 -- -- -- --
------ ---- --- ---- ---- --- ------
Total contractual cash obligations... $2,444 $890 $14 $378 $160 $14 $ 988
====== ==== === ==== ==== === ======
</Table>

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

(1) For a discussion of operating leases, please read Note 10(b) to our
consolidated financial statements

Impact on Liquidity of a Downgrade in Credit Ratings. As of March 4, 2003,
Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a
division of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned
the following credit ratings to senior unsecured debt of CERC Corp.:

<Table>
<Caption>
MOODY'S S&P FITCH
- ------------------ ------------------- -------------------
RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3)
- ------ ---------- ------ ---------- ------ ----------

Ba1 Negative BBB Stable BBB Negative
</Table>

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

(1) A "negative" outlook from Moody's reflects concerns over the next 12 to 18
months which will either lead to a review for a potential downgrade or a
return to a stable outlook.

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

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

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

A decline in credit ratings would increase facility fees and borrowing
costs under our existing revolving credit facility. A decline in credit ratings
would also increase the interest rate on long-term debt to be issued in the
capital markets and would negatively impact our ability to complete capital
market transactions. The $150 million receivables facility of CERC Corp.
requires the maintenance of credit ratings of at least BB from S&P and Ba2 from
Moody's. Receivables would cease to be sold in the event a credit rating fell
below the threshold.

Our bank facilities contain "material adverse change" clauses that could
impact our ability to borrow under these facilities. The "material adverse
change" clause in our revolving credit facility applies to new borrowings under
the facility and relates to changes since the most recent financial statements
delivered to the banks. Financial statements are delivered quarterly.

CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary, provides
comprehensive natural gas sales and services to industrial and commercial
customers that are primarily located within or near the

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

Cross Defaults. Our debentures and borrowings generally provide that a
default on obligations by CenterPoint Energy does not cause a default under our
debentures, revolving credit facility or receivables facility. A payment default
at CERC Corp. exceeding $50 million will cause a default under CenterPoint
Energy's $3.85 billion bank facility.

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

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

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

- various regulatory actions.

Capitalization. Factors affecting our capitalization include:

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

- limitations imposed on us because our parent is a registered holding
company.

In connection with our parent company's registration as a public utility
holding company under the 1935 Act, the SEC has limited the aggregate amount of
our external borrowings to $2.7 billion. Our ability to pay dividends is
restricted by the SEC's requirement that common equity as a percentage of total
capitalization must be at least 30% after the payment of any dividend. In
addition, the order restricts our ability to pay dividends out of capital
accounts to the extent current or retained earnings are insufficient for those
dividends. Under these restrictions, we are permitted to pay dividends in excess
of the respective current or retained earnings in an amount up to $100 million.

Relationship with CenterPoint Energy. We are an indirect wholly owned
subsidiary of CenterPoint Energy. As a result of this relationship, the
financial condition and liquidity of our parent company could affect our access
to capital, our credit standing and our financial condition.

Pension Plan. As discussed in Note 8(a) to the consolidated financial
statements, we participate in CenterPoint Energy's qualified non-contributory
pension plan covering substantially all employees. Pension expense for 2003 is
estimated to be $36 million based on an expected return on plan assets of 9.0%
and a discount rate of 6.75% as of December 31, 2002. Pension expense for the
year ended December 31, 2002 was $13 million. Future changes in plan asset
returns, assumed discount rates and various other factors related to the pension
will impact our future pension expense and liabilities. We cannot predict with
certainty what these factors will be in the future.

OFF BALANCE SHEET FINANCING

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

CRITICAL ACCOUNTING POLICIES

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

IMPAIRMENT OF LONG-LIVED ASSETS

Long-lived assets recorded in our Consolidated Balance Sheets primarily
consist of property, plant and equipment (PP&E). Net PP&E comprises $3.2 billion
or 54% of our total assets as of December 31, 2002. We make judgments and
estimates in conjunction with the carrying value of these assets, including
amounts to be capitalized, depreciation and amortization methods and useful
lives. We evaluate our PP&E for impairment whenever indicators of impairment
exist. During 2002, no such indicators of impairment existed. Accounting
standards require that if the sum of the undiscounted expected future cash flows
from a company's asset is less than the carrying value of the asset, an asset
impairment must be recognized in the financial statements. The amount of
impairment recognized is calculated by subtracting the fair value of the asset
from the carrying value of the asset.

IMPAIRMENT OF GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS

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

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

UNBILLED REVENUES

Revenues related to the sale and/or delivery of natural gas are generally
recorded when natural gas is delivered to customers. However, the determination
of sales to individual customers is based on the reading of their meters, which
is performed on a systematic basis throughout the month. At the end of each
month, amounts of natural gas delivered to customers since the date of the last
meter reading are estimated and the corresponding unbilled revenue is estimated.
Unbilled natural gas sales are estimated based on estimated purchased gas
volumes, estimated lost and unaccounted for gas and tariffed rates in effect.
Accrued unbilled revenues recorded in the Consolidated Balance Sheet as of
December 31, 2001 and 2002 were $269 million and $284 million, respectively,
related to our Natural Gas Distribution business segment.

NEW ACCOUNTING PRONOUNCEMENTS

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

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

We have completed an assessment of the applicability and implications of
SFAS No. 143 and have identified no asset retirement obligations. Our
rate-regulated businesses have previously recognized removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2002, these previously recognized removal costs of $378 million do
not represent SFAS No. 143 asset retirement obligations, but rather embedded
regulatory liabilities.

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

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

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

In June 2002, the Emerging Issues Task Force ("EITF") reached a consensus
that all mark-to-market gains and losses on energy trading contracts should be
shown net in the statement of consolidated income whether or not settled
physically. In October 2002, the EITF issued a consensus that superceded the
June 2002 consensus. The October 2002 consensus required, among other things,
that energy derivatives held for trading purposes be shown net in the statement
of consolidated income. This new consensus, EITF 02-3 "Issues Involved in
Accounting for Derivative Contracts Held for Trading Purposes and Contracts
Involved in Energy Trading and Risk Management Activities," is effective for
fiscal periods beginning after December 15, 2002.

Our former subsidiaries, RESI, RE Europe Trading and Reliant Energy
Services entered into energy derivatives held for trading purposes. On December
31, 2000, these subsidiaries were either sold or transferred to Reliant
Resources, an unconsolidated related party. See Note 2 to our consolidated
financial statements. For financial periods beginning subsequent to December 31,
2002, we will retroactively restate the financial statement presentation of
these energy trading activities. For the year ended December 31, 2000, RESI, RE
Europe Trading, and Reliant Energy Services reported combined revenues and
natural gas and purchased power expenses of $17.6 billion and $17.4 billion,
respectively. We are currently evaluating the effects on our Statements of
Consolidated Income of the net presentation of these trading activities for the
year ended December 31, 2000. Such presentation will not affect previously
reported operating income or net income.

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

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

Please read Note 5 to our consolidated financial statements for a
discussion of our adoption of SFAS No. 133 "Accounting for Derivative
Instruments and Hedging Activities" (SFAS No. 133) on January 1, 2001 and
adoption of subsequent cleared guidance. Please read Note 3(d) to our
consolidated financial statements for a discussion of our adoption of SFAS No.
142.

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(e) REGULATORY MATTERS

CERC 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 utility operations of Natural Gas Distribution and MRT. As of
December 31, 2001 and 2002, CERC had recorded $6 million and $12 million,
respectively, of net regulatory assets.

If, as a result of changes in regulation or competition, CERC's ability to
recover these assets and liabilities would not be probable, CERC would be
required to write off or write down these regulatory assets and liabilities. In
addition, CERC would be required to determine any impairment of the carrying
costs of plant and inventory assets.

Arkansas Rate Case

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

Oklahoma Rate Case

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

(i) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

Accounts receivable, principally customers, net, are net of an allowance
for doubtful accounts of $33 million and $20 million at December 31, 2001 and
2002, respectively. The provisions for doubtful accounts in CERC's Statements of
Consolidated Income for 2000, 2001 and 2002 were $33 million, $46 million and
$15 million, respectively.

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

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

5. DERIVATIVE INSTRUMENTS

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

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

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

(a) Non-Trading Activities

Cash Flow Hedges. To reduce the risk from market fluctuations associated
with purchased gas costs, CERC enters into energy derivatives in order to hedge
certain expected purchases and sales of natural gas. CERC 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. CERC analyzes its physical
transaction portfolio to determine its net exposure by delivery location and
delivery period. Because CERC's physical transactions with similar delivery
locations and periods are highly correlated and share similar risk exposures,
CERC facilitates hedging for customers by aggregating physical transactions and
subsequently entering into non-trading energy derivatives to mitigate exposures
created by the physical positions.

During 2002, no hedge ineffectiveness was recognized in earnings from
derivatives that are designated and qualify as Cash Flow Hedges. No component of
the derivative instruments' gain or loss was excluded from the assessment of
effectiveness. If it becomes probable that an anticipated transaction will not
occur, CERC realizes in net income the deferred gains and losses recognized in
accumulated other comprehensive income. During the year ended December 31, 2002,
there was a $0.9 million deferred loss recognized in earnings as a result of the
discontinuance of cash flow hedges because it was no longer probable that the
forecasted transaction would occur. Once the anticipated transaction occurs, the
accumulated deferred gain or loss recognized in accumulated other comprehensive
income is reclassified and included in CERC's Statements of Consolidated Income
under the caption "Natural Gas and Purchased Power." Cash flows resulting from
these transactions in non-trading energy derivatives are included in the
Statements of Consolidated Cash Flows in the same category as the item being
hedged. As of December 31, 2002, CERC expects $17 million in accumulated other
comprehensive income to be reclassified into net income during the next twelve
months.

The maximum length of time CERC 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 three
years. CERC's policy is not to exceed five years in hedging its exposure.

(b) CREDIT RISKS

In addition to the risk associated with price movements, credit risk is
also inherent in CERC'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 CERC as of December 31, 2001 and 2002:

<Table>
<Caption>
DECEMBER 31, 2001 DECEMBER 31, 2002
------------------- ----------------------
INVESTMENT INVESTMENT
NON-TRADING DERIVATIVE ASSETS GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL(3)
- ----------------------------- ----------- ----- ----------- --------
(IN MILLIONS)

Energy marketers............................. $ 9 $ 9 $ 7 $22
Financial institutions....................... -- -- 9 9
----- ----- --- ---
Total...................................... $ 9 $ 9 $16 $31
===== ===== === ===
</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 encompasses cash and standby
letters of credit.

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

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

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

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

7. TRUST PREFERRED SECURITIES

In June 1996, a Delaware statutory business trust created by CERC Corp.
(CERC Trust) issued $173 million aggregate amount of convertible preferred
securities to the public. CERC Corp. accounts for CERC Trust as a wholly owned
consolidated subsidiary. CERC Trust used the proceeds of the offering to
purchase convertible junior subordinated debentures issued by CERC Corp. having
an interest rate and maturity date that correspond to the distribution rate and
mandatory redemption date of the convertible preferred securities. The
convertible junior subordinated debentures represent CERC Trust's sole asset and
its entire operations. CERC Corp. considers its obligation under the Amended and
Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the
convertible preferred securities, taken together, to constitute a full and
unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect
to the convertible preferred securities.

The convertible preferred securities are mandatorily redeemable upon the
repayment of the convertible junior subordinated debentures at their stated
maturity or earlier redemption. Effective January 7, 2003, the convertible
preferred securities are convertible at the option of the holder into $33.62 of
cash and 2.34 shares of CenterPoint Energy common stock for each $50 of
liquidation value. As of December 31, 2001 and 2002, $0.4 million liquidation
amount of convertible preferred securities were outstanding. The securities, and
their

underlying convertible junior subordinated debentures, bear interest at 6.25%
and mature in June 2026. Subject to some limitations, CERC Corp. has the option
of deferring payments of interest on the convertible junior subordinated
debentures. During any deferral or event of default, CERC Corp. may not pay
dividends on its common stock to CenterPoint Energy. As of December 31, 2002, no
interest payments on the convertible junior subordinated debentures had been
deferred.

8. EMPLOYEE BENEFIT PLANS

(a) PENSION PLANS

Substantially all of CERC's employees participate in CenterPoint Energy's
qualified non-contributory pension plan. 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.

CenterPoint Energy's funding policy is to review amounts annually in
accordance with applicable regulations in order to achieve adequate funding of
projected benefit obligations. Pension expense is allocated to CERC based on
covered employees. This calculation is intended to allocate pension costs in the
same manner as a separate employer plan. Assets of the plan are not segregated
or restricted by CenterPoint Energy's participating subsidiaries. Pension
benefit was $21 million for the year ended December 31, 2000. CERC recognized
pension expense of $1 million and $13 million for the years ended December 31,
2001 and 2002, respectively.

In addition to the Plan, CERC participates in CenterPoint Energy's
non-qualified pension plan, which allows participants to retain the benefits to
which they would have been entitled under the qualified pension plan except for
federally mandated limits on these benefits or on the level of salary on which
these benefits may be calculated. The expense associated with the non-qualified
pension plan was $13 million, $5 million and $2 million for the years ended
December 31, 2000, 2001 and 2002, respectively.

As of December 31, 2001, CenterPoint Energy allocated $94 million of
pension assets, $40 million of non-qualified pension liabilities and $2 million
minimum pension liabilities to CERC. As of December 31, 2002, CenterPoint Energy
has not allocated such pension assets or liabilities to CERC. This change in
method of allocation had no impact on pension expense recorded for the year
ended December 31, 2002.

10. COMMITMENTS AND CONTINGENCIES

(a) ENVIRONMENTAL CAPITAL COMMITMENTS

CERC has various commitments for capital and environmental expenditures.
CERC anticipates no significant capital and other special project expenditures
between 2003 and 2007 for environmental compliance.

(b) Lease Commitments

The following table sets forth information concerning CERC's obligations
under non-cancelable long-term operating leases, principally consisting of
rental agreements for building space, data processing equipment and vehicles,
including major work equipment (in millions):

<Table>

2003........................................................ $ 15
2004........................................................ 12
2005........................................................ 10
2006........................................................ 8
2007........................................................ 7
2008 and beyond............................................. 74
----
Total............................................. $126
====
</Table>

Total rental expense for all operating leases was $33 million, $31 million
and $27 million in 2000, 2001 and 2002, respectively.

Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit
against Reliant Energy Gas Transmission Company (REGT), Reliant Energy Pipeline
Services, Inc., RERC Corp., RES, other Reliant Energy entities and third
parties, in the 1st Judicial District Court, Caddo Parish, Louisiana. The
petition has now been supplemented seven times. As of November 21, 2002, there
were 695 plaintiffs, a majority of whom are Louisiana residents. In addition to
the Reliant Energy entities, the plaintiffs have sued the State of Louisiana
through its Department of Environmental Quality, several individuals, some of
whom are present employees of the State of Louisiana, the Bayou South Gas
Gathering Company, L.L.C., Martin Timber Company, Inc., and several trusts.
Additionally on April 4, 2002, two plaintiffs filed a separate suit with
identical allegations against the same parties in the same court. More recently,
on January 6, 2003, two other plaintiffs filed a third suit of similar
allegations against CenterPoint Energy, as well as other defendants, in Bossier
Parish (26th Judicial District Court).

The suits allege that, at some unspecified date prior to 1985, the
defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox
Aquifer, which lies beneath property owned or leased by certain of the
defendants and which is the sole or primary drinking water aquifer in the area.
The primary source of the contamination is alleged by the plaintiffs to be a gas
processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo
Facility." This facility was purportedly used for gathering natural gas from
surrounding wells, separating gasoline and hydrocarbons from the natural gas for
marketing, and transmission of natural gas for distribution. This site was
originally leased and operated by predecessors of REGT in the late 1940s and was
operated until Arkansas Louisiana Gas Company ceased operations of the plant in
the late 1970s.

Beginning about 1985, the predecessors of certain Reliant Energy defendants
engaged in a voluntary remediation of any subsurface contamination of the
groundwater below the property they own or lease. This work has been done in
conjunction with and under the direction of the Louisiana Department of
Environmental Quality. The plaintiffs seek monetary damages for alleged damage
to the aquifer underlying their property, unspecified alleged personal injuries,
alleged fear of cancer, alleged property damage or diminution of value of their
property, and, in addition, seek damages for trespass, punitive, and exemplary
damages. The quantity of monetary damages sought is unspecified. As of December
31, 2002, CERC is unable to estimate the monetary damages, if any, that the
plaintiffs may be awarded in these matters.

Manufactured Gas Plant Sites. CERC and its predecessors operated
manufactured gas plants (MGP) in the past. In Minnesota, remediation has been
completed on two sites, other than ongoing monitoring and water treatment. There
are five remaining sites in our Minnesota service territory, two of which CERC
believes were neither owned nor operated by CERC, and for which CERC believes it
has no liability.

At December 31, 2001 and 2002, CERC had accrued $23 million and $19
million, respectively, for remediation of the Minnesota sites. At December 31,
2002, the estimated range of possible remediation costs was $8 million to $44
million based on remediation continuing for 30 to 50 years. The cost estimates
are based on studies of a site or industry average costs for remediation of
sites of similar size. The actual remediation costs will be dependent upon the
number of sites to be remediated, the participation of other potentially
responsible parties (PRP), if any, and the remediation methods used. CERC has an
environmental expense tracker mechanism in its rates in Minnesota. CERC has
collected $12 million at December 31, 2002 to be used for future environmental
remediation.

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

Mercury Contamination. CERC'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 CERC at some sites in the past, and CERC 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 CERC and that of others in the natural gas industry to date and on
the current regulations regarding remediation of these sites, CERC believes that
the costs of any remediation of these sites will not be material to CERC's
financial condition, results of operations or cash flows.

Other Environmental. From time to time CERC 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. Considering the information currently known about such sites and
the involvement of CERC in activities at these sites, CERC does not believe that
these matters will have a material adverse effect on CERC's financial position,
results of operations or cash flows.

Department of Transportation

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

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

(d) OTHER LEGAL MATTERS

Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the
Federal False Claims Act against RERC Corp. (now CERC Corp.) and certain of its
subsidiaries alleging mismeasurement of natural gas produced from federal and
Indian lands. The suit seeks undisclosed damages, along with statutory
penalties, interest, costs, and fees. The complaint is part of a larger series
of complaints filed against 77 natural gas pipelines and their subsidiaries and
affiliates. An earlier single action making substantially similar allegations
against the pipelines was dismissed by the federal district court for the
District of Columbia on grounds of improper joinder and lack of jurisdiction. As
a result, the various individual complaints were filed in numerous courts
throughout the country. This case has been consolidated, together with the other
similar False Claims Act cases, in the federal district court in Cheyenne,
Wyoming.

In addition, CERC Corp., CenterPoint Energy Gas Transmission Company,
CenterPoint Energy Field Services, Inc. and CenterPoint Energy-Mississippi River
Transmission Corporation are defendants in a class action filed in May 1999
against approximately 245 pipeline companies and their affiliates. The
plaintiffs in the case purport to represent a class of natural gas producers and
fee royalty owners who allege that they have been subject to systematic gas
mismeasurement by the defendants for more than 25 years. The plaintiffs seek
compensatory damages, along with statutory penalties, treble damages, interest,
costs and fees. The action is currently pending in state court in Stevens
County, Kansas. Motions to dismiss and class certification issues have been
briefed and argued.

Petition requests that the Railroad Commission determine whether Entex has
properly and lawfully charged and collected for gas service to its residential
and commercial customers in its Tyler distribution system for the period
beginning November 1, 1992, and ending October 31, 2002. The Company believes
that all costs for Entex's Tyler distribution system have been properly included
and recovered from customers pursuant to Entex's filed tariffs and that the city
has no legal or factual support for the statements made in its letter.

Gas Recovery Suits. In October 2002, a suit was filed in state district
court in Wharton County, Texas, against CenterPoint Energy, CERC, Entex Gas
Marketing Company, and others alleging fraud, violations of the Texas Deceptive
Trade Practices Act, violations of the Texas Utility Code, civil conspiracy and
violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek
class certification, but no class has been certified. The plaintiffs allege that
defendants inflated the prices charged to residential and small commercial
consumers of natural gas. In February 2003, a similar suit was filed against
CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class
of residential or business customers in Louisiana who allegedly have been
overcharged for gas or gas service provided by CERC. The plaintiffs in both
cases seek restitution for alleged overcharges, exemplary damages and penalties.
CERC denies that it has overcharged any of its customers for natural gas and
believes that the amounts recovered for purchased gas have been in accordance
with what is permitted by state regulatory authorities.

Other Proceedings. CERC is involved in other proceedings before various
courts, regulatory commissions and governmental agencies regarding matters
arising in the ordinary course of business. Management currently believes that
the disposition of these matters will not have a material adverse effect on
CERC's financial position, results of operations or cash flows.

13. REPORTABLE SEGMENTS

Because CERC Corp. is a wholly owned subsidiary of CenterPoint Energy,
CERC's determination of reportable segments considers the strategic operating
units under which CenterPoint Energy manages sales, allocates resources and
assesses performance of various products and services to wholesale or retail
customers in differing regulatory environments. The accounting policies of the
segments are the same as those described in the summary of significant
accounting policies except that some executive benefit costs have not been
allocated to segments. Reportable business segments from previous years have
been restated to conform to the 2002 presentation. CERC accounts for
intersegment sales as if the sales were to third parties, that is, at current
market prices.

Beginning in the first quarter of 2002, CERC began to evaluate performance
on an earnings (loss) before interest expense, distribution on trust preferred
securities and income taxes (EBIT) basis. Prior to 2002, CERC evaluated
performance on the basis of operating income. EBIT, as defined, is shown because
it is a measure CERC uses to evaluate the performance of its business segments
and CERC believes it is a measure of financial performance that may be used as a
means to analyze and compare companies on the basis of operating performance.
CERC expects that some analysts and investors will want to review EBIT when
evaluating CERC. EBIT is not defined under accounting principles generally
accepted in the United States (GAAP), should not be considered in isolation or
as a substitute for a measure of performance prepared in accordance with GAAP
and is not indicative of operating income from operations as determined under
GAAP. Additionally, CERC's computation of EBIT may not be comparable to other
similarly titled measures computed by other companies, because all companies do
not calculate it in the same fashion.

CERC's reportable business segments include the following: Natural Gas
Distribution, Pipelines and Gathering, Wholesale Energy and Other Operations.
Natural Gas Distribution consists of intrastate natural gas sales to, and
natural gas transportation for, residential, commercial and industrial
customers, and some non-rate regulated retail gas marketing operations.
Pipelines and Gathering includes the interstate natural gas pipeline operations
and natural gas gathering and pipeline services. Reliant Energy Services was
previously reported within the Wholesale Energy segment. Other Operations
includes unallocated general corporate expenses and non-operating investments.
During 2000, Reliant Energy transferred RERC's non-rate regulated retail gas
marketing from Other Operations to Natural Gas Distribution and RERC's natural
gas gathering business from Wholesale Energy to Pipelines and Gathering. On
December 31, 2000, RERC Corp. transferred all of the outstanding stock of RESI,
Arkla Finance and RE Europe Trading, all wholly owned subsidiaries of

RERC Corp., to Reliant Resources. Also, on December 31, 2000, a wholly owned
subsidiary of Reliant Resources merged with and into Reliant Energy Services, a
wholly owned subsidiary of RERC Corp., with Reliant Energy Services as the
surviving corporation. As a result of the Merger, Reliant Energy Services became
a wholly owned subsidiary of Reliant Resources. Reportable segments from
previous years have been restated to conform to the 2002 presentation. All of
CERC's long-lived assets are in the United States.

Financial data for business segments and products and services are as
follows:

<Table>
<Caption>
NATURAL GAS PIPELINES AND WHOLESALE OTHER RECONCILING SALES TO
DISTRIBUTION GATHERING ENERGY OPERATIONS ELIMINATIONS AFFILIATES CONSOLIDATED
------------ ------------- --------- ---------- ------------ ---------- ------------
(IN MILLIONS)

AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2000:
Revenues from external
customers(1)................. $4,445 $ 182 $16,961 $ 1 $ -- $-- $21,589
Intersegment revenues.......... 34 202 579 -- (815) -- --
Depreciation and
amortization................. 145 55 11 3 -- -- 214
EBIT........................... 125 137 106 (30) (4) -- 334
Total assets................... 4,518 2,358 -- 448 (748) -- 6,576
Expenditures for long-lived
assets....................... 195 61 27 8 -- -- 291
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2001:
Revenues from external
customers(1)................. 4,737 307 -- -- -- -- 5,044
Intersegment revenues.......... 5 108 -- -- (113) -- --
Depreciation and
amortization................. 147 58 -- 2 -- -- 207
EBIT........................... 149 138 -- 3 (10) -- 280
Total assets................... 3,732 2,361 -- 101 (202) -- 5,992
Expenditures for long-lived
assets....................... 209 54 -- -- -- -- 263
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2002:
Revenues from external
customers(1)................. 3,927 253 -- -- -- 28 4,208
Intersegment revenues.......... 7 119 -- -- (126) -- --
Depreciation and
amortization................. 126 41 -- -- -- -- 167
EBIT........................... 210 158 -- 6 (13) -- 361
Total assets................... 4,051 2,481 -- 206 (752) -- 5,986
Expenditures for long-lived
assets....................... 196 70 -- -- -- -- 266
</Table>

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

(1) Included in revenues from external customers are revenues from sales to
Reliant Resources, a former affiliate, of $816 million, $181 million and $42
million for the years ended December 31, 2000, 2001 and 2002, respectively.

<Table>
<Caption>
YEAR ENDED DECEMBER 31,
-------------------------
2000 2001 2002
------- ------ ------
(IN MILLIONS)

RECONCILIATION OF OPERATING INCOME TO EBIT AND EBIT TO NET
INCOME:
Operating income.......................................... $ 332 $ 266 $ 353
Other, net................................................ 2 14 8
------- ------ ------
EBIT.................................................... 334 280 361
Interest expense and other charges........................ (143) (155) (153)
Income taxes.............................................. (93) (58) (88)
Loss from discontinued operations......................... (24) -- --
------- ------ ------
Net income.............................................. $ 74 $ 67 $ 120
======= ====== ======
REVENUES BY PRODUCTS AND SERVICES:
Retail gas sales.......................................... $ 4,358 $4,645 $3,857
Wholesale energy and energy related sales................. 16,961 -- --
Gas transport............................................. 182 307 255
Energy products and services.............................. 88 92 96
------- ------ ------
Total................................................... $21,589 $5,044 $4,208
======= ====== ======
REVENUES BY GEOGRAPHIC AREAS
U.S. ..................................................... $20,539 $5,044 $4,208
Canada.................................................... 1,050 -- --
------- ------ ------
Total................................................... $21,589 $5,044 $4,208
======= ====== ======
</Table>