EXHIBIT 99.1
ITEM 1. BUSINESS

REGULATION

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

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

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

CenterPoint Energy received an order from the SEC under the 1935 Act on June
30, 2003 and supplemental orders thereafter relating to its financing activities
and those of its regulated subsidiaries, including us, as well as other matters.
The orders are effective until June 30, 2005. As of December 31, 2003, the
orders generally permitted CenterPoint Energy and its subsidiaries, including
us, to issue securities to refinance indebtedness outstanding at June 30, 2003,
and authorized CenterPoint Energy and its subsidiaries, including us, to issue
certain incremental external debt securities and common and preferred stock
through June 30, 2005, without prior authorization from the SEC. The orders also
contain certain requirements regarding ratings of CenterPoint Energy's
securities, interest rates, maturities, issuance expenses and use of proceeds.
The orders require that we maintain a ratio of common equity to total
capitalization of at least 30%.

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.

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

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, though franchises in
Arkansas are perpetual. None of our material franchises expire in the near term.
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 by our local distribution
divisions are subject to traditional cost-of-service regulation at rates
regulated by the relevant state public utility commissions and, in Texas, by the
Railroad Commission of Texas (Railroad Commission) and municipalities we serve.

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

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

Our gas distribution divisions generally recover the cost of gas provided to
customers through gas cost adjustment mechanisms prescribed in their tariffs
that are approved by the appropriate regulatory authority. Recently, our Arkla
and Entex divisions have been involved in both litigation and regulatory
proceedings in which parties have challenged the gas costs that have been
recovered from customers. In response to a claim by the City of Tyler, Texas
that excessive costs, ranging from $2.8 million to $39.2 million, may have been
incurred for gas purchased by Entex for resale to residential and small
commercial customers, Entex and the City of Tyler have requested that the
Railroad Commission determine whether Entex has properly and lawfully charged
and collected for gas service to its residential and commercial customers in its
Tyler distribution system for the period beginning November 1, 1992, and ending
October 31, 2002. Similarly, a complaint has been filed with the LPSC by a
private party alleging that certain gas costs recovered from Entex customers in
Louisiana were excessive and/or were not properly authorized by the LPSC.
Additionally, certain private litigants have filed suit in Louisiana state
courts, alleging that inappropriate or excessive gas costs have been recovered
from Arkla's customers.

DEPARTMENT OF TRANSPORTATION

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

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

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

ENVIRONMENTAL MATTERS

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

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

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

- noise emissions from our facilities; and

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

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

- construct or acquire new equipment;

- modify or replace existing and proposed equipment; and

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

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

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

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

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

LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION

Hydrocarbon Contamination. We and certain of our subsidiaries are among some
of the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and
Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior
to 1985, the defendants allowed or caused hydrocarbon or chemical contamination
of the Wilcox Aquifer, which lies beneath property owned or leased by certain of
the defendants and which is the sole or primary drinking water aquifer in the
area. The primary source of the contamination is alleged by the plaintiffs to be
a gas processing facility in Haughton, Bossier Parish, Louisiana known as the
"Sligo Facility," which was formerly operated by a predecessor in interest of
ours. This facility was purportedly used for gathering natural gas from
surrounding wells, separating gasoline and hydrocarbons from the natural gas for
marketing, and transmission of natural gas for distribution.

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

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, 2003, we had accrued $19 million for remediation of certain
Minnesota sites. At December 31, 2003, the estimated range of possible
remediation costs for these sites was $8 million to $44 million based on
remediation continuing for 30 to 50 years. The cost estimates are based on
studies of a site or industry average costs for remediation of sites of similar
size. The actual remediation costs will be dependent upon the number of sites to
be remediated, the participation of other potentially responsible parties (PRP),
if any, and the remediation methods used. We have utilized an environmental
expense tracker mechanism in our rates in Minnesota to recover estimated costs
in excess of insurance recovery. We have collected or accrued $12.5 million as
of December 31, 2003 to be used for environmental remediation.

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

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

Other Environmental. From time to time, we have received notices from
regulatory authorities or others regarding our status as a PRP in connection
with sites found to require remediation due to the presence of environmental
contaminants. Although their ultimate outcome cannot be predicted at this time,
we do not believe, based on our experience to date, that these matters, either
individually or in the aggregate, will have a material adverse effect on our
financial condition, results of operations or cash flows.

RISK FACTORS

PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES

RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY FULL RECOVERY OF OUR
COSTS.

Our rates for natural gas distribution are regulated by certain
municipalities and state commissions based on an analysis of our invested
capital and our expenses incurred in a test year. Thus, the rates that we are
allowed to charge may not match our expenses at any given time. While rate
regulation is, generally, premised on providing a reasonable opportunity to
recover reasonable and necessary operating expenses and to earn a reasonable
return on invested capital, there can be no assurance that the municipalities
and state commissions will judge all of our costs to be reasonable or necessary
or that the regulatory process in which rates are determined will always result
in rates that will produce full recovery of our costs.

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

We compete primarily with alternate energy sources such as electricity and
other fuel sources. In some areas, intrastate pipelines, other natural gas
distributors and marketers also compete directly with 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 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.

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

We are subject to risk associated with price movements of natural gas.
Movements in 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 consumption in our service territory.
Additionally, increasing gas prices could create the need for us to provide
collateral in order to purchase gas.

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.

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

Contracts with two of our significant pipeline 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, there could be an adverse effect on our results of
operations, financial condition and cash flows.

OUR INTERSTATE PIPELINES' REVENUES AND RESULTS OF OPERATIONS 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 substantial 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.

RISK FACTORS ASSOCIATED WITH OUR FINANCIAL CONDITION

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

As of December 31, 2003, we had $2.4 billion of outstanding indebtedness.
Approximately $518 million principal amount of this debt must be paid through
2006. In addition, the capital constraints and other factors currently impacting
our parent company's and our businesses may require our future indebtedness to
include terms that are more restrictive or burdensome than those of our current
or historical indebtedness. These terms may negatively impact our ability to
operate our business or adversely affect our financial condition and results of
operations. 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 markets in which we operate;

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

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

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

- 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 the Results of Operations -- Liquidity -- Impact on Liquidity of a Downgrade
in Credit Ratings" in Item 7 of Part II of this report. We cannot assure you
that these credit ratings will remain in effect for any given period of time or
that one or more of these ratings will not be lowered or withdrawn entirely by a
rating agency. We note that these credit ratings are not recommendations to buy,
sell or hold our securities. Each rating should be evaluated independently of
any other rating. Any future reduction or withdrawal of one or more of our
credit ratings could have a material adverse impact on our ability to access
capital on acceptable terms.

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 $3.0 billion principal amount of debt required to be paid through
2006. This amount excludes amounts related to capital leases, securitization
debt and indexed debt securities obligations. 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.

OTHER RISKS

WE, AS A SUBSIDIARY OF CENTERPOINT ENERGY, A HOLDING COMPANY, ARE SUBJECT TO
REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS
IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES.

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

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

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

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

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

ITEM 3. LEGAL PROCEEDINGS

For a brief description of certain legal and regulatory proceedings
affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of
this report and Notes 3, 9(c) and 9(d) to our consolidated financial statements,
which information is incorporated herein by reference.

ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

- 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;

- timely rate increases, including recovery of costs;

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

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

- changes in interest rates or rates of inflation;

- weather variations and other natural phenomena;

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

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

- actions by rating agencies;

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

- non-payment of our services due to financial distress of our customers;
and

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(e) REGULATORY ASSETS AND LIABILITIES

The Company applies the accounting policies established in SFAS No. 71,
"Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the
accounts of the utility operations of Natural Gas Distribution and MRT. As of
December 31, 2002 and 2003, the Company had recorded $31 million and $34 million
of regulatory assets, respectively, which are included in other long-term assets
on our Consolidated Balance Sheets. As of December 31, 2002 and 2003, the
Company had recorded $19 million and $434 million of regulatory liabilities,
respectively, which are included in other long-term liabilities on our
Consolidated Balance Sheets. Included in regulatory liabilities at December 31,
2003, is $415 million of removal costs that resulted from a reclassification of
removal costs from accumulated depreciation in accordance with SFAS No. 143,
"Accounting for Asset Retirement Obligations" (SFAS No. 143). For further
information, see Note 2(n).

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

3. REGULATORY MATTERS

(a) RATE CASES

In August 2002, a settlement was approved by the Arkansas Public Service
Commission (APSC) that resulted in an increase in the base rate and service
charge revenues of Arkla of approximately $27 million annually. In addition, the
APSC approved a gas main replacement surcharge that provided $2 million of
additional revenue in 2003 and is expected to provide additional amounts in
subsequent years.

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

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

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

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

(b) OTHER REGULATORY PROCEEDINGS

City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas,
asserted that Entex had overcharged residential and small commercial customers
in that city for excessive gas costs under supply agreements in effect since
1992. That dispute has been referred to the Texas Railroad Commission by
agreement of the parties for a determination of whether Entex has properly and
lawfully charged and collected for gas service to its residential and commercial
customers in its Tyler distribution system for the period beginning November 1,
1992, and ending October 31, 2002. The Company believes that all costs for
Entex's Tyler distribution system have been properly included and recovered from
customers pursuant to Entex's filed tariffs.

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

Following issuance of the Show Cause Order, CEGT made certain compliance
filings, met with members of the FERC's staff and provided additional
information relating to the FERC's Show Cause Order. On March 4, 2004, the FERC
issued orders accepting CEGT's compliance filings and approving a Stipulation
and Consent Agreement with CEGT that resolved the issues raised by the Show
Cause Order. The resolution of these issues did not have a material impact on
our results of operations, financial condition and cash flows.

5. DERIVATIVE INSTRUMENTS

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

(a) NON-TRADING ACTIVITIES.

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

During 2003, no hedge ineffectiveness was recognized in earnings from
derivatives that are designated and qualify as Cash Flow Hedges. No component of
the derivative instruments' gain or loss was excluded from the assessment of
effectiveness. If it becomes probable that an anticipated transaction will not
occur, the Company realizes in net income the deferred gains and losses
recognized in accumulated other comprehensive income. Once the anticipated
transaction occurs, the accumulated deferred gain or loss recognized in
accumulated other comprehensive income is reclassified and included in the
Company's Statements of Consolidated Income under the caption "Natural Gas."
Cash flows resulting from these transactions in non-trading energy derivatives
are included in the Statements of Consolidated Cash Flows in the same category
as the item being hedged. As of December 31, 2003, the Company expects $39
million in accumulated other comprehensive income to be reclassified into net
income during the next twelve months.

The maximum length of time the Company is hedging its exposure to the
variability in future cash flows for forecasted transactions on existing
financial instruments is primarily two years with a limited amount of exposure
up to three years. The Company'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 the Company's non-trading derivative activities. Credit risk relates
to the risk of loss resulting from non-performance of contractual obligations by
a counterparty. The following table shows the composition of the non-trading
derivative assets of the Company as of December 31, 2002 and 2003:

DECEMBER 31, 2002 DECEMBER 31, 2003
----------------------- ------------------------
INVESTMENT INVESTMENT
GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL (3)
----------- ------ ----------- ---------

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

----------

(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 $35 million non-trading derivative asset includes an $11 million
asset due to trades with Reliant Energy Services, a former affiliate.
As of December 31, 2003, 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 commodity price and credit
risk activities, including the trading, marketing, risk management services and
hedging activities of CenterPoint Energy and its subsidiaries, including us. The
committee's duties are to establish 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. EMPLOYEE BENEFIT PLANS

(a) PENSION PLANS

Substantially all of the Company'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 the Company 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. The
Company recognized pension expense of $1 million, $13 million and $36 million
for the years ended December 31, 2001, 2002 and 2003, respectively.

In addition to the Plan, the Company 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 $5 million, $2 million and $3 million for the years ended
December 31, 2001, 2002 and 2003, respectively.

9. COMMITMENTS AND CONTINGENCIES

(A) COMMITMENTS

Environmental Capital Commitments. The Company has various commitments for
capital and environmental expenditures. The Company anticipates no significant
capital and other special project expenditures between 2004 and 2008 for
environmental compliance.

Fuel Commitments. Fuel commitments include several long-term natural gas
contracts related to the Company's natural gas distribution operations, which
have various quantity requirements and durations that are not classified as
non-trading derivative assets and liabilities in the Company's Consolidated
Balance Sheets as of December 31, 2003 as these contracts meet the SFAS No. 133
exception to be classified as "normal purchases contracts" or do not meet the
definition of a derivative. Minimum payment obligations for natural gas supply
contracts are approximately $1 billion in 2004, $565 million in 2005, $344
million in 2006, $171 million in 2007 and $24 million in 2008.

(B) LEASE COMMITMENTS

The following table sets forth information concerning the Company'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):

2004................ $ 25
2005................ 10
2006................ 8
2007................ 4
2008................ 3
2009 and beyond..... 10
-------
Total..... $ 60
=======

Total rental expense for all operating leases was $31 million, $31 million
and $28 million in 2001, 2002 and 2003, respectively.

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

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

Gas Cost Recovery Litigation. In October 2002, a suit was filed in state
district court in Wharton County, Texas against CenterPoint Energy, the Company,
Entex Gas Marketing Company, and others alleging fraud, violations of the Texas
Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil
conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The
plaintiffs seek class certification, but no class has been certified. The
plaintiffs allege that defendants inflated the prices charged to certain
consumers of natural gas. In February 2003, a similar suit was filed against the
Company 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 the Company. In February 2004,
another suit was filed against the Company in Calcasieu Parish, Louisiana,
seeking to recover alleged overcharges for gas or gas services allegedly
provided by Entex without advance approval by the LPSC. The plaintiffs in these
cases seek injunctive and declaratory relief, restitution for the alleged
overcharges, exemplary damages or trebling of actual damages and civil
penalties. In these cases, CenterPoint Energy, the Company and Entex Gas
Marketing Company deny that they have overcharged any of their customers for
natural gas and believe that the amounts recovered for purchased gas have been
in accordance with what is permitted by state regulatory authorities.

(D) ENVIRONMENTAL MATTERS

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among some of the defendants in lawsuits filed beginning in August 2001 in Caddo
Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified
date prior to 1985, the defendants allowed or caused hydrocarbon or chemical
contamination of the Wilcox Aquifer, which lies beneath property owned or leased
by certain of the defendants and which is the sole or primary drinking water
aquifer in the area. The primary source of the contamination is alleged by the
plaintiffs to be a gas processing facility in Haughton, Bossier Parish,
Louisiana known as the "Sligo Facility," which was formerly operated by a
predecessor in interest of CERC Corp. This facility was purportedly used for
gathering natural gas from surrounding wells, separating gasoline and
hydrocarbons from the natural gas for marketing, and transmission of natural gas
for distribution.

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

Manufactured Gas Plant Sites. The Company 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 the Company's Minnesota service territory, two of
which it believes were neither owned nor operated by the Company, and for which
it believes it has no liability.

At December 31, 2003, the Company had accrued $19 million for remediation of
certain Minnesota sites. At December 31, 2003, the estimated range of possible
remediation costs for these sites was $8 million to $44 million based on
remediation continuing for 30 to 50 years. The cost estimates are based on
studies of a site or industry average costs for remediation of sites of similar
size. The actual remediation costs will be dependent upon the number of sites to
be remediated, the participation of other potentially responsible parties (PRP),
if any, and the remediation methods used. The Company has utilized an
environmental expense tracker mechanism in its rates in Minnesota to recover
estimated costs in excess of insurance recovery. The Company has collected or
accrued $12.5 million as of December 31, 2003 to be used for environmental
remediation.

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

Mercury Contamination. The Company's pipeline and distribution operations
have in the past employed elemental mercury in measuring and regulating
equipment. It is possible that small amounts of mercury may have been spilled in
the course of normal maintenance and replacement operations and that these
spills may have contaminated the immediate area with elemental mercury. This
type of contamination has been found by the Company at some sites in the past,
and the Company has conducted remediation at these sites. It is possible that
other contaminated sites may exist and that remediation costs may be incurred
for these sites. Although the total amount of these costs cannot be known at
this time, based on experience by the Company and that of others in the natural
gas industry to date and on the current regulations regarding remediation of
these sites, the Company believes that the costs of any remediation of these
sites will not be material to the Company's financial condition, results of
operations or cash flows.

Other Environmental. From time to time the Company has received notices from
regulatory authorities or others regarding its status as a PRP in connection
with sites found to require remediation due to the presence of environmental
contaminants. The Company anticipates that additional claims like those received
may be asserted in the future and intends to continue vigorously contesting
claims which it does not consider to have merit. Although their ultimate outcome
cannot be predicted at this time, the Company does not believe, based on its
experience to date, that these matters, either individually or in the aggregate,
will have a material adverse effect on the Company's financial condition,
results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory
proceedings before various courts, regulatory commissions and governmental
agencies regarding matters arising in the ordinary course of business. Some of
these proceedings involve substantial amounts. The Company's management
regularly analyzes current information and, as necessary, provides accruals for
probable liabilities on the eventual disposition of these matters. The Company's
management believes that the disposition of these matters will not have a
material adverse effect on the Company's financial condition, results of
operations or cash flows.

12. REPORTABLE SEGMENTS

Because CERC Corp. is an indirect wholly owned subsidiary of CenterPoint
Energy, the Company'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 Company's reportable business segments include the following: Natural
Gas Distribution, Pipelines and Gathering 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. Other Operations includes unallocated general
corporate expenses and non-operating investments. All of the Company's
long-lived assets are in the United States.

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

NATURAL GAS PIPELINES AND OTHER RECONCILING SALES TO
DISTRIBUTION GATHERING OPERATIONS ELIMINATIONS AFFILIATES CONSOLIDATED
------------ --------- ---------- ------------ ---------- ------------

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
Operating income (loss).......... 130 137 (1) -- -- 266
Total assets..................... 4,083 2,379 101 (182) -- 6,381
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............ 33 121 -- (154) -- --
Depreciation and amortization.... 126 41 -- -- -- 167
Operating income................. 198 153 2 -- -- 353
Total assets..................... 4,428 2,500 206 (685) -- 6,449
Expenditures for long-lived
assets......................... 196 70 -- -- -- 266
AS OF AND FOR THE YEAR ENDED
DECEMBER 31, 2003:
Revenues from external
customers...................... 5,378 241 -- -- 31 5,650
Intersegment revenues............ 57 166 9 (232) -- --
Depreciation and amortization.... 136 40 -- -- -- 176
Operating income (loss).......... 202 158 (1) -- -- 359
Total assets..................... 4,661 2,519 388 (715) -- 6,853
Expenditures for long-lived
assets......................... 199 66 -- -- -- 265

- ----------

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

YEAR ENDED DECEMBER 31,
----------------------------------
2001 2002 2003
--------- --------- ---------
(IN MILLIONS)

REVENUES BY PRODUCTS AND SERVICES:
Retail gas sales................................................... $ 4,645 $ 3,857 $ 5,310
Gas transportation................................................. 307 255 244
Energy products and services....................................... 92 96 96
--------- --------- ---------
Total............................................................ $ 5,044 $ 4,208 $ 5,650
========= ========= =========