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                UNITED STATES SECURITIES AND EXCHANGE COMMISSION
                             WASHINGTON, D.C. 20549

                                    FORM 10-K

                                   (MARK ONE)
[X]     ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
        EXCHANGE ACT OF 1934
        FOR THE FISCAL YEAR ENDED DECEMBER 31, 2003
        OR
[  ]    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
        EXCHANGE ACT OF  1934
        FOR THE TRANSITION PERIOD FROM       TO

                         COMMISSION FILE NUMBER 1-13265

                       CENTERPOINT ENERGY RESOURCES CORP.
             (Exact name of registrant as specified in its charter)

                DELAWARE                                76-0511406
     (State or other jurisdiction of                 (I.R.S. Employer
     incorporation or organization)               Identification Number)
             1111 LOUISIANA
          HOUSTON, TEXAS 77002                        (713) 207-1111
(Address and zip code of principal               (Registrant's telephone number,
        executive offices)                            including area code)

           SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:

                                                  NAME OF EACH EXCHANGE ON WHICH
           TITLE OF EACH CLASS                               REGISTERED
-------------------------------------------       ------------------------------
NorAm Financing I 6 1/4% Convertible Trust
     Originated Preferred Securities                  New York Stock Exchange
6% Convertible Subordinated Debentures due            New York Stock Exchange
                   2012

           SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT:
                                      NONE

    CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION I(1)(a) AND (b) OF FORM 10-K AND IS THEREFORE FILING THIS FORM 10-K
WITH THE REDUCED DISCLOSURE FORMAT.

    Indicate by check mark whether the registrant: (1) has filed all reports
required to be filed by Section 13 or 15(d) of the Securities Exchange Act of
1934 during the preceding 12 months (or for such shorter period that the
registrant was required to file such reports), and (2) has been subject to such
filing requirements for the past 90 days. Yes [X] No [ ]

    Indicate by check mark if disclosure of delinquent filers pursuant to Item
405 of Regulation S-K is not contained herein and will not be contained, to the
best of the registrant's knowledge, in definitive proxy or information
statements incorporated by reference in Part III of this Form 10-K or any
amendment to this Form 10-K. [X]

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

    The aggregate market value of the common equity held by non-affiliates as of
June 30, 2003: None

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                                TABLE OF CONTENTS

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<S>             <C>                                                                         <C>
                PART I
Item 1.         Business.................................................................     1
Item 2.         Properties...............................................................    11
Item 3.         Legal Proceedings........................................................    12
Item 4.         Submission of Matters to a Vote of Security Holders......................    12
                PART II
Item 5.         Market for Common Stock and Related Stockholder Matters..................    12
Item 6.         Selected Financial Data .................................................    12
Item 7.         Management's Narrative Analysis of Results of Operations.................    13
Item 7A.        Quantitative and Qualitative Disclosures About Market Risk ..............    19
Item 8.         Financial Statements and Supplementary Data .............................    21
Item 9.         Changes in and Disagreements with Accountants on Accounting and
                Financial Disclosure.....................................................    47
Item 9A.        Controls and Procedures..................................................    47
                PART III
Item 10.        Directors and Executive Officers.........................................    47
Item 11.        Executive Compensation...................................................    47
Item 12.        Security Ownership of Certain Beneficial Owners and Management and
                Related Stockholder Matters .............................................    47
Item 13.        Certain Relationships and Related Transactions...........................    47
Item 14.        Principal Accountant Fees and Services...................................    47
                PART IV
Item 15.        Exhibits, Financial Statement Schedules, and Reports on Form 8-K ........    48
</TABLE>

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    We meet the conditions specified in General Instruction I(1)(a) and (b) to
Form 10-K and are thereby permitted to use the reduced disclosure format for
wholly owned subsidiaries of reporting companies specified therein. Accordingly,
we have omitted from this report the information called for by Item 4
(Submission of Matters to a Vote of Security Holders), Item 10 (Directors and
Executive Officers of the Registrant), Item 11 (Executive Compensation), Item 12
(Security Ownership of Certain Beneficial Owners and Management and Related
Stockholder Matters) and Item 13 (Certain Relationships and Related Party
Transactions) of Form 10-K. In lieu of the information called for by Item 6
(Selected Financial Data) and Item 7 (Management's Discussion and Analysis of
Financial Condition and Results of Operations) of Form 10-K, we have included
under Item 7 a Management's Narrative Analysis of the Results of Operations to
explain material changes in the amount of revenue and expense items between
2001, 2002 and 2003.

           CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

    From time to time we make statements concerning our expectations, beliefs,
plans, objectives, goals, strategies, future events or performance and
underlying assumptions and other statements that are not historical facts. These
statements are "forward-looking statements" within the meaning of the Private
Securities Litigation Reform Act of 1995. Actual results may differ materially
from those expressed or implied by these statements. You can generally identify
our forward-looking statements by the words "anticipate," "believe," "continue,"
"could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective,"
"plan," "potential," "predict," "projection," "should," "will," or other similar
words.

    We have based our forward-looking statements on our management's beliefs and
assumptions based on information available to our management at the time the
statements are made. We caution you that assumptions, beliefs, expectations,
intentions and projections about future events may and often do vary materially
from actual results. Therefore, we cannot assure you that actual results will
not differ materially from those expressed or implied by our forward-looking
statements.

    Some of the factors that could cause actual results to differ from those
expressed or implied by our forward-looking statements are described under "Risk
Factors" beginning on page 8 in Item 1 of this report.

    You should not place undue reliance on forward-looking statements. Each
forward-looking statement speaks only as of the date of the particular
statement, and we undertake no obligation to publicly update or revise any
forward-looking statements.

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                                     PART I

ITEM 1.  BUSINESS

                                  OUR BUSINESS

GENERAL

    We own gas distribution systems serving approximately 3 million customers in
Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Through wholly
owned subsidiaries, we own two interstate natural gas pipelines and gathering
systems and provide various ancillary services. We are an indirect wholly owned
subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility
holding company.

    Our reportable business segments are Natural Gas Distribution, Pipelines and
Gathering and Other Operations.

    CenterPoint Energy is a registered public utility holding company under the
Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act
and related rules and regulations impose a number of restrictions on the
activities of CenterPoint Energy and those of its regulated subsidiaries. The
1935 Act, among other things, limits the ability of CenterPoint Energy 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.

    Our principal executive offices are located at 1111 Louisiana, Houston,
Texas 77002 (telephone number: 713-207-1111).

     References to "we," "us," and "our" mean CenterPoint Energy Resources Corp.
(CERC Corp.) together with its subsidiaries.

NATURAL GAS DISTRIBUTION

    Our natural gas distribution business engages in intrastate natural gas
sales to, and natural gas transportation for, residential, commercial and
industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma
and Texas through three unincorporated divisions: CenterPoint Energy Arkla
(Arkla), CenterPoint Energy Entex (Entex) and CenterPoint Energy Minnegasco
(Minnegasco). These operations are regulated as natural gas utility operations
in the jurisdictions served by these divisions. Our operations also include
non-rate regulated retail gas sales to and transportation services for
commercial and industrial customers in the six states listed above as well as
several other Midwestern states.

    -   Arkla provides natural gas distribution services to approximately
        695,000 customers in over 245 communities in Arkansas, Louisiana,
        Oklahoma and Texas. The largest metropolitan areas served by Arkla are
        Little Rock, Arkansas and Shreveport, Louisiana. In 2003, approximately
        70% of Arkla's total throughput was attributable to retail sales of
        natural gas and approximately 30% was attributable to transportation
        services.

    -   Entex provides natural gas distribution services to approximately 1.6
        million customers in over 500 communities in Louisiana, Mississippi and
        Texas. The largest metropolitan area served by Entex is Houston. In
        2003, approximately 94% of Entex's total throughput was attributable to
        retail sales of natural gas and approximately 6% was attributable to
        transportation services.

    -   Minnegasco provides natural gas distribution services to approximately
        746,000 customers in over 240 communities in Minnesota. The largest
        metropolitan area served by Minnegasco is Minneapolis. In 2003,
        approximately 94% of Minnegasco's total throughput was attributable to
        retail sales of natural gas and approximately 6% was attributable to
        transportation services. Additionally, Minnegasco provides unregulated
        services consisting of heating, ventilating and air conditioning (HVAC)
        equipment and appliance sales and repair services, and home security
        monitoring.

    The demand for natural gas sales to, and natural gas transportation for,
residential, commercial and industrial customers is seasonal. In 2003,
approximately 74% of the total throughput of our natural gas distribution
business

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occurred in the first and fourth quarters. These patterns reflect the higher
demand for natural gas for heating purposes during those periods.

Supply and Transportation

    Arkla. In 2003, Arkla purchased virtually all of its natural gas supply
pursuant to term contracts, with terms varying from a few months to three years.
Arkla's major third party suppliers in 2003 included BP America Production
Company (29%), Oneok Energy Marketing and Trading LLC (23%), CenterPoint Energy
Gas Services, Inc. (CEGS) (13%) and Conoco Phillips Company (9%). Numerous other
suppliers provided the remaining 26% of Arkla's natural gas supply requirements.
Arkla transports substantially all of its natural gas supplies under contracts
with our pipeline subsidiaries.

    Entex. In 2003, Entex purchased virtually all of its natural gas supply
pursuant to term contracts, with terms varying from one to five years. Entex's
major third party suppliers in 2003 included American Electric Power Company,
Inc. (43%), Kinder Morgan, Inc. (20%), CEGS (11%), and Entergy-Koch, LP (11%).
Numerous other suppliers provided the remaining 15% of Entex's natural gas
supply requirements. Entex transports its natural gas supplies through various
interstate and intrastate pipelines under long-term contracts with terms varying
from one to five years.

    Minnegasco. In 2003, Minnegasco purchased approximately 77% of its natural
gas supply pursuant to term contracts, with terms varying from a few months to
two years. Minnegasco purchased the remaining 23% of its natural gas supply on
the spot market. Minnegasco's major third party suppliers in 2003 included BP
Canada Energy Marketing (53%), Duke Energy Trading & Marketing (8%), Tenaska
Marketing Ventures (6%), Mirant Americas Energy Marketing (5%) and NG Energy
Trading (5%). Minnegasco transports its natural gas supplies through various
interstate pipelines under long-term contracts with terms varying from one to
five years.

    Generally, the regulations of the states in which our natural gas
distribution business operates allow it to pass through changes in the costs of
natural gas to its customers under purchased gas adjustment provisions in its
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.

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

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

    On an ongoing basis, we enter into contracts to provide sufficient supplies
and pipeline capacity to meet our firm customer requirements; however, it is
possible for limited service disruptions to occur from time to time due to
weather conditions, transportation constraints and other events. As a result of
these factors, supplies of natural gas may become unavailable from time to time
or prices may increase rapidly in response to temporary supply constraints or
other factors.

Commercial and Industrial Sales

    Our commercial and industrial sales business, conducted through CEGS and
CenterPoint Energy Intrastate Gas Pipeline, provides comprehensive natural gas
products and services to commercial and industrial customers in the Gulf Coast
and Midwestern regions of the United States. Most services provided by CEGS are
not subject to rate regulation. In 2003, the commercial and industrial sales
business represented over 50% of the throughput of our Natural Gas Distribution
business segment. During that period, approximately 94% of the commercial and
industrial group's total throughput was attributable to natural gas sales; the
remainder was attributable to

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transportation services provided to third parties and affiliates. For more
information on CEGS's derivative instruments and hedging activities, please read
"Quantitative and Qualitative Disclosures About Market Risk -- Commodity Price
Risk From Non-Trading Activities" in Item 7A of this report and Note 5 to our
consolidated financial statements.

Assets

    As of December 31, 2003, we owned approximately 63,000 linear miles of gas
distribution lines, varying in size from one-half inch to 24 inches in diameter.
Generally, in each of the cities, towns and rural areas we serve, we own the
underground gas mains and service lines, metering and regulating equipment
located on customers' premises and the district regulating equipment necessary
for pressure maintenance. With a few exceptions, the measuring stations at which
we receive gas are owned, operated and maintained by others, and our
distribution facilities begin at the outlet of the measuring equipment. These
facilities, including odorizing equipment, are usually located on the land owned
by suppliers.

Competition

    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 for gas sales to end users. In addition, as
a result of federal regulatory changes affecting interstate pipelines, natural
gas marketers operating on these pipelines may be able to bypass our facilities
and market and sell and/or transport natural gas directly to commercial and
industrial customers.

PIPELINES AND GATHERING

    Our pipelines and gathering business operates two interstate natural gas
pipelines as well as gas gathering facilities and also provides pipeline
services.

    We own and operate gas transmission lines primarily located in Arkansas,
Illinois, Louisiana, Missouri, Oklahoma and Texas. Our pipeline operations are
primarily conducted by two wholly owned interstate pipeline subsidiaries which
provide gas transportation and storage services primarily to industrial
customers and local distribution companies:

    -   CenterPoint Energy Gas Transmission Company (CEGT) is an interstate
        pipeline that provides natural gas transportation, natural gas storage
        and pipeline services to customers principally in Arkansas, Louisiana,
        Oklahoma and Texas.

    -   CenterPoint Energy -- Mississippi River Transmission Corporation (MRT)
        is an interstate pipeline that provides natural gas transportation,
        natural gas storage and pipeline services to customers principally in
        Arkansas and Missouri.

    Our gathering operations are conducted by a wholly owned gas gathering
subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CEFS is a natural
gas gathering and processing business serving natural gas fields in the
Midcontinent basin of the United States that interconnect with CEGT's and MRT's
pipelines, as well as other interstate and intrastate pipelines. CEFS operates
gathering pipelines, which collect natural gas from approximately 200 separate
systems located in major producing fields in Arkansas, Louisiana, Oklahoma and
Texas.

    Our pipeline project management and facility operation services are provided
to affiliates and third parties through a wholly owned pipeline services
subsidiary, CenterPoint Energy Pipeline Services, Inc.

    In 2003, approximately 25% of our total operating revenues from pipelines
and gathering was attributable to services provided to Arkla, and approximately
10% was attributable to services to Laclede Gas Company (Laclede), an
unaffiliated distribution company that provides natural gas utility service to
the greater St. Louis metropolitan area in Illinois and Missouri. Services to
Arkla and Laclede are provided under several long-term firm storage and
transportation agreements. Contracts for firm transportation in Arkla's major
service areas are currently scheduled to expire in 2005. The Arkansas Public
Service Commission (APSC) is currently reviewing Arkla's request to enter into a
seven-year contract for firm transportation with CEGT. The agreement to provide
services to Laclede expires in 2007.

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

Assets

    We own and operate approximately 8,200 miles of gas transmission lines
primarily located in Missouri, Illinois, Arkansas, Louisiana, Oklahoma and
Texas. We also own and operate six natural gas storage fields with a combined
daily deliverability of approximately 1.2 Bcf per day and a combined working gas
capacity of approximately 59.0 Bcf. We also own a 10% interest in Gulf South
Pipeline Company, LP's Bistineau storage facility. This facility has a total
working gas capacity of 73.8 Bcf and approximately 1.1 Bcf per day of
deliverability. Our storage capacity in the Bistineau facility is 8 Bcf of
working gas with 100 MMcf per day of deliverability. Most of our storage
operations are in north Louisiana and Oklahoma. We also own and operate
approximately 4,300 miles of gathering pipelines that collect gas from
approximately 200 separate systems located in major producing fields in
Arkansas, Louisiana, Oklahoma and Texas.

Competition

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

OTHER OPERATIONS

    In 2003, Other Operations included unallocated corporate costs and
inter-segment eliminations.

FINANCIAL INFORMATION ABOUT SEGMENTS

    For financial information about our segments, see Note 12 to our
consolidated financial statements, which note is incorporated herein by
reference.

                                   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

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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.

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    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;

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    -   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.

                                       7

<PAGE>
    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.

                                    EMPLOYEES

    As of December 31, 2003, we had 5,464 full-time employees. The following
table sets forth the number of our employees by business segment as of December
31, 2003:

<TABLE>
<CAPTION>
                                                                 NUMBER REPRESENTED BY
                                                                    UNIONS OR OTHER
                                                                 COLLECTIVE BARGAINING
            BUSINESS SEGMENT                    NUMBER                  GROUPS
            ----------------                    ------           ---------------------
<S>                                             <C>              <C>
Natural Gas Distribution................          4,813                          1,549
Pipelines and Gathering.................            651                              -
                                                  -----                          -----
  Total.................................          5,464                          1,549
                                                  =====                          =====
</TABLE>

    As of December 31, 2003, approximately 28% of our employees are subject to
collective bargaining agreements. Two of these agreements, covering
approximately 9% of our employees, have expired or will expire in 2004.

    The Minnegasco division of our natural gas distribution business has 512
bargaining unit employees that are covered by collective bargaining unit
agreements that have expired or will expire in 2004. An agreement with the
International Brotherhood of Electrical Workers Local 949, which expired in
December 2003, was renegotiated in February 2004 covering 267 of these
employees. The remaining 245 employees are covered by a collective bargaining
agreement with the Office and Professional Employees International Union Local
12, which expires in May 2004.

                                  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.

                                       8

<PAGE>

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.

                                       9

<PAGE>

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;

                                       10

<PAGE>

        -   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 2.  PROPERTIES

CHARACTER OF OWNERSHIP

    We own our principal properties in fee. Also, most gas mains are located,
pursuant to easements and other rights, on public roads or on land owned by
others.

NATURAL GAS DISTRIBUTION

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

                                       11

<PAGE>

PIPELINES AND GATHERING

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

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 4.  SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

    The information called for by Item 4 is omitted pursuant to Instruction I(2)
to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

                                     PART II

ITEM 5.  MARKET FOR COMMON STOCK AND RELATED STOCKHOLDER MATTERS

    All of the 1,000 outstanding shares of CenterPoint Energy Resources Corp.'s
common stock are held by Utility Holding, LLC, a wholly owned subsidiary of
CenterPoint Energy, Inc.

    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 SEC restricts our ability to pay
dividends out of capital accounts to the extent current or retained earnings are
insufficient for those dividends.

    In 2002 and 2003, we paid dividends on our common stock of $350 million and
$-0-, respectively, to CenterPoint Energy, Inc.

ITEM 6.  SELECTED FINANCIAL DATA

    The information called for by Item 6 is omitted pursuant to Instruction I(2)
to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

                                       12

<PAGE>

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

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

    We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc.
(CenterPoint Energy), a public utility holding company created on August 31,
2002, as part of a corporate restructuring (Restructuring) of Reliant Energy,
Incorporated (Reliant Energy). CenterPoint Energy is a registered public utility
holding company under the Public Utility Holding Company Act of 1935, as amended
(1935 Act). For information about the 1935 Act, please read " -- Liquidity --
Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay
Dividends."

    Because we are an indirect wholly owned subsidiary of 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.

                    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."

                       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

                                       13

<PAGE>

various business operations, debt service costs and income tax expense.

    The following table sets forth selected financial data for the years ended
December 31, 2001, 2002 and 2003, followed by a discussion of our consolidated
results of operations based on operating income. We have provided a
reconciliation of consolidated operating income to net income below.

                           SELECTED FINANCIAL RESULTS

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                             -----------------------
                                                                         2001         2002          2003
                                                                       ----------   ----------    ----------
                                                                                  (IN MILLIONS)
<S>                                                                    <C>          <C>           <C>
Revenues...........................................................    $   5,044    $   4,208     $   5,650
                                                                       ----------   ----------    ----------
Expenses:
  Natural gas......................................................        3,781        2,901         4,297
  Operation and maintenance........................................          657          667           688
  Depreciation and amortization....................................          207          167           176
  Taxes other than income taxes....................................          133          120           130
                                                                       ----------   ----------    ----------
          Total....................................................        4,778        3,855         5,291
                                                                       ----------   ----------    ----------
Operating Income...................................................          266          353           359
Interest Expense and Distribution on Trust Preferred Securities....         (155)        (153)         (179)
Other Income, net..................................................           14            8             8
                                                                       ----------   ----------    ----------
Income Before Income Taxes.........................................          125          208           188
Income Tax Expense.................................................          (58)         (88)          (59)
                                                                       ----------   ----------    ----------
          Net Income...............................................    $      67    $     120     $     129
                                                                       ==========   ==========    ==========
</TABLE>


    2003 Compared to 2002. Our operating income increased $6 million in 2003
compared to 2002 due to higher revenues from rate increases implemented late in
2002 ($33 million), increased margins due to higher commodity prices ($8
million), improved margins from new transportation contracts to power plants ($7
million), improved margins from our unregulated commercial and industrial sales
($6 million), continued customer growth ($6 million) and improved margins from
enhanced services in our gas gathering operations ($4 million). These increases
were partially offset by decreased revenues as a result of a decrease in the
estimate of margins earned on unbilled revenues ($11 million), higher pension,
employee benefit and other miscellaneous expenses ($27 million), certain costs
being included in operating expense subsequent to the amendment of a receivables
facility in November 2002 as compared to being included in interest expense in
the prior year ($7 million) and increased bad debt expense primarily due to
higher gas prices ($9 million). Project work expenses included in operation and
maintenance expense decreased and were offset by a corresponding decrease in
revenues billed for these services ($14 million). Our effective tax rate for
2003 and 2002 was 31.3% and 42.2%, respectively. The decrease in the effective
rate for 2003 compared to 2002 was primarily the result of a non-recurring
decreased tax expense relating to our Minnesota operations.

    2002 Compared to 2001. Our operating income increased $87 million in 2002
compared to 2001 primarily as a result of improved margins 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 ($37
million). Depreciation and amortization decreased primarily as a result of the
discontinuance of goodwill amortization in 2002 in accordance with Statement of
Financial Accounting Standards (SFAS) SFAS No. 142, "Goodwill and Other
Intangible Assets" (SFAS No. 142) as further discussed in Note 2(d) to our
consolidated financial statements ($49 million). Our effective tax rate for 2002
and 2001 was 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.

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.

                                    LIQUIDITY

     Capital Requirements. We anticipate investing up to an aggregate $1.5
billion in capital expenditures in the

                                       14

<PAGE>

years 2004 through 2008, including approximately $308 million and $349 million
in 2004 and 2005, respectively.

    The following table sets forth estimates of our contractual obligations to
make future payments for 2004 through 2008 and thereafter (in millions):

<TABLE>
<CAPTION>
                                                                                                2009 AND
       CONTRACTUAL OBLIGATIONS           TOTAL    2004      2005     2006     2007      2008   THEREAFTER
-------------------------------------   -------  ------    -----    -----     ----      ----   ----------
<S>                                     <C>      <C>       <C>      <C>       <C>       <C>    <C>
Long-term debt.......................   $ 2,371  $    -    $ 367    $ 161     $  7      $307   $    1,529
Short-term borrowings, including
  credit facilities..................        63      63        -        -        -         -            -
Operating leases(1)..................        60      25       10        8        4         3           10
Non-trading derivative liabilities...        10       7        2        1        -         -            -
Other commodity commitments(2).......     2,151   1,045      565      344      171        24            2
                                        -------  ------    -----    -----     ----      ----   ----------
  Total contractual cash obligations.   $ 4,655  $1,140    $ 944    $ 514     $182      $334   $    1,541
                                        =======  ======    =====    =====     ====      ====   ==========
</TABLE>

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

     (1) For a discussion of operating leases, please read Note 9(b) to our
consolidated financial statements.

     (2) For a discussion of other commodity commitments, please read Note 9(a)
to our consolidated financial statements.

    Off-Balance Sheet Arrangements. Other than operating leases, we have no
off-balance sheet arrangements. However, we do participate in a receivables
factoring arrangement. In connection with our November 2002 amendment and
extension of our $150 million receivables facility, we formed a bankruptcy
remote subsidiary, which we consolidate, for the sole purpose of buying
receivables created by us and selling those receivables to an unrelated third
party. This transaction is accounted for as a sale of receivables under the
provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities", and, as a result, the related
receivables are excluded from the Consolidated Balance Sheet. On June 25, 2003,
we elected to reduce the receivables facility to $100 million and in January
2004, the $100 million receivables facility was replaced with a $250 million
receivables facility terminating in January 2005. For additional information
regarding this transaction please read Note 2(i) to our consolidated financial
statements.

    Long-Term and Short-Term Debt. In 2003, we completed several capital market
and bank financing transactions which, collectively, increased our borrowing
capacity, converted a portion of our interest payment obligations from floating
rates to fixed rates and refinanced current maturities of long-term debt. The
proceeds of the debt transactions in 2003 were primarily used to refinance
existing short-term debt with long-term debt, refinance maturing debt and pay
related debt issuance costs. Our 2003 capital market transactions included the
following:

<TABLE>
<CAPTION>
                                                              PRINCIPAL      INTEREST
    ISSUANCE DATE            BORROWER       SECURITY           AMOUNT         RATE        MATURITY DATE
--------------------        ----------    ------------      -------------   ----------    -------------
                                                            (IN MILLIONS)
<S>                         <C>           <C>               <C>             <C>           <C>
March and April 2003        CERC Corp.    Senior Notes       $        762       7.875%      April 2013

    November 2003           CERC Corp.    Senior Notes                160       5.950%     January 2014
</TABLE>


    In 2003, we also entered into a new credit facility, which increased
liquidity and extended the termination date of the facility it replaced. As of
December 31, 2003, we had the following credit facility.

<TABLE>
<CAPTION>
                                       SIZE OF        AMOUNT
                                     FACILITY AT    OUTSTANDING
                                       DECEMBER     AT DECEMBER                          TYPE OF
DATE EXECUTED        COMPANY           31, 2003       31, 2003      TERMINATION DATE    FACILITY
--------------       ----------      -----------    -----------     ----------------    ---------
                                            (IN MILLIONS)
<S>                  <C>             <C>            <C>             <C>                 <C>
March 25, 2003       CERC Corp.      $       200    $        63       March 23, 2004     Revolver
</TABLE>

    We are currently in discussions with banks seeking to arrange a replacement
revolving credit facility and expect to have such a facility in place on or
prior to the termination date of the existing facility. In the first quarter of
2004, we replaced our $100 million receivables facility with a $250 million
committed one-year receivables facility. The bankruptcy remote subsidiary
established in 2002 continues to buy our receivables and sell them to an
unrelated third party.

    At December 31, 2003, we had a shelf registration statement covering $50
million of debt securities.

    Cash Requirements in 2004. 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

                                       15

<PAGE>

requirements during 2004 include the following:

    -   approximately $308 million of capital expenditures; and

    -   maturity of any borrowings under our $200 million revolving credit
        agreement.

    We expect that revolving credit borrowings, anticipated cash flows from
operations and borrowings from affiliates will be sufficient to meet our cash
needs for 2004.

    Impact on Liquidity of a Downgrade in Credit Ratings. As of March 1, 2004,
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 our senior unsecured debt:

<TABLE>
<CAPTION>
       MOODY'S                S&P                 FITCH
----------------------  -------------------  -------------------
 RATING     OUTLOOK(1)  RATING   OUTLOOK(2)  RATING   OUTLOOK(3)
 ------     ----------  ------   ----------  ------   ----------
<S>         <C>         <C>      <C>         <C>      <C>
Ba1         Negative    BBB      Negative    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) An S&P rating outlook assesses the potential direction of a long-term
        credit rating over the intermediate to longer term.

    (3) A "negative" outlook from Fitch encompasses a one-to-two year horizon
        as to the likely ratings 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 borrowing costs under our $200
million 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
as more fully described in " -- Certain Contractual and Regulatory Limits on
Ability to Issue Securities and Pay Dividends" below. Additionally, a decline in
credit ratings could increase cash collateral requirements that could exist in
connection with certain contracts relating to gas purchases, gas price hedging
and gas storage activities of our Natural Gas Distribution business segment.

    Our revolving credit facility contains a "material adverse change" clause
that could impact our ability to make new borrowings under this facility. The
"material adverse change" clause in our revolving credit facility relates to any
material adverse change in the business, condition, operations, performance or
properties of the borrower or the borrower and its subsidiaries taken as a
whole.

    CenterPoint Energy Gas Services, Inc. (CEGS), a wholly owned subsidiary of
CERC Corp., provides comprehensive natural gas sales and services to industrial
and commercial customers, which are primarily located within or near the
territories served by our pipelines and natural gas distribution subsidiaries.
In order to hedge its exposure to natural gas prices, CEGS has agreements with
provisions standard for the industry that establish credit thresholds and
require a party to provide additional collateral on two business days' notice
when that party's rating or the rating of a credit support provider for that
party (CERC Corp. in this case) falls below those levels. As of December 31,
2003, the senior unsecured debt of CERC Corp. was rated BBB by S&P and Ba1 by
Moody's. We estimate that as of December 31, 2003, unsecured credit limits
extended to CEGS by counterparties could aggregate $62 million; however,
utilized credit capacity is significantly lower.

                                       16

<PAGE>

    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
on, or a non-payment default that permits acceleration of, any indebtedness at
CERC Corp. exceeding $50 million will cause a default under CenterPoint Energy's
$2.3 billion credit facility entered into in October 2003. A payment default by
us in respect of, or an acceleration of, borrowed money and certain other
specified types of obligations, in the aggregate principal amount of $50
million, will cause a default on senior debt of CenterPoint Energy aggregating
$1.4 billion.

    Pension Plan. As discussed in Note 7 to the consolidated financial
statements, we participate in CenterPoint Energy's qualified non-contributory
pension plan covering substantially all employees. Pension expense for 2004 is
estimated to be $31 million based on an expected return on plan assets of 9.0%
and a discount rate of 6.25% as of December 31, 2003. Pension expense for the
year ended December 31, 2003 was $36 million. Future changes in plan asset
returns, assumed discount rates and various other factors related to the pension
will impact our future pension expense. We cannot predict with certainty what
these factors will be in the future.

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

    -   cash collateral requirements that could exist in connection with certain
        contracts, including gas purchases, gas price hedging and gas storage
        activities of our Natural Gas Distribution business segment,
        particularly given gas price levels and volatility;

    -   acceleration of payment dates on certain gas supply contracts under
        certain circumstances, as a result of increased gas prices and
        concentration of suppliers;

    -   increased costs related to the acquisition of gas for storage;

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

    -   various regulatory actions.

    Money Pool. 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 and under an order from the SEC dated June 30, 2003 (June
2003 Financing Order) relating to our financing activities. Our money pool
borrowing limit under such financing orders is $600 million. At December 31,
2003, we had no investments in the money pool or borrowings from the money pool.
The money pool may not provide sufficient funds to meet our cash needs.

    Certain Contractual and Regulatory Limits on Ability to Issue Securities and
Pay Dividends. Factors affecting our ability to issue securities, pay dividends
on our common stock or take other actions to adjust our capitalization include:

    -   covenants and other provisions in our credit facility and receivables
        facility; and

    -   limitations imposed on us under the 1935 Act.

    Our bank facility and our receivables facility limit our debt as a
percentage of our total capitalization to 60% and contain an earnings before
interest, taxes, depreciation and amortization (EBITDA) to interest covenant.
Our bank facility also contains a provision that could, under certain
circumstances, limit the amount of dividends that could be paid by us. We are in
compliance with such covenants.

    Our parent, CenterPoint Energy, is a registered public utility holding
company under the 1935 Act. The 1935 Act and related rules and regulations
impose a number of restrictions on our parent's activities and those of its
subsidiaries, including us. The 1935 Act, among other things, limits our
parent's ability and the ability of its regulated subsidiaries, including us, 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.

                                       17

<PAGE>
    The June 2003 Financing Order is effective until June 30, 2005.
Additionally, CenterPoint Energy has received several subsequent orders which
provide additional financing authority. These orders establish limits on the
amount of external debt and equity securities that can be issued by CenterPoint
Energy and its regulated subsidiaries, including us, without additional
authorization but generally permit CenterPoint Energy and its regulated
subsidiaries, including us, to refinance our existing obligations. We are in
compliance with the authorized limits. The orders also permit our utilization of
undrawn credit facilities. As of March 1, 2004, we are authorized to issue an
additional $2 million of debt and an additional aggregate $250 million of
preferred stock and preferred securities after giving effect to our capital
market transactions in 2003.

    The SEC has reserved jurisdiction over, and must take further action to
permit, the issuance of $480 million of additional debt by us.

    The orders require that if CenterPoint Energy or any of its regulated
subsidiaries, including us, issue any securities that are rated by a nationally
recognized statistical rating organization (NRSRO), the security to be issued
must obtain an investment grade rating from at least one NRSRO and, as a
condition to such issuance, all outstanding rated securities of the issuer and
of CenterPoint Energy must be rated investment grade by at least one NRSRO. The
orders also contain certain requirements for interest rates, maturities,
issuance expenses and use of proceeds.

    The 1935 Act limits the payment of dividends to payment from current and
retained earnings unless specific authorization is obtained to pay dividends
from other sources. The June 2003 Financing Order requires us to maintain a
ratio of common equity to total capitalization of at least thirty percent (30%).

    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.

                          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. Our significant accounting policies are discussed in Note 2 to our
consolidated financial statements. We believe the following accounting policies
involve the application of critical accounting estimates. Accordingly, these
accounting estimates have been reviewed and discussed with the audit committee
of the board of directors of CenterPoint Energy.

IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES

    We review the carrying value of our long-lived assets, including goodwill
and identifiable intangibles, whenever events or changes in circumstances
indicate that such carrying values may not be recoverable, and annually for
goodwill as required by SFAS No. 142. Unforeseen events and changes in
circumstances and market condition and material differences in the value of
long-lived assets and intangibles due to changes in estimates of future cash
flows, regulatory matters and operating costs could negatively affect the fair
value of our assets and result in an impairment charge.

    Fair value is the amount at which the asset could be bought or sold in a
current transaction between willing parties and may be estimated using a number
of techniques, including quoted market prices or valuations by third parties,
present value techniques based on estimates of cash flows, or multiples of
earnings or revenue performance measures. The fair value of the asset could be
different using different estimates and assumptions in these valuation
techniques.

                                       18

<PAGE>

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. As
additional information becomes available, or actual amounts are determinable,
the recorded estimates are revised. Consequently, operating results can be
affected by revisions to prior accounting estimates.

                          NEW ACCOUNTING PRONOUNCEMENTS

    See Note 2(n) to the consolidated financial statements for a discussion of
new accounting pronouncements.

ITEM 7A.  QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

IMPACT OF CHANGES IN INTEREST RATES AND ENERGY COMMODITY PRICES

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

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

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

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

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

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

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

INTEREST RATE RISK

    We have outstanding long-term debt, mandatorily redeemable preferred
securities of subsidiary trusts holding solely our junior subordinated
debentures (trust preferred securities), a bank facility, and some lease
obligations which subject us to the risk of loss associated with movements in
market interest rates.

    Our floating-rate obligations aggregated $347 million and $63 million at
December 31, 2002 and 2003, respectively. If the floating interest rates were to
increase by 10% from their levels at December 31, 2003, our combined interest
expense would increase by a total of $0.03 million each month in which such
increase continued.

                                       19

<PAGE>

    At December 31, 2002 and 2003, we had outstanding fixed-rate debt and trust
preferred securities aggregating $2.0 billion and $2.4 billion, respectively, in
principal amount and having a fair value of $2.1 billion and $2.6 billion,
respectively. These instruments are fixed-rate and, therefore, do not expose us
to the risk of loss in earnings due to changes in market interest rates (please
read Note 6 to our consolidated financial statements). However, the fair value
of these instruments would increase by approximately $74 million if interest
rates were to decline by 10% from their levels at December 31, 2003. In general,
such an increase in fair value would impact earnings and cash flows only if we
were to reacquire all or a portion of these instruments in the open market prior
to their maturity.

COMMODITY PRICE RISK FROM NON-TRADING ACTIVITIES

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

    We use derivative instruments as economic hedges to offset the commodity
exposure inherent in our businesses. The stand-alone commodity risk created by
these instruments, without regard to the offsetting effect of the underlying
exposure these instruments are intended to hedge, is described below. We measure
the commodity risk of our Non-Trading Energy Derivatives using a sensitivity
analysis. The sensitivity analysis performed on our Non-Trading Energy
Derivatives measures the potential loss in earnings based on a hypothetical 10%
movement in energy prices. A decrease of 10% in the market prices of energy
commodities from their December 31, 2002 levels would have decreased the fair
value of our Non-Trading Energy Derivatives by $12 million. A decrease of 10% in
the market prices of energy commodities from their December 31, 2003 levels
would have decreased the fair value of our Non-Trading Energy Derivatives by $50
million.

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

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

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

    -   as applicable, anticipated underlying transactions settle as expected.

    If any of the above-mentioned assumptions ceases to be true, a loss on the
derivative instruments may occur, or the options might be worthless as
determined by the prevailing market value on their termination or maturity date,
whichever comes first. Non-Trading Energy Derivatives designated and effective
as hedges, may still have some percentage which is not effective. The change in
value of the Non-Trading Energy Derivatives that represents the ineffective
component of the hedges is recorded in our results of operations.

    CenterPoint Energy has established a Risk Oversight Committee, comprised of
corporate and business segment officers, that oversees 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,
approve trading of new products and commodities, monitor risk positions and
ensure compliance with the risk management policies and procedures and trading
limits established by 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.

                                       20

<PAGE>

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

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

                        STATEMENTS OF CONSOLIDATED INCOME

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                      2001             2002            2003
                                                                ---------------   --------------  --------------
                                                                                  (IN THOUSANDS)
<S>                                                             <C>               <C>             <C>
REVENUES....................................................    $   5,044,419     $   4,207,836   $   5,649,720
                                                                --------------    --------------  --------------
EXPENSES:
  Natural gas...............................................        3,781,200         2,900,682       4,296,928
  Operation and maintenance.................................          657,515           666,502         688,281
  Depreciation and amortization.............................          207,203           167,456         175,975
  Taxes other than income taxes.............................          132,560           119,911         129,846
                                                                --------------    --------------  --------------
      Total.................................................        4,778,478         3,854,551       5,291,030
                                                                -------------     -------------   -------------
OPERATING INCOME............................................          265,941           353,285         358,690
                                                                -------------     -------------   -------------
OTHER INCOME (EXPENSE):
  Interest expense and distribution on trust preferred
   securities...............................................         (154,993)         (153,713)       (178,985)
  Other, net................................................           14,583             8,131           7,879
                                                                --------------    --------------  --------------
      Total.................................................         (140,410)         (145,582)       (171,106)
                                                                -------------     -------------   --------------
INCOME BEFORE INCOME TAXES..................................          125,531           207,703         187,584
  Income Tax Expense........................................           58,287            87,643          58,706
                                                                --------------    --------------  --------------
NET INCOME..................................................    $      67,244     $     120,060   $     128,878
                                                                ==============    ==============  ==============
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       21

<PAGE>

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

                 STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME

<TABLE>
<CAPTION>
                                                                              YEAR ENDED DECEMBER 31,
                                                                              -----------------------
                                                                          2001          2002          2003
                                                                      ------------   -----------   -----------
                                                                                  (IN THOUSANDS)
<S>                                                                   <C>            <C>           <C>
Net income......................................................      $    67,244    $   120,060   $   128,878
                                                                      -----------    -----------   -----------
Other comprehensive income (loss), net of tax:
  Minimum non-qualified pension liability adjustment
    (net of tax of $4,703 and $790).............................            8,279          1,468             -
  Cumulative effect of adoption of SFAS No. 133 (net of tax of
    $20,511)....................................................           38,092              -             -
  Net deferred gain (loss) from cash flow hedges (net of tax of
    $23,821, $35,142 and $15,405)...............................          (11,826)        46,062        21,971
  Reclassification of net deferred loss (gain) from cash flow
    hedges realized in net income (net of tax of $18,947, $5,681
    and $569)...................................................          (61,449)           381         1,297
                                                                      ------------   -----------   -----------
Other comprehensive income (loss)...............................          (26,904)        47,911        23,268
                                                                      ------------   -----------   -----------
Comprehensive income............................................      $    40,340    $   167,971   $   152,146
                                                                      ============   ===========   ===========
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       22
<PAGE>

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

                           CONSOLIDATED BALANCE SHEETS

<TABLE>
<CAPTION>
                                                                                             DECEMBER 31,
                                                                                     ----------------------------
                                                                                         2002           2003
                                                                                     -------------  -------------
                                                                                            (IN THOUSANDS)
<S>                                                                                  <C>            <C>
                                    ASSETS
CURRENT ASSETS:
  Cash and cash equivalents.....................................................     $       9,237  $      34,447
  Accounts receivable, principally customers, net...............................           380,317        462,988
  Accrued unbilled revenue......................................................           284,112        323,844
  Inventory.....................................................................           135,707        187,226
  Non-trading derivative assets.................................................            27,275         45,897
  Taxes receivable..............................................................            61,512         32,023
  Prepaid expenses..............................................................            20,767         11,104
  Deferred tax asset............................................................            10,186             --
  Other.........................................................................            29,998         71,597
                                                                                     -------------  -------------
        Total current assets....................................................           959,111      1,169,126
                                                                                     -------------  -------------
PROPERTY, PLANT AND EQUIPMENT, NET..............................................         3,630,470      3,735,561
                                                                                     -------------  -------------
OTHER ASSETS:
  Goodwill, net.................................................................         1,740,510      1,740,510
  Other intangibles, net........................................................            19,878         20,101
  Non-trading derivative assets.................................................             3,866         11,273
  Notes receivable -- affiliated companies, net.................................            39,097         33,929
  Other.........................................................................            55,570        142,162
                                                                                     -------------  -------------
        Total other assets......................................................         1,858,921      1,947,975
                                                                                     -------------  -------------
        TOTAL ASSETS............................................................     $   6,448,502  $   6,852,662
                                                                                     =============  =============

                       LIABILITIES AND STOCKHOLDER'S EQUITY
CURRENT LIABILITIES:
  Short-term borrowings.........................................................     $     347,000  $      63,000
  Current portion of long-term debt.............................................           517,616             --
  Accounts payable, principally trade...........................................           465,694        528,394
  Accounts and notes payable -- affiliated companies, net.......................           101,231         23,351
  Taxes accrued.................................................................            57,057         65,636
  Interest accrued..............................................................            49,084         58,505
  Customer deposits.............................................................            54,081         58,372
  Non-trading derivative liabilities............................................             9,973          6,537
  Accumulated deferred income taxes, net........................................                --          8,856
  Other.........................................................................           102,510        125,132
                                                                                     -------------  -------------
        Total current liabilities...............................................         1,704,246        937,783
                                                                                     -------------  -------------
OTHER LIABILITIES:
  Accumulated deferred income taxes, net........................................           606,075        645,125
  Non-trading derivative liabilities............................................               873          3,330
  Benefit obligations...........................................................           132,434        130,980
  Other.........................................................................           520,673        571,005
                                                                                     -------------  -------------
        Total other liabilities.................................................         1,260,055      1,350,440
                                                                                     -------------  -------------
LONG-TERM DEBT..................................................................         1,441,264      2,370,974
                                                                                     -------------  -------------
COMMITMENTS AND CONTINGENCIES (NOTE 9)
CERC OBLIGATED MANDATORILY REDEEMABLE CONVERTIBLE PREFERRED
  SECURITIES OF SUBSIDIARY TRUST HOLDING SOLELY JUNIOR SUBORDINATED
  DEBENTURES OF CERC............................................................               508             --
                                                                                     -------------  -------------
STOCKHOLDER'S EQUITY............................................................         2,042,429      2,193,465
                                                                                     -------------  -------------
        TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY..............................     $   6,448,502  $   6,852,662
                                                                                     =============  =============
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       23
<PAGE>

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

                      STATEMENTS OF CONSOLIDATED CASH FLOWS

<TABLE>
<CAPTION>
                                                                           YEAR ENDED DECEMBER 31,
                                                                ---------------------------------------------
                                                                      2001            2002            2003
                                                                ------------     ------------    ------------
                                                                                (IN THOUSANDS)
<S>                                                             <C>              <C>             <C>
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income................................................    $     67,244     $    120,060    $    128,878
  Adjustments to reconcile net income to net cash
     provided by operating activities:
     Depreciation and amortization..........................         207,203          167,456         175,975
     Deferred income taxes..................................          30,320           23,003          25,097
     Amortization of deferred financing costs...............           1,096            2,770           8,424
     Changes in other assets and liabilities:
       Accounts receivable and unbilled revenues, net.......         677,383            3,275        (121,864)
       Accounts receivable/payable, affiliates..............          17,497          (65,688)         (3,784)
       Inventory............................................         (22,048)           8,762         (51,519)
       Taxes receivable.....................................              --          (61,512)         29,489
       Accounts payable.....................................        (436,875)         198,045          61,589
       Fuel cost recovery...................................           8,292           28,317         (11,350)
       Interest and taxes accrued...........................          (7,114)           7,653          18,000
       Net non-trading derivative assets and liabilities....           6,775           13,527          17,828
       Other current assets.................................         (29,573)         (32,833)        (31,936)
       Other current liabilities............................          15,256           11,604          26,913
       Other assets.........................................         (21,571)         100,118          19,663
       Other liabilities....................................          (4,726)         (92,064)         40,250
       Other, net...........................................          (7,067)           1,370         (14,481)
                                                                ------------     ------------    ------------
          Net cash provided by operating activities.........         502,092          433,863         317,172
                                                                ------------     ------------    ------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures......................................        (263,257)        (266,208)       (265,061)
  Other, net................................................          (4,834)           9,726          (7,581)
                                                                ------------     ------------    ------------
          Net cash used in investing activities.............        (268,091)        (256,482)       (272,642)
                                                                ------------     ------------    ------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Payments of long-term debt................................        (155,569)          (6,653)       (507,795)
  Proceeds from long-term debt..............................         585,632               --         928,525
  Increase (decrease) in short-term borrowings, net.........        (289,473)           1,473        (284,000)
  Increase (decrease) in notes with affiliates, net.........        (216,758)         170,658         (68,928)
  Dividends to parent.......................................        (400,000)        (350,000)             --
  Capital contribution from parent..........................         241,352               --              --
  Debt issuance costs.......................................              --               --         (87,122)
  Other, net................................................          (5,336)             (47)             --
                                                                ------------     ------------    ------------
          Net cash used in financing activities.............        (240,152)        (184,569)        (19,320)
                                                                ------------     ------------    ------------
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS........          (6,151)          (7,188)         25,210
CASH AND CASH EQUIVALENTS AT BEGINNING OF THE YEAR..........          22,576           16,425           9,237
                                                                ------------     ------------    ------------
CASH AND CASH EQUIVALENTS AT END OF THE YEAR................    $     16,425     $      9,237    $     34,447
                                                                ============     ============    ============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
  Cash Payments:
     Interest...............................................    $    148,303     $    146,244    $    164,040
     Income taxes (refunds).................................          49,872          125,085         (49,033)
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       24
<PAGE>

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

                 STATEMENTS OF CONSOLIDATED STOCKHOLDER'S EQUITY

<TABLE>
<CAPTION>
                                                                                                     ACCUMULATED
                                                      COMMON STOCK                                      OTHER           TOTAL
                                                     ---------------     PAID IN       RETAINED     COMPREHENSIVE   STOCKHOLDER'S
                                                     SHARES   AMOUNT     CAPITAL       EARNINGS     INCOME (LOSS)      EQUITY
                                                     ------   ------   -----------   ------------   -------------   -------------
                                                                                    (IN THOUSANDS)
<S>                                                  <C>      <C>      <C>           <C>            <C>             <C>
Balance at December 31, 2000 .....................    1,000   $    1   $ 2,410,716   $         --   $      (9,747)  $   2,400,970
Net income .......................................       --       --            --         67,244              --          67,244
Dividend to parent ...............................       --       --      (334,593)       (65,407)             --        (400,000)
Transfer of benefits to parent ...................       --       --       (62,080)            --              --         (62,080)
Contributions from parent ........................       --       --       241,352             --              --         241,352
Other comprehensive income (loss), net
  of tax:
  Cumulative effect of adoption of
    SFAS No 133 ..................................       --       --            --             --          38,092          38,092
  Net deferred loss from cash flow hedges ........       --       --            --             --         (11,826)        (11,826)
  Reclassification of net deferred gain from
   cash flow hedges realized in net income .......       --       --            --             --         (61,449)        (61,449)
  Additional minimum non-qualified
    pension liability adjustment .................       --       --            --             --           8,279           8,279
                                                     ------   ------   -----------   ------------   -------------   -------------
Balance at December 31, 2001 .....................    1,000        1     2,255,395          1,837         (36,651)      2,220,582

Net income .......................................       --       --            --        120,060              --         120,060
Dividend to parent ...............................       --       --      (272,907)       (77,093)             --        (350,000)
Contributions from parent ........................       --       --         3,876             --              --           3,876
Other comprehensive income, net of tax:
  Net deferred gain from cash flow hedges ........       --       --            --             --          46,062          46,062
  Reclassification of net deferred loss from
   cash flow hedges realized in net income .......       --       --            --             --             381             381
  Minimum non-qualified pension liability
   adjustment ....................................       --       --            --             --           1,468           1,468
                                                     ------   ------   -----------   ------------   -------------   -------------
Balance at December 31, 2002 .....................    1,000        1     1,986,364         44,804          11,260       2,042,429

Net income .......................................       --       --            --        128,878              --         128,878
Other ............................................       --       --        (1,110)            --              --          (1,110)
Other comprehensive income, net of tax:
  Net deferred gain from cash flow hedges ........       --       --            --             --          21,971          21,971
  Reclassification of net deferred
   loss from cash flow hedges realized in net
   income ........................................       --       --            --             --           1,297           1,297
                                                     ------   ------   -----------   ------------   -------------   -------------
Balance at December 31, 2003 .....................    1,000   $    1   $ 1,985,254   $    173,682   $      34,528   $   2,193,465
                                                     ======   ======   ===========   ============   =============   =============
</TABLE>

          See Notes to the Company's Consolidated Financial Statements

                                       25
<PAGE>

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

                   NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.  BACKGROUND AND BASIS OF PRESENTATION

    CenterPoint Energy Resources Corp. (CERC Corp.), formerly named Reliant
Energy Resources Corp. (RERC Corp.), together with its subsidiaries
(collectively, the Company), distributes natural gas, transports natural gas
through its interstate pipelines and provides natural gas gathering and pipeline
services. CERC Corp. is a Delaware corporation.

    The Company's natural gas distribution operations (Natural Gas Distribution)
are conducted by three unincorporated divisions: CenterPoint Energy Entex
(Entex), CenterPoint Energy Minnegasco (Minnegasco) and CenterPoint Energy Arkla
(Arkla) and other non-rate regulated retail gas marketing operations. The
Company's pipelines and gathering operations (Pipelines and Gathering) are
primarily conducted by two wholly owned pipeline subsidiaries, CenterPoint
Energy Gas Transmission Company (CEGT) and CenterPoint Energy-Mississippi River
Transmission Corporation (MRT), and a wholly owned gas gathering subsidiary,
CenterPoint Energy Field Services, Inc. (CEFS). The Company's principal
operations are located in Arkansas, Louisiana, Minnesota, Mississippi, Missouri,
Oklahoma and Texas.

    The Company is an indirect wholly owned subsidiary of CenterPoint Energy,
Inc. (CenterPoint Energy), a public utility holding company created on August
31, 2002, as part of a corporate restructuring (Restructuring) of Reliant
Energy, Incorporated (Reliant Energy). CenterPoint Energy is a registered public
utility holding company under the Public Utility Holding Company Act of 1935, as
amended (1935 Act). The 1935 Act and related rules and regulations impose a
number of restrictions on the activities of CenterPoint Energy and those of its
regulated subsidiaries. The 1935 Act, among other things, limits the ability of
CenterPoint Energy 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.

Basis of Presentation

    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 and distribution for, residential, commercial, industrial and
institutional customers and non-rate regulated retail gas marketing operations
to commercial and industrial customers. Pipelines and Gathering includes the
interstate natural gas pipeline operations and the natural gas gathering and
pipeline services businesses. Other Operations consists primarily of other
corporate operations which support all of the Company's business operations.

2.  SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(a) RECLASSIFICATIONS AND USE OF ESTIMATES

    Some amounts from the previous years have been reclassified to conform to
the 2003 presentation of financial statements. These reclassifications do not
affect net income.

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

(b) PRINCIPLES OF CONSOLIDATION

    The accounts of CERC Corp. and its wholly owned and majority owned
subsidiaries are included in the Company's consolidated financial statements.
All significant intercompany transactions and balances are eliminated.

                                       26
<PAGE>

Other investments, excluding marketable securities, are generally carried at
cost.

(c) REVENUES

    The Company records natural gas sales and services under the accrual method
and these revenues are generally recognized upon delivery. Natural gas sales and
services not billed by month-end are accrued based upon estimated purchased gas
volumes, estimated lost and unaccounted for gas and currently effective tariff
rates. Pipelines and Gathering records revenues as transportation services are
provided.

(d) LONG-LIVED ASSETS AND INTANGIBLES

    The Company records property, plant and equipment at historical cost. The
Company expenses all repair and maintenance costs as incurred. The cost of
utility plant and equipment retirements is charged to accumulated depreciation.
Property, plant and equipment includes the following:

<TABLE>
<CAPTION>
                                                                      DECEMBER 31,
                                             ESTIMATED USEFUL    ----------------------
                                              LIVES (YEARS)        2002          2003
                                             ----------------    --------      --------
                                                                     (IN MILLIONS)
<S>                                          <C>                 <C>           <C>
Natural gas distribution................           5-50          $  2,151      $  2,316
Pipelines and gathering.................           5-75             1,686         1,722
Other property..........................           3-20                49            49
                                                                 --------      --------
  Total.................................                            3,886         4,087
Accumulated depreciation................                             (256)         (351)
                                                                 --------      --------
  Property, plant and equipment, net....                         $  3,630      $  3,736
                                                                 ========      ========
</TABLE>

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

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

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

<TABLE>
<CAPTION>
                                                     YEAR ENDED DECEMBER 31,
                                                 -------------------------------
                                                  2001        2002        2003
                                                 -------    --------    --------
                                                           (IN MILLIONS)
<S>                                              <C>        <C>         <C>
Reported net income.......................       $    67    $    120    $    129
Add: Goodwill amortization, net of tax....            49          --          --
                                                 -------    --------    --------
Adjusted net income.......................       $   116    $    120    $    129
                                                 =======    ========    ========
</TABLE>

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

<TABLE>
<CAPTION>
                             DECEMBER 31, 2002              DECEMBER 31, 2003
                         --------------------------     --------------------------
                         CARRYING       ACCUMULATED     CARRYING      ACCUMULATED
                          AMOUNT       AMORTIZATION      AMOUNT       AMORTIZATION
                         --------      ------------     --------      ------------
                                              (IN MILLIONS)
<S>                      <C>           <C>              <C>           <C>
Land Use Rights....       $     7        $    (2)        $     7        $    (3)
Other..............            18             (3)             20             (4)
                          -------        -------         -------        -------
Total..............       $    25        $    (5)        $    27        $    (7)
                          =======        =======         =======        =======
</TABLE>

    The Company recognizes specifically identifiable intangibles when specific
rights and contracts are acquired.

                                       27
<PAGE>

The Company has no intangible assets with indefinite lives recorded as of
December 31, 2003. The Company amortizes other acquired intangibles on a
straight-line basis over the lesser of their contractual or estimated useful
lives that range from 47 to 75 years for land rights and 4 to 25 years for other
intangibles.

    Amortization expense for other intangibles for the years ended December
2001, 2002, and 2003 was $0.8 million, $1.1 million and $1.5 million,
respectively. Estimated amortization expense is approximately $3 million in 2004
and $1 million per year for the four succeeding fiscal years.

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

<TABLE>
<CAPTION>
                                 DECEMBER 31,
                                2002 AND 2003
                                -------------
<S>                             <C>
Natural Gas Distribution...       $  1,085
Pipelines and Gathering....            601
Other Operations...........             55
                                  --------
  Total....................       $  1,741
                                  ========
</TABLE>

    The Company completed its review of goodwill impairment during the second
quarter of 2003 for its reporting units pursuant to SFAS No. 142. No impairment
was indicated as a result of this assessment.

(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.

(f) DEPRECIATION AND AMORTIZATION EXPENSE

    Depreciation is computed using the straight-line method based on economic
lives or a regulatory-mandated recovery period. Other amortization expense
includes amortization of regulatory assets and other intangibles.

    The following table presents depreciation, goodwill amortization and other
amortization expense for 2001, 2002 and 2003.

<TABLE>
<CAPTION>
                                                  YEAR ENDED DECEMBER 31,
                                              --------------------------------
                                                2001        2002        2003
                                              --------    --------    --------
                                                        (IN MILLIONS)
<S>                                           <C>         <C>         <C>
Depreciation expense....................      $    146    $    153    $    161
Goodwill amortization expense...........            49          --          --
Other amortization expense..............            12          14          15
                                              --------    --------    --------
  Total depreciation and amortization...      $    207    $    167    $    176
                                              ========    ========    ========
</TABLE>

(g) CAPITALIZATION OF INTEREST

    Interest and allowance for funds used during construction (AFUDC), for
subsidiaries that apply SFAS No. 71, are capitalized as a component of projects
under construction and will be amortized over the assets' estimated useful
lives. During 2001, 2002 and 2003, the Company capitalized interest and AFUDC of
$0.2 million, $1.2 million and $0.9 million, respectively.

                                       28
<PAGE>

(h) INCOME TAXES

    The Company is included in the consolidated income tax returns of
CenterPoint Energy. The Company calculates its income tax provision on a
separate return basis under a tax sharing agreement with CenterPoint Energy. The
Company uses the liability method of accounting for deferred income taxes and
measures deferred income taxes for all significant income tax temporary
differences. Investment tax credits were deferred and are being amortized over
the estimated lives of the related property. Current federal and certain state
income taxes are payable to or receivable from CenterPoint Energy. For
additional information regarding income taxes, see Note 8.

(i) ACCOUNTS RECEIVABLE AND ALLOWANCE FOR DOUBTFUL ACCOUNTS

    Accounts receivable, principally customers, net, are net of an allowance for
doubtful accounts of $20 million and $28 million at December 31, 2002 and 2003,
respectively. The provisions for doubtful accounts in the Company's Statements
of Consolidated Income for 2001, 2002 and 2003 were $46 million, $15 million and
$24 million, respectively.

    In connection with the Company's November 2002 amendment and extension of
its $150 million receivables facility, CERC Corp. formed a bankruptcy remote
subsidiary for the sole purpose of buying receivables created by the Company and
selling those receivables to an unrelated third party. This transaction was
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. Effective June 25, 2003, the Company elected to
reduce the purchase limit under the receivables facility from $150 million to
$100 million. As of December 31, 2002 and 2003, the Company had utilized $107
million and $100 million of its receivables facility, respectively.

    The bankruptcy remote subsidiary purchases receivables with cash and
subordinated notes. In July 2003, the subordinated notes owned by the Company
were pledged to a gas supplier to secure obligations incurred in connection with
the purchase of gas by the Company.

    In the first quarter of 2004, the Company replaced the receivables facility
with a $250 million committed one-year receivables facility. The bankruptcy
remote subsidiary continues to buy the Company's receivables and sell them to an
unrelated third party.

 (j) INVENTORY

    Inventory consists principally of materials and supplies and natural gas and
is primarily valued at the lower of average cost or market. Inventory includes
the following components:

<TABLE>
<CAPTION>
                                  DECEMBER 31,
                               -----------------
                                2002       2003
                               ------     ------
                                (IN MILLIONS)
<S>                            <C>        <C>
Materials and supplies...      $   32     $   27
Natural gas..............         104        160
                               ------     ------
  Total inventory........      $  136     $  187
                               ======     ======
</TABLE>

(k) INVESTMENT IN OTHER DEBT AND EQUITY SECURITIES

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

    As of December 31, 2002 and 2003, the Company held no "available-for-sale"
securities.

                                       29
<PAGE>

(l) ENVIRONMENTAL COSTS

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

(m) STATEMENTS OF CONSOLIDATED CASH FLOWS

    For purposes of reporting cash flows, the Company considers cash equivalents
to be short-term, highly liquid investments with maturities of three months or
less from the date of purchase.

(n) NEW ACCOUNTING PRONOUNCEMENTS

    Effective January 1, 2003, the Company adopted 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.

    The Company's rate-regulated businesses recognize removal costs as a
component of depreciation expense in accordance with regulatory treatment. As of
December 31, 2002 and 2003, these removal costs of $395 million and $415
million, respectively, have been reclassified from accumulated depreciation to
other long-term liabilities in the Consolidated Balance Sheets.

    In April 2003, the FASB issued SFAS No. 149, "Amendment of Statement 133 on
Derivative Instruments and Hedging Activities" (SFAS No. 149). SFAS No. 149
clarifies when a contract with an initial net investment meets the
characteristics of a derivative as discussed in SFAS No. 133 and when a
derivative contains a financing component. SFAS No. 149 also amends certain
existing pronouncements, which will result in more consistent reporting of
contracts as either derivative or hybrid instruments. SFAS No. 149 is effective
for contracts entered into or modified after June 30, 2003 and for hedging
relationships designated after June 30, 2003, and should be applied
prospectively. Certain paragraphs of this statement that relate to forward
purchases or sales of when-issued securities or other securities that do not yet
exist should be applied to both existing contracts and new contracts entered
into after June 30, 2003. The provisions of this statement that relate to SFAS
No. 133 implementation issues that have been effective for fiscal quarters that
began prior to June 15, 2003 should continue to be applied in accordance with
their respective effective dates. The adoption of SFAS No. 149 did not have a
material effect on the Company's consolidated financial statements.

    In May 2003, the FASB issued SFAS No. 150, "Accounting for Certain Financial
Instruments with Characteristics of Both Liabilities and Equity" (SFAS No. 150).
SFAS No. 150 establishes standards for how an issuer classifies and measures
certain financial instruments with characteristics of both liabilities and
equity. It

                                       30
<PAGE>

requires that an issuer classify a financial instrument that is within its scope
as a liability (or an asset in some circumstances). Many of those instruments
were previously classified as equity. Effective July 1, 2003, upon the adoption
of SFAS No. 150, the Company reclassified $0.4 million of trust preferred
securities as long-term debt and began to recognize the dividends paid on the
trust preferred securities as interest expense. Prior to July 1, 2003, the
dividends were classified as "Distribution on Trust Preferred Securities" in the
Statements of Consolidated Income. SFAS No. 150 does not permit restatement
of prior periods. The adoption of SFAS No. 150 did not impact the Company's net
income. See discussion of FIN 46, "Consolidation of Variable Interest Entities,
an Interpretation of Accounting Research Bulletin No. 51" (FIN 46) below
regarding the accounting for the trust preferred securities at December 31,
2003.

    In January 2003, the FASB issued 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, subject to the following
additional releases by the FASB. On October 9, 2003, the FASB deferred the
application for FIN 46 until the end of the first interim period or annual
period ending after December 15, 2003 if the variable interest was created
before February 1, 2003 and a public entity had not issued financial statements
reporting the variable interest entity in accordance with FIN 46. On December
24, 2003, the FASB issued a revision to FIN 46 (FIN 46-R). The effective dates
and impact of FIN 46 and FIN 46R are as follows: (a) for special-purpose
entities (SPE's) created before February 1, 2003, the Company must apply the
provisions of FIN 46 or FIN 46-R at the end of the first interim or annual
reporting period ending after December 15, 2003, (b) for variable interest
entities created before February 1, 2003 which do not meet the definition of an
SPE provided by FIN 46-R, the Company is required to adopt FIN 46-R at the end
of the first interim or annual period ending after March 15, 2004 and (c) for
all entities, regardless of whether an SPE, that were created subsequent to
December 31, 2003, the Company is required to apply the provisions of FIN 46-R
immediately. The Company has subsidiary trusts that have Mandatorily Redeemable
Preferred Securities outstanding with a liquidation value of $0.4 million as of
December 31, 2003. These securities were issued in 1996 and were previously
reported on the Company's Consolidated Balance Sheet as CERC Obligated
Mandatorily Redeemable Preferred Securities of Subsidiary Trusts Holding Solely
Junior Subordinated Debentures of CERC (see disclosure above on SFAS No. 150).
The trusts were determined to be SPE's, and therefore, the provisions of FIN 46
or FIN 46-R were applicable to the trusts for the December 31, 2003 financial
statements. The trusts were determined to be variable interest entities under
FIN 46-R. The Company also determined that it is not the primary beneficiary of
the trusts. Therefore, the trusts and the mandatorily redeemable preferred
securities issued by the trusts are no longer reported on the Company's
Consolidated Balance Sheet as of December 31, 2003. Instead, the Company reports
its junior subordinated debentures due to the trusts as long-term debt. See Note
6. The Company has made this reclassification as of December 31, 2003 and has
elected not to restate prior period information. The Company is currently
evaluating the impact of adopting FIN 46-R applicable to non-SPE's created prior
to February 1, 2003 but does not expect a material impact.

    On December 23, 2003, the FASB issued SFAS No. 132 (Revised 2003),
"Employer's Disclosures about Pensions and Other Postretirement Benefits" (SFAS
No. 132(R)) which increases the existing disclosure requirements by requiring
more details about pension plan assets, benefit obligations, cash flows, benefit
costs and related information. Companies will be required to segregate plan
assets by category, such as debt, equity and real estate, and to provide certain
expected rates of return and other informational disclosures. SFAS No. 132(R)
also requires companies to disclose various elements of pension and
postretirement benefit costs in interim-period financial statements for quarters
beginning after December 15, 2003. The Company has adopted the disclosure
requirements of SFAS No. 132(R) in Note 7 to these consolidated financial
statements.

    In December 2003, Congress passed the Medicare Prescription Drug,
Improvement and Modernization Act of 2003 (the Act) which will become effective
in 2006. The Act contains incentives for the Company, if it continues to provide
prescription drug benefits for its retirees, through the provision of a
non-taxable reimbursement to the Company of specified costs. The Company has
many different alternatives available under the Act, and, until clarifying
regulations are issued with respect to the Act, the Company is unable to
determine the financial impact. On January 12, 2004, the FASB issued FASB Staff
Position (FSP) FAS 106-1, "Accounting and Disclosure Requirements Related to the
Medicare Prescription Drug, Improvement and Modernization Act of 2003" (FAS
106-1). In accordance with FSP FAS 106-1, the Company's postretirement benefits
obligations and net periodic postretirement benefit cost in the financial
statements and accompanying notes do not reflect the effects of the

                                       31
<PAGE>

legislation. Specific authoritative guidance on the accounting for the
legislation is pending and that guidance, when issued, may require the Company
to change previously reported information.

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.


                                       32
<PAGE>

4.  RELATED PARTY TRANSACTIONS

    From time to time, the Company has receivables from, or payables to,
CenterPoint Energy or its subsidiaries.

<TABLE>
<CAPTION>
                                                                               DECEMBER 31,
                                                                          -----------------------
                                                                            2002          2003
                                                                          ---------     ---------
                                                                              (IN MILLIONS)
<S>                                                                       <C>           <C>
Accounts receivable from affiliates...................................    $      21     $       6
Accounts payable to affiliates........................................          (48)          (29)
                                                                          ---------     ---------
   Accounts receivable/(payable) -- affiliated companies, net.........          (27)          (23)
                                                                          ---------     ---------

Note receivable from affiliates.......................................           29            --
Notes payable to affiliates...........................................         (103)           --
                                                                          ---------     ---------
   Notes receivable/(payable) -- affiliated companies, net............          (74)           --
                                                                          ---------     ---------
        Account and notes payable -- affiliated companies, net........    $    (101)    $     (23)
                                                                          =========     =========

Long-term notes receivable from affiliates............................    $      75     $      67
Long-term notes payable from affiliates...............................          (36)          (33)
                                                                          ---------     ---------
        Long-term notes receivable -- affiliated companies, net.......    $      39     $      34
                                                                          =========     =========
</TABLE>

    For the years ended December 31, 2001, 2002 and 2003, the Company had net
interest income (expense) related to affiliate borrowings of $5 million, ($2)
million and $3 million, respectively.

    The 1935 Act generally prohibits borrowings by CenterPoint Energy from its
subsidiaries, including the Company, either through the money pool or otherwise.

    In 2002, the Company supplied natural gas to Reliant Energy Services, Inc.
(Reliant Energy Services), a subsidiary of Reliant Resources, Inc. (Reliant
Resources), which was an affiliate through September 30, 2002. During 2001 and
2002, the sales and services by the Company to Reliant Resources and its
subsidiaries totaled $181 million and $42 million, respectively. During 2002 and
2003, the sales and services by the Company to CenterPoint Energy and its
affiliates totaled $28 million and $32 million, respectively. Purchases of
natural gas by the Company from Reliant Resources and its subsidiaries were $639
million and $204 million in 2001 and 2002, respectively.

    CenterPoint Energy provides some corporate services to the Company. The
costs of services have been directly charged to the Company using methods that
management believes are reasonable. These methods include negotiated usage
rates, dedicated asset assignment, and proportionate corporate formulas based on
assets, operating expenses and employees. These charges are not necessarily
indicative of what would have been incurred had the Company not been an
affiliate. Amounts charged to the Company for these services were $77 million,
$107 million and $113 million for 2001, 2002 and 2003, respectively, and are
included primarily in operation and maintenance expenses.

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.

                                       33
<PAGE>

(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:

<TABLE>
<CAPTION>
                                      DECEMBER 31, 2002            DECEMBER 31, 2003
                                  -----------------------      ------------------------
                                  INVESTMENT                   INVESTMENT
                                  GRADE(1)(2)      TOTAL       GRADE(1)(2)    TOTAL (3)
                                  -----------      ------      -----------    ---------
<S>                               <C>              <C>         <C>            <C>
Energy marketers...............     $    7         $   22        $    24      $      35
Financial institutions.........          9              9             21             21
Other..........................         --             --             --              1
                                    ------         ------        -------      ---------
  Total........................     $   16         $   31        $    45      $      57
                                    ======         ======        =======      =========
</TABLE>

    ----------

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

(c) GENERAL POLICY.

    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

                                       34
<PAGE>

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.

6.  LONG-TERM DEBT AND SHORT-TERM BORROWINGS

<TABLE>
<CAPTION>
                                                       DECEMBER 31, 2002        DECEMBER 31, 2003
                                                    ----------------------   -----------------------
                                                    LONG-TERM   CURRENT(1)   LONG-TERM    CURRENT(1)
                                                    ---------   ----------   ---------    ----------
                                                                     (IN MILLIONS)
<S>                                                 <C>         <C>          <C>          <C>
Short-term borrowings:
  Bank loans..................................                   $   347                   $    --
  Revolving credit facility...................                        --                        63
                                                                 -------                   -------
     Total short-term borrowings..............                       347                        63
                                                                 -------                   -------
Long-term debt:
  Convertible subordinated debentures 6.00% due
    2012......................................      $      76         --     $      74          --
  Senior notes 5.95% to 8.90% due 2005 to
     2014.....................................          1,331        500         2,251          --
  Junior subordinated debentures payable
    to affiliate 6.25% due 2026(2)............             --         --             6          --
  Other.......................................             36          5            36          --
Unamortized discount and premium(3)...........             (2)        13             4          --
                                                    ---------    -------     ---------     -------
     Total long-term debt.....................          1,441        518         2,371          --
                                                    ---------    -------     ---------     -------
     Total borrowings.........................      $   1,441    $   865     $   2,371     $    63
                                                    =========    =======     =========     =======
</TABLE>

----------

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

    (2) The junior subordinated debentures were issued to subsidiary trusts in
        connection with the issuance by those trusts of preferred securities.
        The trust preferred securities were deconsolidated effective December
        31, 2003 pursuant to the adoption of FIN 46. This resulted in the junior
        subordinated debentures held by the trusts being reported as long-term
        debt. For further discussion, see Note 2(n).

    (3) Debt acquired in business acquisitions is adjusted to fair market value
        as of the acquisition date. Included in long-term debt is additional
        unamortized premium related to fair value adjustments of long-term debt
        of $7 million and $6 million at December 31, 2002 and 2003,
        respectively, which is being amortized over the remaining term of the
        related long-term debt.

(a) SHORT-TERM BORROWINGS

    Credit Facilities. At December 31, 2003, CERC Corp. had a revolving credit
facility that provided for an aggregate of $200 million in committed credit. At
December 31, 2003, $63 million was borrowed under this revolving credit
facility. This revolver terminates on March 23, 2004. Rates for borrowings under
this facility, including the facility fee, are London interbank offered rate
(LIBOR) plus 250 basis points based on current credit ratings and the applicable
pricing grid. The revolving credit facility contains various business and
financial covenants. CERC Corp. is prohibited from making loans to or other
investments in CenterPoint Energy. CERC Corp. is currently in compliance with
the covenants under the credit agreement. CERC Corp. is currently in discussions
with banks seeking to arrange a replacement revolving credit facility and
expects to have such a facility in place on or prior to the termination date of
the existing facility.

    The weighted average interest rate on external short-term borrowings as of
December 31, 2002 and 2003 was 1.7% and 5.0%, respectively. These interest rates
exclude facility fees and other fees paid in connection with the arrangement of
the bank facilities.

                                       35
<PAGE>

(b) LONG-TERM DEBT

    On March 25 and April 14, 2003, the Company issued $650 million aggregate
principal amount and $112 million aggregate principal amount, respectively, of
7.875% senior notes due in 2013. A portion of the proceeds was used to refinance
$360 million aggregate principal amount of the Company's 6 3/8% Term Enhanced
ReMarketable Securities (TERM Notes) and to pay costs associated with the
refinancing. Proceeds were also used to repay approximately $340 million of bank
borrowings under the Company's $350 million revolving credit facility prior to
its expiration on March 31, 2003.

    On November 3, 2003, the Company issued $160 million aggregate principal
amount of its 5.95% senior notes due 2014. The Company accepted $140 million
aggregate principal amount of its TERM Notes maturing in November 2003 and $1.25
million as consideration for the unsecured senior notes. The Company retired the
TERM notes received and used the remaining proceeds to finance remaining costs
of issuance of the notes and for general corporate purposes.

    Junior Subordinated Debentures (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
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. As discussed in Note 2(n), upon
the Company's adoption of FIN 46, the junior subordinated debentures discussed
above are included in long-term debt as of December 31, 2003.

    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, 2002 and 2003, $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, 2003, no
interest payments on the convertible junior subordinated debentures had been
deferred.

    Maturities. The Company's consolidated maturities of long-term debt and
sinking fund requirements are $-0- in 2004, $367 million in 2005, $161 million
in 2006, $7 million in 2007 and $307 million in 2008. The 2004 amount is net of
accumulated sinking fund payments that can be satisfied with bonds that had been
acquired and retired as of December 31, 2003.

    Transportation Agreement. A subsidiary of CERC Corp. had an agreement (ANR
Agreement) with ANR Pipeline Company (ANR) that contemplated that this
subsidiary would transfer to ANR an interest in some of CERC Corp.'s pipeline
and related assets. In 2001, this subsidiary was transferred to Reliant
Resources as a result of CenterPoint Energy's planned divestiture of certain
unregulated business operations. However, the Company retained the pipelines
covered by the ANR Agreement. Therefore, the subsequent divestiture of Reliant
Resources by CenterPoint Energy on September 30, 2002, resulted in a conversion
of the Company's obligation to ANR into an obligation to Reliant Resources. As
of December 31, 2002, the Company had recorded $5 million and $36 million in
current portion of long-term debt and long-term debt, respectively, and as of
December 31, 2003, the Company had recorded $-0- and $36 million in current
portion of long-term debt and long-term debt, respectively, in its Consolidated
Balance Sheets to reflect this obligation for the use of 130 million cubic feet
(Mmcf)/day of capacity in some of the Company's transportation facilities. The
volume of transportation declined to 100 Mmcf/day in the year 2003 and CERC
refunded $5 million to Reliant Resources. The ANR Agreement will terminate in
2005 with a refund of $36 million to Reliant Resources.

                                       36
<PAGE>

(c) RESTRICTIONS ON DEBT

    CERC Corp.'s credit facility and receivables facility contain various
business and financial covenants requiring CERC Corp. to, among other things,
maintain leverage (as defined in the credit facilities), below a specified
ratio. These covenants are not anticipated to materially restrict borrowings or
the sale of receivables under these facilities. As of December 31, 2003, CERC
Corp. was in compliance with these debt covenants.

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.

(b) SAVINGS PLAN

    The Company participates in CenterPoint Energy's qualified savings plan,
which includes a cash or deferred arrangement under Section 401(k) of the
Internal Revenue Code of 1986, as amended. Under the plan, participating
employees may contribute a portion of their compensation, on a pre-tax or
after-tax basis, generally up to a maximum of 16% of compensation. CenterPoint
Energy matches 75% of the first 6% of each employee's compensation contributed.
CenterPoint Energy may contribute an additional discretionary match of up to 50%
of the first 6% of each employee's compensation contributed. These matching
contributions are fully vested at all times. A substantial portion of the
matching contribution is initially invested in CenterPoint Energy common stock.
CenterPoint Energy allocates to the Company the savings plan benefit expense
related to the Company's employees.

    Savings plan benefit expense was $12 million, $17 million and $15 million
for the years ended December 31, 2001, 2002 and 2003, respectively.

(c) POSTRETIREMENT BENEFITS

    The Company's employees participate in CenterPoint Energy's plans which
provide certain healthcare and life insurance benefits for retired employees on
a contributory and non-contributory basis. Employees become eligible for these
benefits if they have met certain age and service requirements at retirement, as
defined in the plans. Under plan amendments effective in early 1999, healthcare
benefits for future retirees were changed to limit employer contributions for
medical coverage. Such benefit costs are accrued over the active service period
of employees.

    The Company is required to fund a portion of its obligations in accordance
with rate orders. All other obligations are funded on a pay-as-you-go basis.

    On January 12, 2004, the FASB issued FSP FAS 106-1. In accordance with FSP
FAS 106-1, the Company's

                                       37
<PAGE>

postretirement benefits obligations and net periodic postretirement benefit cost
in the financial statements and accompanying notes do not reflect the effects of
the legislation. Specific authoritative guidance on the accounting for the
legislation is pending and that guidance, when issued, may require the Company
to change previously reported information.

    The net postretirement benefit cost includes the following components:

<TABLE>
<CAPTION>
                                                             YEAR ENDED DECEMBER 31,
                                                            -------------------------
                                                            2001      2002       2003
                                                            ----      ----       ----
                                                                 (IN MILLIONS)
<S>                                                         <C>       <C>        <C>
Service cost -- benefits earned during the period.........  $   2     $   2      $   2
Interest cost on projected benefit obligation.............      9         9         10
Expected return on plan assets............................     (1)       (2)        (2)
Net amortization..........................................      2         2          2
                                                            -----     -----      -----
Net postretirement benefit cost...........................  $  12     $  11      $  12
                                                            =====     =====      =====
</TABLE>

    The Company used the following assumptions to determine net postretirement
benefit costs:

<TABLE>
<CAPTION>
                                                               YEAR ENDED
                                                               DECEMBER 31,
                                                         -----------------------
                                                          2001     2002     2003
                                                         ------   ------   -----
<S>                                                      <C>      <C>      <C>
Discount rate........................................     7.50%    7.25%   6.75%
Expected return on plan assets.......................     10.0%     9.5%    9.0%
</TABLE>

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

    Following are reconciliations of the Company's beginning and ending balances
of its postretirement benefit plans benefit obligation, plan assets and funded
status for 2002 and 2003.

<TABLE>
<CAPTION>
                                                                 YEAR ENDED
                                                                DECEMBER 31,
                                                           --------------------
                                                             2002        2003
                                                           --------    --------
                                                               (IN MILLIONS)
<S>                                                        <C>         <C>
CHANGE IN BENEFIT OBLIGATION
Accumulated benefit obligation, beginning of year.....     $    131    $    155
Service cost..........................................            2           2
Interest cost.........................................            9          10
Benefits paid.........................................          (17)        (18)
Participant contributions.............................            3           4
Plan amendments.......................................           --          (2)
Actuarial loss........................................           27          20
                                                           --------    --------
Accumulated benefit obligation, end of year...........     $    155    $    171
                                                           ========    ========
CHANGE IN PLAN ASSETS
Plan assets, beginning of year........................     $     18    $     18
Benefits paid.........................................          (17)        (18)
Employer contributions................................           16          14
Participant contributions.............................            3           4
Actual investment return..............................           (2)          3
                                                           --------    --------
Plan assets, end of year..............................     $     18    $     21
                                                           ========    ========
RECONCILIATION OF FUNDED STATUS
Funded status.........................................     $   (137)   $   (150)
Unrecognized prior service cost.......................           19          15
Unrecognized actuarial loss...........................           21          40
                                                           --------    --------
Net amount recognized.................................     $    (97)   $    (95)
                                                           ========    ========
AMOUNTS RECOGNIZED IN BALANCE SHEETS
Benefit obligations...................................     $    (97)   $    (95)
                                                           --------    --------
Net amount recognized at end of year..................     $    (97)   $    (95)
                                                           ========    ========
</TABLE>

                                       38
<PAGE>

<TABLE>
<CAPTION>
                                                                 YEAR ENDED
                                                                DECEMBER 31,
                                                           --------------------
                                                             2002        2003
                                                           --------    --------
<S>                                                        <C>         <C>
ACTUARIAL ASSUMPTIONS
Discount rate..........................................        6.75%       6.25%
Expected long-term on assets...........................         9.0%        8.5%
Healthcare cost trend rate assumed for the next year...       11.25%      10.50%
Rate to which the cost trend rate is assumed to decline
   (ultimate trend rate)...............................         5.5%        5.5%
Year that the rate reaches the ultimate trend rate.....        2011        2011
Measurement date used to determine plan obligations and    December    December
   assets..............................................    31, 2002    31, 2003
</TABLE>

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

<TABLE>
<CAPTION>
                                                         1%             1%
                                                      INCREASE       DECREASE
                                                      --------       --------
                                                           (IN MILLIONS)
<S>                                                   <C>            <C>
Effect on total of service and interest cost.....      $   1          $   1
Effect on the postretirement benefit obligation..         10              9
</TABLE>

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

<TABLE>
<CAPTION>
                                                      DECEMBER 31,
                                                      ------------
                                                 2002              2003
                                                 ----              ----
<S>                                              <C>               <C>
Domestic equity securities....................    38%               40%
International equity securities...............    10                10
Debt securities...............................    52                49
Cash..........................................    --                 1
                                                 ---               ---
    Total.....................................   100%              100%
                                                 ===               ===
</TABLE>

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

    As part of the investment strategy discussed above, the Company has adopted
and maintains the following asset allocation targets for its postretirement
benefit plan:

<TABLE>
<S>                                             <C>
Domestic equity securities....................   33-43%
International equity securities...............    5-15%
Debt securities...............................   48-58%
Cash..........................................     0-2%
</TABLE>

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

    The Company expects to contribute $15 million to its postretirement benefits
plan in 2004.

(d) POSTEMPLOYMENT BENEFITS

    The Company participates in CenterPoint Energy's plan which provides
postemployment benefits for former or inactive employees, their beneficiaries
and covered dependents, after employment but before retirement (primarily
healthcare and life insurance benefits for participants in the long-term
disability plan). Postemployment benefits costs were $3 million, $6 million and
$5 million in 2001, 2002 and 2003, respectively.

                                       39
<PAGE>

(e) OTHER NON-QUALIFIED PLANS

    The Company participates in CenterPoint Energy's deferred compensation plans
that provide benefits payable to directors, officers and certain key employees
or their designated beneficiaries at specified future dates, upon termination,
retirement or death. Benefit payments are made from the general assets of the
Company. During 2001, 2002 and 2003, the Company recorded benefits expense
relating to these programs of $1 million each year. Included in "Benefit
Obligations" in the accompanying Consolidated Balance Sheets at December 31,
2002 and 2003, was $13 million and $10 million, respectively, relating to
deferred compensation plans.

(f) OTHER EMPLOYEE MATTERS

    As of December 31, 2003, approximately 28% of the Company's employees are
subject to collective bargaining agreements. Two of these agreements, covering
approximately 9% of the Company's employees, have expired or will expire in
2004.

    The Minnegasco division of the Company's natural gas distribution business
has 512 bargaining unit employees that are covered by collective bargaining unit
agreements that have expired or will expire in 2004. An agreement with the
International Brotherhood of Electrical Workers Local 949, which expired in
December 2003, was renegotiated in February 2004 covering 267 of these
employees. The remaining 245 employees are covered by a collective bargaining
agreement with the Office and Professional Employees International Union Local
12, which expires in May 2004.

8.  INCOME TAXES

    The Company's current and deferred components of income tax expense are as
follows:

<TABLE>
<CAPTION>
                              YEAR ENDED DECEMBER 31,
                             --------------------------
                             2001      2002       2003
                             -----     -----      -----
                                   (IN MILLIONS)
<S>                          <C>       <C>        <C>
Current
  Federal.............       $  31     $  56      $  30
  State...............          (3)        9          4
                             -----     -----      -----
     Total current....          28        65         34
                             -----     -----      -----
Deferred
  Federal.............          29        12         11
  State...............           1        11         14
                             -----     -----      -----
     Total deferred...          30        23         25
                             -----     -----      -----
Income tax expense....       $  58     $  88      $  59
                             =====     =====      =====
</TABLE>

    A reconciliation of the federal statutory income tax rate to the effective
income tax rate is as follows:

<TABLE>
<CAPTION>
                                                                    YEAR ENDED DECEMBER 31,
                                                                -------------------------------
                                                                 2001        2002        2003
                                                                -------     -------     -------
                                                                          (IN MILLIONS)
<S>                                                             <C>         <C>         <C>
Income before income taxes..................................    $   125     $   208     $   188
  Federal statutory rate....................................         35%         35%         35%
                                                                -------     -------     -------
Income tax expense at statutory rate........................         44          73          66
                                                                -------     -------     -------
Increase (decrease) in tax resulting from:
  Capital loss benefit......................................         --         (72)         --
  State income taxes, net of valuation allowances and
     federal income tax benefit (1).........................         (1)         13          12
  Goodwill amortization.....................................         16          --          --
  Valuation allowance, capital loss.........................         --          72          --
  Changes in estimates for prior year items.................         --          --         (19)
  Other, net................................................         (1)          2          --
                                                                -------     -------     -------
     Total..................................................         14          15          (7)
                                                                -------     -------     -------
Income tax expense..........................................    $    58     $    88     $    59
                                                                =======     =======     =======
Effective Rate..............................................       46.4%       42.2%       31.3%
</TABLE>

----------

    (1) Calculation of the accrual for state income taxes at the end of each
        year requires that the Company estimate

                                       40
<PAGE>

        the manner in which its income for that year will be allocated and/or
        apportioned among the various states in which it conducts business,
        where states have widely differing tax rules and rates. These
        allocation/apportionment factors change from year to year and the amount
        of taxes ultimately payable may differ from that estimated as a part of
        the accrual process. For these reasons, the amount of state income tax
        expense may vary significantly from year to year, even in the absence of
        significant changes to state income tax valuation allowances or changes
        in individual state income tax rates.

    Following are the Company's tax effects of temporary differences between the
carrying amounts of assets and liabilities in the financial statements and their
respective tax bases:

<TABLE>
<CAPTION>
                                                         DECEMBER 31,
                                                      -----------------
                                                        2002      2003
                                                      -------   -------
                                                        (IN MILLIONS)
<S>                                                   <C>       <C>
Deferred tax assets:
  Current:
     Current portion of capital loss..............    $     8   $    --
     Allowance for doubtful accounts..............          9         9
                                                      -------   -------
       Total current deferred tax assets..........         17         9
  Non-current:
     Employee benefits............................         79        63
     Operating and capital loss carryforwards.....         86        81
     Deferred gas costs...........................         --        18
     Other........................................         50        52
     Valuation allowance..........................        (83)      (73)
                                                      -------   -------
       Total non-current deferred tax assets......        132       141
                                                      -------   -------
       Total deferred tax assets..................        149       150
                                                      -------   -------
Deferred tax liabilities:
  Current:
     Non-trading derivative liabilities, net......          7        18
                                                      -------   -------
       Total current deferred tax liabilities.....          7        18
  Non-current:
     Depreciation.................................        685       746
     Deferred gas costs...........................          3        --
     Other........................................         50        40
                                                      -------   -------
       Total non-current deferred tax liabilities.        738       786
                                                      -------   -------
       Total deferred tax liabilities.............        745       804
                                                      -------   -------
       Accumulated deferred income taxes, net.....    $   596   $   654
                                                      =======   =======
</TABLE>

    The Company is included in the consolidated income tax returns of
CenterPoint Energy. CenterPoint Energy's consolidated federal income tax returns
have been audited and settled through the 1996 tax year. The 1997 through 2000
consolidated federal income tax returns are currently under audit.

    Tax Attribute Carryforwards. At December 31, 2003, the Company had $348
million of state tax net operating loss carryforwards. The loss carryforwards
are available to offset future state taxable income through the year 2022.
Substantially all of the state loss carryforwards will expire between 2014 and
2020. The Company also had $206 million of capital loss carryforwards which will
expire in 2007.

    The valuation allowance reflects a net increase of $68 million in 2002 and a
net decrease of $10 million in 2003. These net changes resulted from a
reassessment of the Company's future ability to use federal capital loss
carryforwards and state tax net operating loss carryforwards.

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):

                                       41
<PAGE>

<TABLE>
<S>                     <C>
2004................    $    25
2005................         10
2006................          8
2007................          4
2008................          3
2009 and beyond.....         10
                        -------
          Total.....    $    60
                        =======
</TABLE>

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

(C) LEGAL MATTERS

    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,

                                       42
<PAGE>

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,

                                       43
<PAGE>

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.

10. ESTIMATED FAIR VALUE OF FINANCIAL INSTRUMENTS

    The fair values of cash and cash equivalents, investments in debt and equity
securities classified as "available-for-sale" and "trading" in accordance with
SFAS No. 115, and short-term borrowings are estimated to be equivalent to
carrying amounts and have been excluded from the table below. The fair values of
non-trading derivative assets and liabilities are equivalent to their carrying
amounts in the Consolidated Balance Sheets at December 31, 2002 and 2003 and
have been determined using quoted market prices for the same or similar
instruments when available or other estimation techniques (see Note 5).
Therefore, these financial instruments are stated at fair value and are excluded
from the table below:

<TABLE>
<CAPTION>
                                                   DECEMBER 31, 2002       DECEMBER 31, 2003
                                                  -------------------     --------------------
                                                  CARRYING      FAIR       CARRYING     FAIR
                                                   AMOUNT      VALUE        AMOUNT      VALUE
                                                  --------   --------     --------    --------
                                                                  (IN MILLIONS)
<S>                                               <C>        <C>          <C>         <C>
Financial liabilities:
  Long-term debt (excluding capital leases)....   $  1,959   $  2,069     $  2,371    $  2,612
</TABLE>

11. UNAUDITED QUARTERLY INFORMATION

    Summarized quarterly financial data is as follows:

<TABLE>
<CAPTION>
                                          YEAR ENDED DECEMBER 31, 2002
                         ---------------------------------------------------------------
                         FIRST QUARTER   SECOND QUARTER   THIRD QUARTER   FOURTH QUARTER
                         -------------   --------------   -------------   --------------
                                                 (IN MILLIONS)
<S>                      <C>             <C>              <C>             <C>
Revenues............       $   1,242        $   868          $  737          $   1,361
Operating income....             143             48              37                125
Net income (loss)...              69              8              (5)                48
</TABLE>

<TABLE>
<CAPTION>
                                          YEAR ENDED DECEMBER 31, 2003
                         ---------------------------------------------------------------
                         FIRST QUARTER   SECOND QUARTER   THIRD QUARTER   FOURTH QUARTER
                         -------------   --------------   -------------   --------------
                                                 (IN MILLIONS)
<S>                      <C>             <C>              <C>             <C>
Revenues............       $   2,094        $ 1,032          $  950           $ 1,574
Operating income....             172             67              33                87
Net income (loss)...              88             15             (10)               36
</TABLE>

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.

                                       44
<PAGE>

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

<TABLE>
<CAPTION>
                                  NATURAL GAS   PIPELINES AND    OTHER     RECONCILING    SALES TO
                                  DISTRIBUTION    GATHERING    OPERATIONS  ELIMINATIONS  AFFILIATES  CONSOLIDATED
                                  ------------    ---------    ----------  ------------  ----------  ------------
<S>                               <C>           <C>            <C>         <C>           <C>         <C>
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
</TABLE>

----------

(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.

<TABLE>
<CAPTION>
                                                                             YEAR ENDED DECEMBER 31,
                                                                       ----------------------------------
                                                                         2001         2002        2003
                                                                       ---------    ---------   ---------
                                                                                  (IN MILLIONS)
<S>                                                                    <C>          <C>         <C>
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
                                                                       =========    =========   =========
</TABLE>


                                       45
<PAGE>

                          INDEPENDENT AUDITORS' REPORT

To the Stockholder of CenterPoint Energy Resources Corp.:

    We have audited the accompanying consolidated balance sheets of CenterPoint
Energy Resources Corp., formerly Reliant Energy Resources Corp., and its
subsidiaries (the Company) as of December 31, 2002 and 2003, and the related
consolidated statements of income, comprehensive income, stockholder's equity
and cash flows for each of the three years in the period ended December 31,
2003. Our audits also included the financial statement schedule listed in the
Index at Item 15(a)(2). These financial statements and the financial statement
schedule are the responsibility of the Company's management. Our responsibility
is to express an opinion on these financial statements and the financial
statement schedule based on our audits.

    We conducted our audits in accordance with auditing standards generally
accepted in the United States of America. Those standards require that we plan
and perform the audit to obtain reasonable assurance about whether the financial
statements are free of material misstatement. An audit includes examining, on a
test basis, evidence supporting the amounts and disclosures in the financial
statements. An audit also includes assessing the accounting principles used and
significant estimates made by management, as well as evaluating the overall
financial statement presentation. We believe that our audits provide a
reasonable basis for our opinion.

    In our opinion, such consolidated financial statements present fairly, in
all material respects, the financial position of the Company at December 31,
2002 and 2003, and the results of its operations and its cash flows for each of
the three years in the period ended December 31, 2003 in conformity with
accounting principles generally accepted in the United States of America. Also,
in our opinion, such financial statement schedule, when considered in relation
to the basic consolidated financial statements taken as a whole, presents fairly
in all material respects the information set forth therein.

    As discussed in Note 2(d) to the consolidated financial statements, on
January 1, 2002, the Company changed its method of accounting for goodwill and
certain intangible assets to conform to Statement of Financial Accounting
Standards No. 142, "Goodwill and Other Intangible Assets."

DELOITTE & TOUCHE LLP

Houston, Texas
March 12, 2004

                                       46
<PAGE>

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND
        FINANCIAL DISCLOSURE.

    None.

ITEM 9A. CONTROLS AND PROCEDURES.

    In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an
evaluation, under the supervision and with the participation of management,
including our principal executive officer and principal financial officer, of
the effectiveness of our disclosure controls and procedures as of the end of the
period covered by this report. Based on that evaluation, our principal executive
officer and principal financial officer concluded that our disclosure controls
and procedures were effective as of December 31, 2003 to provide assurance that
information required to be disclosed in our reports filed or submitted under the
Exchange Act is recorded, processed, summarized and reported within the time
periods specified in the Securities and Exchange Commission's rules and forms.

    There has been no change in our internal controls over financial reporting
that occurred during the three months ended December 31, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.

                                    PART III

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS.

    The information called for by Item 10 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 11. EXECUTIVE COMPENSATION.

    The information called for by Item 11 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND
         RELATED STOCKHOLDERS MATTERS.

    The information called for by Item 12 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS.

    The information called for by Item 13 is omitted pursuant to Instruction
I(2) to Form 10-K (Omission of Information by Certain Wholly Owned
Subsidiaries).

ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES.

     Aggregate fees billed to the Company during the fiscal years ending
December 31, 2002 and 2003 by its principal accounting firm, Deloitte & Touche
LLP, are set forth below. These fees do not include certain fees related to
general corporate matters, financial reporting, tax and other fees which have
not been allocated to the Company by CenterPoint Energy.

<TABLE>
<CAPTION>
                                                   YEAR ENDED DECEMBER 31,
                                                     2002           2003
                                                 ------------   ------------

<S>                                              <C>            <C>

Audit fees..................................      $667,000       $864,259
Audit-related fees..........................        95,100         53,935
                                                  --------       --------
     Total audit and audit-related fees.....       762,100        918,194
Tax fees....................................            --             --
All other fees..............................            --             --
                                                  --------       --------
     Total fees.............................      $762,100       $918,194
                                                  ========       ========
</TABLE>

(1) Agreed upon procedures related to our receivables facility.

    The Company is not required to and does not have an audit committee.



                                       47
<PAGE>

                                     PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES, AND REPORTS ON FORM 8-K

<TABLE>
<S>                                                                     <C>
(a)(1) Financial Statements.
  Statements of Consolidated Income for the Three Years
     Ended December 31, 2003......................................      21
  Statements of Consolidated Comprehensive Income for the
     Three Years Ended December 31, 2003..........................      22
  Consolidated Balance Sheets at December 31, 2003 and
     2002.........................................................      23
  Statements of Consolidated Cash Flows for the Three Years
     Ended December 31, 2003......................................      24
  Statements of Consolidated Shareholders' Equity for the
     Three Years Ended December 31, 2003..........................      25
  Notes to Consolidated Financial Statements......................      26
  Independent Auditors' Report....................................      46
(a)(2) Financial Statement Schedules for the Three Years
  Ended December 31, 2003.
  II -- Qualifying Valuation Accounts.............................      49
</TABLE>

     The following schedules are omitted because of the absence of the
conditions under which they are required or because the required information is
included in the financial statements:

    I, III, IV and V.

(a)(3) Exhibits

    See Index of Exhibits on page 51.

(b) Reports on Form 8-K

    On October 29, 2003, we filed a Current Report on Form 8-K dated October 29,
2003 in which we furnished information under Item 12 of that form relating to
our third quarter 2003 financial results.

    On November 5, 2003, we filed a Current Report on Form 8-K dated October 29,
2003 announcing the pricing and closing of $160 million of our senior notes in a
private placement with institutions pursuant to Rule 144A under the Securities
Act of 1933, as amended, and Regulation S. The notes bear interest at a rate of
5.95% and will be due January 15, 2014.

    On March 3, 2004, we filed a Current Report on Form 8-K dated March 3, 2004
to furnish under Item 9 of that form a slide presentation we expect will be
presented to various members of the financial and investment community from time
to time.

                                       48
<PAGE>

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

                  SCHEDULE II -- QUALIFYING VALUATION ACCOUNTS
                   FOR THE THREE YEARS ENDED DECEMBER 31, 2003

<TABLE>
<CAPTION>
                   COLUMN A                         COLUMN B     COLUMN C      COLUMN D    COLUMN E
----------------------------------------------     ----------  ------------   ----------  ---------
                                                                ADDITIONS
                                                               ------------
                                                   BALANCE AT                 DEDUCTIONS  BALANCE AT
                                                    BEGINNING     CHARGED        FROM       END OF
                  DESCRIPTION                       OF PERIOD    TO INCOME    RESERVES(1)   PERIOD
----------------------------------------------     ----------  ------------   ----------  ---------
                                                                    (IN THOUSANDS)
<S>                                                <C>         <C>            <C>         <C>
Year Ended December 31, 2003:
  Accumulated provisions:
     Uncollectible accounts receivable........     $   19,568  $    23,713    $  15,306     27,975
     Deferred tax asset valuation allowance...         82,880       (9,632)          --     73,248
Year Ended December 31, 2002:
  Accumulated provisions:
     Uncollectible accounts receivable........         33,047       15,391       28,870     19,568
     Deferred tax asset valuation allowance...         14,999       67,881           --     82,880
Year Ended December 31, 2001:
  Accumulated provisions:
     Uncollectible accounts receivable........         32,375       45,745       45,073     33,047
     Deferred tax asset valuation allowance...         47,677      (32,678)          --     14,999
</TABLE>

----------

(1) Deductions from reserves represent losses or expenses for which the
    respective reserves were created. In the case of the uncollectible accounts
    reserve, such deductions are net of recoveries of amounts previously written
    off.

                                       49
<PAGE>

                                   SIGNATURES

    Pursuant to the requirements of Section 13 or 15(d) of the Securities
Exchange Act of 1934, the registrant has duly caused this report to be signed on
its behalf by the undersigned, thereunto duly authorized, in the City of
Houston, the State of Texas, on the 12th day of March, 2004.

                                              CENTERPOINT ENERGY RESOURCES CORP.
                                                                    (Registrant)

                                                     By: /s/ DAVID M. MCCLANAHAN
                                                     ---------------------------
                                                             David M. McClanahan
                                           President and Chief Executive Officer

    Pursuant to the requirements of the Securities Exchange Act of 1934, this
report has been signed below by the following persons on behalf of the
registrant and in the capacities indicated on March 12, 2004.

<TABLE>
<CAPTION>
                   SIGNATURE                                                   TITLE
--------------------------------------------          ----------------------------------------------------
<S>                                                   <C>
          /s/ DAVID M. MCCLANAHAN                     President, Chief Executive Officer and Director
--------------------------------------------          (Principal Executive Officer and Director)
             (David M. McClanahan)

            /s/ GARY L. WHITLOCK                      Executive Vice President and Chief Financial Officer
--------------------------------------------          (Principal Financial Officer)
               (Gary L. Whitlock)

             /s/ JAMES S. BRIAN                       Senior Vice President and Chief Accounting Officer
--------------------------------------------          (Principal Accounting Officer)
                (James S. Brian)
</TABLE>

                                       50
<PAGE>

                       CENTERPOINT ENERGY RESOURCES CORP.

                   EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
                     FOR FISCAL YEAR ENDED DECEMBER 31, 2003

                                INDEX OF EXHIBITS

    Exhibits not incorporated by reference to a prior filing are designated by a
cross (+); all exhibits not so designated are incorporated herein by reference
to a prior filing as indicated.

<TABLE>
<CAPTION>
                                                                                            SEC FILE OR
EXHIBIT                                                                                     REGISTRATION   EXHIBIT
NUMBER                    DESCRIPTION                   REPORT OR REGISTRATION STATEMENT       NUMBER      REFERENCE
-------    -----------------------------------------    --------------------------------    ------------   ---------
<S>        <C>                                          <C>                                 <C>            <C>
2(a)(1)    --  Agreement and Plan of Merger             HI's Form 8-K dated August 11,           1-7629         2
                   among the Company, HL&P, HI          1996
                   Merger, Inc. and NorAm dated
                   August 11, 1996
2(a)(2)    --  Amendment to Agreement and               Registration Statement on Form        333-11329        2(c)
                   Plan of Merger among the             S-4
                   Company, HL&P, HI Merger,
                   Inc. and NorAm dated August
                   11, 1996
2(b)       --  Agreement and Plan of Merger             Registration Statement on Form        333-54526         2
                   dated December 29, 2000              S-3
                   merging Reliant Resources
                   Merger Sub, Inc. with and
                   into Reliant Energy Services,
                   Inc.
3(a)(1)    --  Certificate of Incorporation             Form 10-K for the year ended             1-3187       3(a)(1)
                   of RERC Corp.                        December 31, 1997
3(a)(2)    --  Certificate of Merger merging            Form 10-K for the year ended             1-3187       3(a)(2)
                   former NorAm Energy Corp.            December 31, 1997
                   with and into HI Merger, Inc.
                   dated August 6, 1997
3(a)(3)    --  Certificate of Amendment                 Form 10-K for the year ended             1-3187       3(a)(3)
                   changing the name to Reliant         December 31, 1998
                   Energy Resources Corp.
3(b)       --  Bylaws of RERC Corp.                     Form 10-K for the year ended             1-3187        3(b)
                                                        December 31, 1997
4(a)(1)    --  Indenture, dated as of                   NorAm's Form 10-K for the year          1-13265        4.14
                   December 1, 1986, between            ended December 31, 1986
                   NorAm and Citibank, N.A., as
                   Trustee
4(a)(2)    --  First Supplemental Indenture             Form 10-K for the year ended             1-3187       4(a)(2)
                   to Exhibit 4(a)(1) dated as          December 31, 1997
                   of September 30, 1988
4(a)(3)    --  Second Supplemental Indenture            Form 10-K for the year ended             1-3187       4(a)(3)
                   to Exhibit 4(a)(1) dated as          December 31, 1997
                   of November 15, 1989
4(a)(4)    --  Third Supplemental Indenture             Form 10-K for the year ended             1-3187       4(a)(4)
                   to Exhibit 4(a)(1) dated as          December 31, 1997
                   of August 6, 1997
4(b)(1)    --  Indenture, dated as of March             NorAm's Registration Statement         33-14586        4.20
                   31, 1987, between NorAm and          on Form S-3
                   Chase Manhattan Bank, N.A.,
                   as Trustee, authorizing 6%
                   Convertible Subordinated
                   Debentures due 2012
4(b)(2)    --  Supplemental Indenture to                Form 10-K for the year ended             1-3187       4(b)(2)
                   Exhibit 4(b)(1) dated as of          December 31, 1997
                   August 6, 1997
4(c)(1)    --  Form of Indenture between                NorAm's Registration Statement         33-64001         4.8
                   NorAm and The Bank of New            on Form S-3
                   York as Trustee

</TABLE>

                                       51

<PAGE>

<TABLE>
<CAPTION>
                                                                                            SEC FILE OR
EXHIBIT                                                                                     REGISTRATION   EXHIBIT
NUMBER                    DESCRIPTION                   REPORT OR REGISTRATION STATEMENT       NUMBER      REFERENCE
-------    -----------------------------------------    --------------------------------    ------------   ---------
<S>        <C>                                          <C>                                 <C>            <C>
4(c)(2)    --  Form of First Supplemental               NorAm's Form 8-K dated June 10,         1-13265      4.01
                   Indenture to Exhibit 4(c)(1)         1996
4(c)(3)    --  Second Supplemental Indenture            Form 10-K for the year ended             1-3187     4(d)(3)
                   to Exhibit 4(c)(1) dated as          December 31, 1997
                   of August 6, 1997
4(d)       --  Indenture, dated as of                   Registration Statement on Form        333-41017       4.1
                   December 1, 1997, between            S-3
                   RERC Corp. and Chase Bank of
                   Texas, National Association
4(e)(1)    --  Indenture, dated as of                   Form 8-K dated February 5, 1998         1-13265       4.1
                   February 1, 1998, between
                   RERC Corp. and Chase Bank of
                   Texas, National Association,
                   as Trustee
4(e)(2)    --  Supplemental Indenture No. 1,            Form 8-K dated February 5, 1998         1-13265       4.2
                   dated as of February 1, 1998,
                   providing for the issuance of
                   RERC Corp.'s 6 1/2%
                   Debentures due February 1,
                   2008
4(e)(3)    --  Supplemental Indenture No. 2,            Form 8-K dated November 9, 1998         1-13265       4.1
                   dated as of November 1, 1998,
                   providing for the issuance of
                   RERC Corp.'s 6 3/8% Term
                   Enhanced ReMarketable
                   Securities
4(e)(4)    --  Supplemental Indenture No. 3,            Registration Statement on Form        333-49162       4.2
                   dated as of July 1, 2000,            S-4
                   providing for the issuance of
                   RERC Corp.'s 8.125% Notes due
                   2005
4(e)(5)    --  Supplemental Indenture No. 4,            Form 8-K dated February 21, 2001        1-13265       4.1
                   dated as of February 15,
                   2001, providing for the
                   issuance of RERC Corp.'s
                   7.75% Notes due 2011
4(e)(6)    --  Supplemental Indenture No. 5,            Form 8-K dated March 18, 2003           1-13265       4.1
                   dated as of March 25,
                   2003, providing for the
                   issuance of CERC Corp.'s
                   7.875% Senior Notes due 2013
4(e)(7)    --  Supplemental Indenture No. 6,            Form 8-K dated April 7, 2003            1-13265       4.2
                   dated as of April 14,
                   2003, providing for the
                   issuance of CERC Corp.'s
                   7.875% Senior Notes due 2013
4(e)(8)    --  Supplemental Indenture No. 7,            Form 8-K dated October 29, 2003         1-13265       4.2
                   dated as of November 3,
                   2003, providing for the
                   issuance of CERC Corp.'s
                   5.95% Senior Notes due 2014
4(e)(9)    --  Registration Rights Agreement            Form 8-K dated October 29, 2003         1-13265       4(i)
                   dated as of November 3, 2003,
                   among CERC Corp. and the
                   initial purchasers named therein
                   relating to CERC Corp.'s
                   5.95% Senior Notes due 2014
4(f)(1)    --  Revolving Credit Agreement               Form 10-K for the year ended             1-3187      4(g)1
                   among NorAm Energy Corp. and         December 31, 2001
                   the Bank's party thereto and
                   Citibank, N.A., as Agent
                   dated as of March 31, 1998
4(f)(2)    --  Amendment Agreement dated as             Form 10-K for the year ended             1-3187      4(g)2
                   of March 23, 1999 among RERC         December 31, 2001
                   Corp., the lenders parties
                   thereto, The Bank of Nova
                   Scotia, as issuing Bank, and
                   Citibank, N.A., as Agent
</TABLE>

                                       52

<PAGE>

<TABLE>
<CAPTION>
                                                                                            SEC FILE OR
EXHIBIT                                                                                     REGISTRATION   EXHIBIT
NUMBER                    DESCRIPTION                   REPORT OR REGISTRATION STATEMENT       NUMBER      REFERENCE
-------    -----------------------------------------    --------------------------------    ------------   ---------
<S>        <C>                                          <C>                                 <C>            <C>
4(f)(3)    --  Second Amendment Agreement               Form 10-K for the year ended             1-3187       4(g)3
                   and Consent dated as of              December 31, 2001
                   August 22, 2000 among RERC
                   Corp., the lenders party
                   thereto, The Bank of Nova
                   Scotia, as Issuing Bank, and
                   Citibank, N.A., as Agent
4(f)(4)    --  Third Amendment Agreement and            Form 10-K for the year ended             1-3187       4(g)4
                   Consent, dated as of July 13,        December 31, 2001
                   2001, among RERC Corp., the
                   lenders party thereto, The
                   Bank of Nova Scotia, as
                   Issuing Bank, and Citibank,
                   N.A., as Agent
</TABLE>

    There have not been filed as exhibits to this Form 10-K certain long-term
debt instruments, including indentures, under which the total amount of
securities do not exceed 10% of the total assets of CERC. CERC hereby agrees to
furnish a copy of any such instrument to the SEC upon request.

<TABLE>
<CAPTION>
                                                                                            SEC FILE OR
EXHIBIT                                                                                     REGISTRATION   EXHIBIT
NUMBER                    DESCRIPTION                   REPORT OR REGISTRATION STATEMENT       NUMBER      REFERENCE
-------    -----------------------------------------    --------------------------------    ------------   ---------
<S>        <C>                                          <C>                                 <C>            <C>
10(a)      --  Service Agreement by and be-             NorAm's Form 10-K for the year          1-13265      10.20
                   tween Mississippi River              ended December 31, 1989
                   Transmission Corporation and
                   Laclede Gas Company dated
                   August 22, 1989
10(b)      --  $200,000,000 Credit Agreement,           Form 10-Q for the quarter ended         1-13265       4(a)
                   dated as of March 25, 2003,          March 31, 2003
                   among CERC Corp., as
                   borrower, and the banks named
                   therein
+12        --  Computation of Ratios of Earn-
                   ings to Fixed Charges
+23        --  Consent of Deloitte & Touche
                   LLP
+31.1      --  Rule 13a-14(a)/15d-14(a)
                   Certification of David M.
                   McClanahan
+31.2      --  Rule 13a-14(a)/15d-14(a)
                   Certification of Gary L.
                   Whitlock
+32.1      --  Section 1350 Certification of David
                   M. McClanahan
+32.2      --  Section 1350 Certification of Gary
                   L. Whitlock
</TABLE>

                                       53