CENTERPOINT ENERGY RESOURCES CORP - 10-Q Quarterly Report

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

FORM 10-Q

(Mark One)

[X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE
ACT OF 1934

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 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 incorporation or organization) (I.R.S. Employer Identification No.)

1111 LOUISIANA
HOUSTON, TEXAS 77002
(Address of principal executive offices) (Zip Code)

(713) 207-1111
(Registrant's telephone number, including area code)

CENTERPOINT ENERGY RESOURCES CORP. MEETS THE CONDITIONS SET FORTH IN GENERAL
INSTRUCTION H(1)(a) AND (b) OF FORM 10-Q AND IS THEREFORE FILING THIS FORM 10-Q
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 whether the registrant is an accelerated filer (as
defined in Rule 12b-2 of the Exchange Act). Yes No X
--- ---

As of November 3, 2003, all 1,000 shares of CenterPoint Energy Resources Corp.
common stock were held by Utility Holding, LLC, a wholly owned subsidiary of
CenterPoint Energy, Inc.

CENTERPOINT ENERGY RESOURCES CORP.
QUARTERLY REPORT ON FORM 10-Q
FOR THE QUARTER ENDED SEPTEMBER 30, 2003

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.................................................................1

Statements of Consolidated Operations
Three and Nine Months Ended September 30, 2002 and 2003 (unaudited)...................1

Consolidated Balance Sheets
December 31, 2002 and September 30, 2003 (unaudited)..................................2

Statements of Consolidated Cash Flows
Nine Months Ended September 30, 2002 and 2003 (unaudited).............................4

Notes to Unaudited Consolidated Interim Financial Statements.............................5

Item 2. Management's Narrative Analysis of the Results of Operations of
CenterPoint Energy Resources Corp. and Subsidiaries.....................................16

Item 4. Controls and Procedures.............................................................26

PART II. OTHER INFORMATION

Item 1. Legal Proceedings...................................................................27

Item 5. Other Information...................................................................27

Item 6. Exhibits and Reports on Form 8-K....................................................30

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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" in Item 5 of Part II 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.

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PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS.

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED OPERATIONS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to the Company's Unaudited Consolidated Interim Financial Statements

1

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

ASSETS

See Notes to the Company's Unaudited Interim Consolidated Financial Statements

2

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
CONSOLIDATED BALANCE SHEETS -- (CONTINUED)
(THOUSANDS OF DOLLARS)
(UNAUDITED)

LIABILITIES AND STOCKHOLDER'S EQUITY

See Notes to the Company's Unaudited Consolidated Interim Financial Statements

3

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES
(AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.)
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)
(UNAUDITED)

See Notes to the Company's Unaudited Consolidated Interim Financial Statements

4

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED INTERIM FINANCIAL STATEMENTS

(1) BACKGROUND AND BASIS OF PRESENTATION

Included in this Quarterly Report on Form 10-Q of CenterPoint Energy

Resources Corp. (CERC Corp.), together with its wholly owned and majority owned
subsidiaries (the Company), are the Company's consolidated interim financial
statements and notes (Interim Financial Statements). The Company has filed a
Current Report on Form 8-K dated June 16, 2003 (June 16, 2003 Form 8-K). The
June 16, 2003 Form 8-K gives retroactive effect of the adoption of Emerging
Issues Task Force (EITF) No. 02-03 "Issues Involved in Accounting for Derivative
Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and
Risk Management Activities" (EITF No. 02-03). The Company's adoption of EITF No.
02-03 only impacted the year ended December 31, 2000 and had no effect of the
Interim Financial Statements. The Interim Financial Statements are unaudited,
omit certain financial statement disclosures and should be read with the June
16, 2003 Form 8-K, including the exhibits thereto, and the Quarterly Reports on
Form 10-Q of CERC Corp. for the quarters ended March 31, 2003 and June 30, 2003.

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 its subsidiaries. The 1935 Act, among other
things, generally limits the ability of CenterPoint Energy and its 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. The United States Congress is currently
considering legislation which has a provision that would repeal the 1935 Act.
The Company 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
its business.

BASIS OF PRESENTATION

The preparation of financial statements in conformity with generally
accepted accounting principles in the United States of America (GAAP) requires
management to make estimates and assumptions that affect the reported amounts of
assets and liabilities and 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.

The Interim Financial Statements reflect all normal recurring adjustments
that are, in the opinion of management, necessary to present fairly the
financial position and results of operations for the respective periods. Amounts
reported in the Company's Statements of Consolidated Operations are not
necessarily indicative of amounts expected for a full year period due to the
effects of, among other things, (a) seasonal fluctuations in demand for energy
and energy services, (b) changes in energy commodity prices, (c) timing of
maintenance and other expenditures and (d) acquisitions and dispositions of
businesses, assets and other interests. In addition, certain amounts from the
prior year have been reclassified to conform to the Company's presentation of
financial statements in the current year. These reclassifications do not affect
net income.

The following notes to the consolidated annual financial statements
included in Exhibit 99.2 to the June 16, 2003 Form 8-K (CERC Corp. 8-K Notes)
relate to certain contingencies. These notes, as updated herein, are
incorporated herein by reference:

Notes to Consolidated Financial Statements: Note 3(e) (Regulatory Matters),
Note 5 (Derivative Instruments) and Note 10 (Commitments and
Contingencies).

For information regarding environmental matters and legal proceedings, see
Note 10.

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(2) NEW ACCOUNTING PRONOUNCEMENTS

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

The Company has identified no asset retirement obligations. The Company's
rate-regulated businesses recognize removal costs as a component of depreciation
expense in accordance with regulatory treatment. As of September 30, 2003, these
removal costs of $393 million do not represent SFAS No. 143 asset retirement
obligations, but rather embedded regulatory liabilities.

In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145
eliminates the current requirement that gains and losses on debt extinguishment
must be classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent. SFAS No. 145 also requires that capital
leases that are modified so that the resulting lease agreement is classified as
an operating lease be accounted for as a sale-leaseback transaction. The changes
related to debt extinguishment are effective for fiscal years beginning after
May 15, 2002, and the changes related to lease accounting are effective for
transactions occurring after May 15, 2002. The Company has applied this guidance
as it relates to lease accounting and the accounting provisions related to debt
extinguishment. Upon adoption of SFAS No. 145, any gain or loss on
extinguishment of debt that was classified as an extraordinary item in prior
periods is required to be reclassified. No such reclassification was required in
the three months or nine months ended September 30, 2002.

In June 2002, the FASB issued SFAS No. 146, "Accounting for Costs Associated
with Exit or Disposal Activities" (SFAS No. 146). SFAS No. 146 nullifies EITF
Issue No. 94-3, "Liability Recognition for Certain Employee Termination Benefits
and Other Costs to Exit an Activity (including Certain Costs Incurred in a
Restructuring)" (EITF No. 94-3). The principal difference between SFAS No. 146
and EITF No. 94-3 relates to the requirements for recognition of a liability for
costs associated with an exit or disposal activity. SFAS No. 146 requires that a
liability be recognized for a cost associated with an exit or disposal activity
when it is incurred. A liability is incurred when a transaction or event occurs
that leaves an entity little or no discretion to avoid the future transfer or
use of assets to settle the liability. Under EITF No. 94-3, a liability for an
exit cost was recognized at the date of an entity's commitment to an exit plan.
In addition, SFAS No. 146 also requires that a liability for a cost associated
with an exit or disposal activity be recognized at its fair value when it is
incurred. SFAS No. 146 is effective for exit or disposal activities that are
initiated after December 31, 2002. The Company adopted the provisions of SFAS
No. 146 on January 1, 2003. The adoption of SFAS No. 146 had no effect on the
Company's consolidated financial statements.

In June 2002, the EITF reached a consensus on EITF No. 02-03 that all
mark-to-market gains and losses on energy trading contracts should be shown net
in the income statement whether or not settled physically. An entity should
disclose the gross transaction volumes for those energy-trading contracts that
are physically settled. The EITF did not reach a consensus on whether
recognition of dealer profit, or unrealized gains and losses at inception of an
energy-trading contract, is appropriate in the absence of quoted market prices
or current market transactions for contracts with similar terms. The FASB staff
indicated that until such time as a consensus is reached, the FASB staff will
continue to hold the view that previous EITF consensus do not allow for
recognition of dealer profit, unless evidenced by quoted market prices or other
current market transactions for energy trading contracts with similar terms and
counterparties. The consensus on presenting gains and losses on energy trading
contracts net is effective for financial statements issued for periods ending
after July 15, 2002. Upon application of the consensus, comparative financial
statements for prior periods should be reclassified to conform to the consensus.
The Company's adoption of EITF No. 02-03 on January 1, 2003 only impacted the
year ended December 31, 2000 and had no effect on the Interim Financial
Statements.

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

In January 2003, the FASB issued FIN 46, "Consolidation of Variable Interest
Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46).
FIN 46 requires certain variable interest entities to be consolidated by the
primary beneficiary of the entity if the equity investors in the entity do not
have the characteristics of a controlling financial interest or do not have
sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. On October 9, 2003, the FASB deferred the application of FIN
46 until the end of the first interim or annual period ending after December 15,
2003 for variable interest entities created before February 1, 2003. The FASB is
currently considering several amendments to FIN 46, and the Company will analyze
the impact, if any, these changes have on its consolidated financial statements
upon ultimate implementation of FIN 46. The Company does not expect the adoption
of FIN 46 to have a material effect on its consolidated financial statements.

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 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 $0.5 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 Operations. SFAS No. 150 does not
permit restatement of prior periods. The adoption of SFAS No. 150 did not impact
the Company's net income.

(3) REGULATORY MATTERS

CenterPoint Energy Entex Rate Increase Filing.

On June 13, 2003, the CenterPoint Energy Entex (Entex) division of CERC
Corp. filed a rate increase request with the City of Houston which, if approved,
would yield approximately $17 million in additional annual revenue. The Company
is seeking a return on common equity of 11.25% and an overall return of 8.87% on
its rate base. The filing does not affect the rates under special contracts with
certain industrial customers. The city has suspended the rate request while it
negotiates a settlement with the Company. Upon resolution of its rate filing
with the City of Houston, Entex will seek to implement new rates in adjacent
cities and their surrounding areas that are similar to

7

those ultimately approved by the City of Houston. The Company expects that new
rates will become effective in these jurisdictions by the first quarter of 2004.

(4) 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.

Cash Flow Hedges. During the nine months ended September 30, 2003, there
was no hedge ineffectiveness 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.
During the nine months ended September 30, 2003, there was no effect on earnings
as a result of the discontinuance of cash flow hedges. As of September 30, 2003,
the Company expects $6.6 million in accumulated other comprehensive income to be
reclassified into net income during the next twelve months.

For additional information regarding the Company's use of derivatives, see
Note 5 to the CERC Corp. 8-K Notes, which is incorporated herein by reference.

(5) GOODWILL AND INTANGIBLES

Goodwill as of December 31, 2002 and September 30, 2003 by reportable
business segment is as follows (in millions):

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

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

The Company recognizes specifically identifiable intangibles when specific
rights and contracts are acquired. The Company amortizes other acquired
intangibles on a straight-line basis over the lesser of their contractual or
estimated useful lives. The Company has no intangible assets with indefinite
lives recorded as of September 30, 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 use rights and 4
to 25 years for other intangibles.

Amortization expense for other intangibles for the three months ended
September 30, 2002 and 2003 was $0.3 million and $0.4 million, respectively.
Amortization expense for other intangibles for the nine months ended September
30, 2002 and 2003 was $0.8 million and $1.1 million, respectively. Estimated
amortization expense for the remainder of 2003 is approximately $0.4 million and
is approximately $1.9 million per year for the five succeeding fiscal years.

(6) SHORT-TERM BORROWINGS, LONG-TERM DEBT AND RECEIVABLES FACILITY

(a) Short-Term Borrowings

Credit Facilities. As of September 30, 2003, CERC Corp. had a revolving
credit facility that provided for an aggregate of $200 million in committed
credit. As of September 30, 2003, $55 million was borrowed under this

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revolving credit facility. This revolving credit facility 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.

(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 unsecured 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 unsecured notes due 2014, the proceeds of which were
used to retire $140 million aggregate principal amount of the Company's TERM
Notes maturing in November 2003, to pay the cost of terminating a remarketing
option relating to those securities ($17 million), to pay issuance costs and for
general corporate purposes. As a result of this transaction, the $140 million
aggregate principal amount of the Company's TERM Notes has been classified as
long-term debt in the Consolidated Balance Sheet as of September 30, 2003.

(c) Receivables Facility

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 and selling receivables created by the
Company. This transaction is accounted for as a sale of receivables under the
provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial
Assets and Extinguishments of Liabilities," and, as a result, the related
receivables are excluded from the Consolidated Balance Sheets. 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
September 30, 2003, the Company had utilized $107 million and $68 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.

The commitment to purchase receivables expires November 14, 2003. Purchases
of receivables under the related uncommitted facility may occur until November
12, 2005. In the fourth quarter of 2003, the Company expects to replace the
receivables facility with a committed one-year receivables facility.

(7) TRUST PREFERRED SECURITIES

A statutory business trust created by CERC Corp. has issued 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 September 30, 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.

The sole asset of the trust consists of convertible junior subordinated
debentures of CERC Corp. having an interest rate and maturity date that
correspond to the distribution rate and mandatory redemption date of the
convertible preferred securities, and a principal amount corresponding to the
common and convertible preferred securities issued by the trust. For additional
information regarding the convertible preferred securities, see Note 7 to the
CERC Corp. 8-K Notes, which is incorporated herein by reference.

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For a discussion of the effect of adoption of SFAS No. 150 on the trust
preferred securities discussed above, see Note 2.

(8) COMPREHENSIVE INCOME (LOSS)

The following table summarizes the components of total comprehensive
income (loss):

(9) RELATED PARTY TRANSACTIONS

From time to time, the Company has receivables from, or payables to,
CenterPoint Energy or its subsidiaries. As of December 31, 2002, the Company had
net short-term borrowings, included in accounts and notes payable-affiliated
companies, of $74 million and net accounts payable of $27 million. As of
September 30, 2003, the Company had net accounts payable of $16 million included
in accounts and notes payable-affiliated companies. As of December 31, 2002 and
September 30, 2003, the Company had net long-term receivables, included in notes
receivable-affiliated companies, totaling $39 million and $35 million,
respectively. For the three and nine months ended September 30, 2002, the
Company had net interest expense related to affiliate borrowings of $1.5 million
and $1.2 million, respectively. For the three and nine months ended September
30, 2003, the Company had net interest income related to affiliate borrowings of
$0.6 million and $3.0 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. For the three and
nine months ended September 30, 2002, the sales and services by the Company to
Reliant Resources and its subsidiaries totaled $17 million and $42 million,
respectively. For the three and nine months ended September 30, 2002, the sales
and services by the Company to CenterPoint Energy and its affiliates totaled $7
million and $25 million, respectively. For the three and nine months ended
September 30, 2003, the sales and services by the Company to CenterPoint Energy
and its affiliates totaled $15 million and $25 million, respectively. Purchases
of natural gas by the Company from Reliant Resources and its subsidiaries were
$28 million and $186 million for the three and nine months ended September 30,
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 $24 million
and $76 million for the three and nine months ended September 30, 2002,
respectively, and $26 million and $83 million for the three and nine months
ended September 30, 2003, respectively, and are included primarily in operation
and maintenance expenses.

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(10) ENVIRONMENTAL MATTERS AND LEGAL PROCEEDINGS

(a) Environmental Matters.

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are
among numerous defendants in lawsuits 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." 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 the Company believes were neither owned nor operated by the Company, and
for which it believes it has no liability.

At September 30, 2003, the Company had accrued $19 million for remediation
of the Minnesota sites. At September 30, 2003, the estimated range of possible
remediation costs was $8 million to $44 million based on remediation continuing
for 30 to 50 years. The cost estimates are based on studies of a site or
industry average costs for remediation of sites of similar size. The actual
remediation costs will be dependent upon the number of sites to be remediated,
the participation of other potentially responsible parties (PRP), if any, and
the remediation methods used. 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 at
September 30, 2003 to be used for future environmental remediation.

The Company has received notices from the United States Environmental
Protection Agency and others regarding its status as a PRP for sites in other
states. 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

11

environmental contaminants. Considering the information currently known about
such sites and the involvement of the Company in activities at these sites, the
Company does not believe that these matters will have a material adverse effect
on its financial position, results of operations or cash flows.

(b) Department of Transportation.

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

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

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

(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.

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

12

Gas Cost Recovery Suits. 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 Utility Code, civil
conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The
plaintiffs seek class certification, but no class has been certified. The
plaintiffs allege that defendants inflated the prices charged to 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. The plaintiffs in
both cases seek restitution for the alleged overcharges, exemplary damages and
penalties. In both cases, the Company denies that it has overcharged any of its
customers for natural gas and believes that the amounts recovered for purchased
gas have been in accordance with what is permitted by state regulatory
authorities.

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

FERC initially required CEGT to file a response within 30 days explaining
why its failure to post all of the non-conforming terms and conditions in its
negotiated rate contracts did not violate Section 4 of the Natural Gas Act and
would not warrant FERC: (i) suspending or revoking CEGT's authority to enter
into negotiated rate contracts; (ii) requiring CEGT to file all negotiated rate
contracts for preapproval before they become effective; and (iii) requiring CEGT
to provide to all customers on its system the preferential non-conforming terms
and conditions that were not reported. FERC may also require CEGT to implement a
strict compliance plan to ensure that future non-conforming contracts are
reported to FERC. In its Show Cause Order, FERC did not propose any fine or
other monetary sanction for the alleged violations. At the time it issued its
Show Cause Order, FERC also initiated proceedings to review certain pending
contracts between CEGT and members of Arkansas Gas Consumers, Inc. which FERC
alleged contain similar non-conforming provisions. In that order, FERC directed
CEGT to modify those contracts and make additional filings regarding them to
conform to its conclusions in the Show Cause Order, including making certain
provisions available on a generally applicable basis, unless CEGT can provide an
acceptable explanation of why such modifications and filings are not required.

Subsequently, CEGT met with members of FERC's staff and provided additional
information relating to FERC's Show Cause Order. CEGT was granted an extension
of the response period to November 14, 2003, and has requested an additional
extension to December 15, 2003, in order to allow additional time for further
discussion with staff members.

CEGT believes that its past filings with the FERC conformed to FERC's filing
requirements at the time the various contracts were negotiated and that it will
be able to demonstrate to FERC that it has complied with the applicable policy
in all material respects. Nevertheless, CEGT intends to cooperate fully with
FERC and will comply with applicable FERC requirements for filing and posting
information relating to those contracts. CEGT believes at this time that the
ultimate resolution of this matter would not have a material adverse effect on
the financial condition or results of operations of either CERC or CEGT. The
negotiated rate contracts in question are a subset of all of the CEGT
transportation agreements. Even if it were ultimately precluded from using
negotiated rate contracts, CEGT would still be able to provide firm and
interruptible transportation services to its customers under its existing
tariff.

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

13

(11) REPORTABLE BUSINESS 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. For
descriptions of the reportable business segments, see Note 13 to the CERC Corp.
8-K Notes, which is incorporated herein by reference.

In the second quarter of 2003, the Company began to evaluate business
segment performance on an operating income basis. Operating income is shown
because it is the measure currently used by the chief operating decision maker
to evaluate performance and allocate resources. Additionally, it is a widely
accepted measure of financial performance prepared in accordance with GAAP.
Prior to the second quarter of 2003, the Company evaluated performance on an
earnings before interest expense, distribution on trust preferred securities and
income taxes (EBIT) basis. Historically, the difference between EBIT and
operating income has not been material.

The following table summarizes financial data for the reportable business
segments:

(1) Included in revenues from third parties are revenues from sales to Reliant
Resources, a former affiliate, of $17 million and $42 million for the three
and nine months ended September 30, 2002.

15

ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS OF
CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES

The following narrative analysis should be read in combination with our
interim financial statements and notes contained in Item 1 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). The 1935 Act
and related rules and regulations impose a number of restrictions on the
activities of CenterPoint Energy and its subsidiaries. The 1935 Act, among other
things, generally limits the ability of CenterPoint Energy and its 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 and its subsidiaries,
including us, received an order from the Securities and Exchange Commission
(SEC) under the 1935 Act on June 30, 2003 (June 2003 Financing Order) relating
to financing and other activities, which is effective until June 30, 2005.

On October 28, 2003, the SEC issued a supplemental order that permitted us
to issue additional debt securities in connection with the retirement of our 6
3/8% Term Enhanced ReMarketable Securities (TERM Notes). For more information
regarding the Orders, please read " -- Liquidity -- Certain Contractual and
Regulatory Limits on Ability to Issue Securities."

We meet the conditions specified in General Instruction H(1)(a) and (b) to
Form 10-Q and are therefore permitted to use the reduced disclosure format for
wholly owned subsidiaries of reporting companies. Accordingly, we have omitted
from this report the information called for by Item 3 (Quantitative and
Qualitative Disclosures About Market Risk) of Part I and the following Part II
items of Form 10-Q: Item 2 (Changes in Securities and Use of Proceeds), Item 3
(Defaults Upon Senior Securities) and Item 4 (Submission of Matters to a Vote of
Security Holders). The following discussion explains material changes in the
amount of our revenue and expense items between the three months and nine months
ended September 30, 2003 and the three months and nine months ended September
30, 2002. Reference is made to "Management's Narrative Analysis of the Results
of Operations" in Exhibit 99.1 to the Current Report on Form 8-K dated June 16,
2003 (June 16, 2003 Form 8-K).

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, state and municipal governmental authorities having jurisdiction over
rates we charge, competition in our various business operations, debt service
costs and income tax expense. For more information regarding factors that may
affect the future results of operations of our business, please read "Risk
Factors" in Item 5 of Part II of this report and "Management's Narrative
Analysis of the Results of Operations -- Certain Factors Affecting Future
Earnings" in Exhibit 99.1 to the June 16, 2003 Form 8-K, each of which is
incorporated herein by reference.

In the second quarter of 2003, we began to evaluate performance on an
operating income basis. Operating income is shown because it is the measure
currently used by the chief operating decision maker to evaluate performance and
allocate resources. Additionally, it is a widely accepted measure of financial
performance prepared in accordance with generally accepted accounting principles
in the United States of America (GAAP). Prior to the second quarter of 2003, we
evaluated performance on an earnings before interest expense, distribution on
trust preferred securities and income taxes (EBIT) basis. Historically, the
difference between EBIT and operating income has not been material.

16

The following table sets forth our consolidated results of operations for
the three and nine months ended September 30, 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.

THREE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED TO THREE MONTHS ENDED SEPTEMBER
30, 2002

For the three months ended September 30, 2003, operating income decreased
$4 million as compared to the same period in 2002. Operating margins (revenues
less natural gas costs) for the three months ended September 30, 2003 were $11
million higher than in the same period in 2002 primarily because of:

o higher revenues from rate increases implemented late in 2002 ($6
million);

o increased usage ($5 million);

o continued customer growth ($3 million); and

o franchise fees billed to customers ($2 million), partially offset by;

o reduced margins from our unregulated commercial and industrial sales
($4 million).

Operation and maintenance expense increased $10 million for the three
months ended September 30, 2003 as compared to the same period in 2002. The
increase in operation and maintenance expense was primarily due to:

o higher employee benefit expenses, primarily due to increased pension
costs ($8 million); and

o certain costs being included in operating expense subsequent to the
amendment of a receivables facility in November 2002 as compared with
being included in interest expense in the prior year ($2 million).

Depreciation and amortization expense increased $2 million for the three
months ended September 30, 2003 as compared to the same period in 2002 primarily
as a result of increases in plant in service.

Taxes other than income taxes increased $3 million for the three months
ended September 30, 2003 as compared to the same period in 2002 primarily due to
franchise fees resulting from higher revenues ($2 million).

Interest expense increased $5 million for the three months ended September
30, 2003 as compared to the same period in 2002 due to higher borrowing costs
and increased debt levels and financing costs.

Income tax expense decreased $3 million for the three months ended
September 30, 2003 as compared to the same period in 2002 primarily as a result
of a decrease in state tax expense.

17

NINE MONTHS ENDED SEPTEMBER 30, 2003 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30,
2002

For the nine months ended September 30, 2003, operating income increased
$43 million as compared to the same period in 2002. Operating margins (revenues
less natural gas costs) for the nine months ended September 30, 2003 were $80
million higher than in the same period in 2002 primarily because of:

o higher revenues from rate increases implemented late in 2002 ($30
million);

o increased usage ($10 million);

o franchise fees billed to customers ($9 million);

o improved margins from our unregulated commercial and industrial sales
($8 million);

o higher commodity prices ($8 million);

o continued customer growth ($8 million);

o improved margins from new transportation contracts to power plants ($5
million);

o increased miscellaneous service revenues and forfeited discounts ($5
million);

o colder weather ($4 million); and

o improved margins from enhanced services in our gas gathering
operations ($4 million).

These increases were partially offset by reduced project-related revenues
($16 million) and a one-time refund of a tax on fuel in 2002 ($3 million).

Operation and maintenance expense increased $20 million for the nine months
ended September 30, 2003 as compared to the same period in 2002. The increase in
operation and maintenance expense was primarily due to:

o higher employee benefit expenses primarily due to increased pension
costs ($23 million);

o certain costs being included in operating expense subsequent to the
amendment of a receivables facility in November 2002 as compared with
being included in interest expense in the prior year ($9 million); and

o increased bad debt expense primarily due to colder weather and higher
gas prices ($3 million).

The increases in operation and maintenance expense were partially offset by
a decrease in project-related costs ($16 million).

Depreciation and amortization expense increased $8 million for the nine
months ended September 30, 2003 as compared to the same period in 2002 primarily
as a result of increases in plant in service.

Taxes other than income taxes increased $9 million for the nine months
ended September 30, 2003 as compared to the same period in 2002 due to increased
franchise fees resulting from higher revenue.

Interest expense increased $15 million for the nine months ended September
30, 2003 as compared to the same period in 2002 due to higher borrowing costs
and increased debt levels and financing costs.

Income tax expense increased $5 million for the nine months ended September
30, 2003 as compared to the same period in 2002 due to higher pre-tax income.
However, our effective tax rates for the nine months ended September 30, 2003
and 2002 were 37.3% and 41.1%, respectively. The decrease in the effective tax
rate for 2003 compared to 2002 was primarily the result of a decrease in state
tax expense.

18

LIQUIDITY

Long-Term Debt. Of the $2.3 billion principal amount of long-term debt
outstanding at September 30, 2003, approximately $2.3 billion aggregate
principal amount is senior and unsecured, and approximately $77 million
aggregate principal amount with a final maturity of 2012 is subordinated and
unsecured. In addition, the debentures relating to $0.4 million of trust
preferred securities issued by our statutory business trust subsidiary are
subordinated.

The terms of various debt instruments having a final maturity of 2013, and
under which we have an aggregate $907 million outstanding, limit the issuance of
secured debt by us and provide for equal and ratable security for such debt in
the event debt secured by "principal property" (as defined in the debt
instruments) is issued. Additionally, our $200 million credit agreement expiring
in March 2004 prohibits the issuance of debt secured by "principal property."
The definition is similar to that contained in the debt instruments described
above. Any pledge of assets as security for our debt is subject to SEC approval
under the 1935 Act. We currently have SEC authorization to issue debt secured by
a pledge of the stock of our nonutility subsidiaries.

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 reduced current maturities of long-term debt from $518 million at December
31, 2002 to $-0- at September 30, 2003. In March and April 2003, we issued $762
million aggregate principal amount of our 7.875% senior notes due 2013, the
proceeds from which were used to refinance $360 million aggregate principal
amount of our TERM Notes maturing in November 2003, pay the cost of terminating
a remarketing option relating to those securities and repay approximately $340
million of bank borrowings bearing interest at 1.575% under our $350 million
credit facility having a termination date of March 31, 2003. We replaced the
credit facility which matured in March 2003 with a new $200 million revolving
credit facility that terminates in March 2004. On November 3, 2003, we issued
$160 million aggregate principal amount of our 5.95% senior unsecured notes due
2014, the proceeds of which were used to retire $140 million aggregate principal
amount of our TERM Notes, to pay the cost of terminating a remarketing option
relating to those securities ($17 million), to pay issuance costs and for
general corporate purposes.

In October 2003, our parent refinanced its bank facility with a $2.35
billion credit facility. CenterPoint Energy's new credit facility contains no
restrictions on our use of proceeds from financing activities.

Short-Term Debt and Receivables Facility. Our revolver and receivables
facility are scheduled to terminate on the dates indicated below.

- ----------
(1) The commitment to purchase receivables expires November 14, 2003. Purchases
of receivables under the related uncommitted facility may occur until
November 12, 2005.

Rates for borrowings under the revolving credit facility, including the
facility fee, are LIBOR plus 250 basis points based on current credit ratings
and the applicable pricing grid.

Effective June 25, 2003, we elected to reduce the purchase limit under our
receivables facility from $150 million to $100 million. The bankruptcy remote
subsidiary established to purchase and subsequently sell receivables makes such
purchases with a combination of cash and subordinated notes. In July 2003, the
subordinated notes owned by us were pledged to a gas supplier to secure
obligations incurred in connection with the purchase of gas by us. In the fourth
quarter of 2003, we plan to extend the existing committed facility for one year
or replace the receivables facility with a committed one-year receivables
facility.

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.

19

The terms of the money pool are in accordance with requirements applicable to
registered public utility holding companies under the 1935 Act and with the
related financing orders we have received. Our money pool borrowing limit under
such financing orders is $600 million. At September 30, 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.

Cash Requirements in 2003 and 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 requirements
during the last three months of 2003 and during 2004 include the following:

o approximately $355 million of capital expenditures, of which $76
million relates to the fourth quarter of 2003;

o up to $100 million in the event our committed receivables facility is
not replaced or extended; and

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

We expect that revolving credit borrowings, anticipated cash flows from
operations, borrowings from affiliates and proceeds from capital market
transactions, will be sufficient to meet our cash needs for the remainder of
2003 and 2004. If we are unable to obtain external financings to meet our future
capital requirements on terms that are acceptable to us, our financial condition
and future results of operations could be materially and adversely affected. Our
future indebtedness may include terms that are more restrictive or burdensome
than those of our current indebtedness. Such terms may negatively impact our
ability to operate our business or may restrict the payment of dividends to our
parent company.

At September 30, 2003, we had a shelf registration statement covering $50
million of debt securities. The amount of any debt security or any security
having equity characteristics that we can issue, whether registered or
unregistered, or whether debt is secured or unsecured, is expected to be
affected by:

o general economic and capital market conditions;

o credit availability from financial institutions and other lenders;

o investor confidence in us and the markets in which we operate;

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

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

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

o provisions of relevant tax and securities laws; and

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

Proceeds from the sales of securities are expected to be used primarily to
refinance debt. We may access the bank and capital markets to refinance debt
that is not scheduled to mature in the next twelve months.

20

Impact on Liquidity of a Downgrade in Credit Ratings. As of October 7, 2003,
Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a
division of The McGraw Hill Companies (S&P) and Fitch, Inc. (Fitch) had assigned
the following credit ratings to our senior unsecured debt:

- ----------

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

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

(3) A "stable" outlook from Fitch indicates that the rating is not likely
to move over a one- to two-year period.

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

A decline in credit ratings would increase facility fees and borrowing
costs under our 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.

Our bank facility contains a "material adverse change" clause that could
impact our ability to borrow under this facility. The "material adverse change"
clause in our revolving credit facility applies to new borrowings under the
facility, other than borrowings being used to repay commercial paper, and
relates to changes since December 31, 2002 in our business, condition (financial
or otherwise), operations, performance or properties.

Our $100 million receivables facility requires the maintenance of credit
ratings of at least BB from S&P and Ba2 from Moody's. Receivables would cease to
be sold in the event a credit rating fell below the threshold.

CenterPoint Energy Gas Resources Corp., a wholly owned subsidiary, provides
comprehensive natural gas sales and services to industrial and commercial
customers that are primarily located within or near the territories served by
our pipelines and natural gas distribution subsidiaries. In order to hedge its
exposure to natural gas prices, CenterPoint Energy Gas Resources Corp. has
agreements with provisions standard for the industry that establish credit
thresholds and then require a party to provide additional collateral on two
business days' notice when that party's credit rating or the rating of a credit
support provider for that party (CenterPoint Energy Resources Corp. in this
case) falls below those levels. As of October 31, 2003, our senior unsecured
debt was rated BBB by S&P and Ba1 by Moody's. Based on these ratings, we
estimate that unsecured credit limits extended to CenterPoint Energy Gas
Resources Corp. by counterparties could aggregate $29 million; however, utilized
credit capacity is significantly lower.

Cross Defaults. Our debentures and borrowings generally provide that a
default on obligations by CenterPoint Energy does not cause a default under our
debentures, revolving credit facility or receivables facility. A payment default
on, or a non-payment default that permits acceleration of, any indebtedness at
CenterPoint Energy Resources Corp. exceeding $50 million will cause a default
under CenterPoint Energy's $2.35 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 CenterPoint Energy's
3.75% senior convertible notes due 2023, its 5.875% senior notes due 2008, its
6.85% senior notes due 2015 and its 7.25% senior notes due 2010.

21

Pension Plan. As discussed in Note 8(a) of the notes to the consolidated
financial statements included in Exhibit 99.2 to the June 16, 2003 Form 8-K
(CERC Corp. 8-K Notes), which is incorporated herein by reference, we
participate in CenterPoint Energy's qualified non-contributory pension plan
covering substantially all employees. Pension expense for 2003 is estimated to
be $36 million based on an expected return on plan assets of 9.0% and a discount
rate of 6.75% as of December 31, 2002. Pension expense for the year ended
December 31, 2002 was $13 million. Future changes in plan asset returns, assumed
discount rates and various other factors related to the pension will impact our
future pension expense. 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:

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

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

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

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

o various regulatory actions.

Certain Contractual and Regulatory Limits on Ability to Issue Securities.
Factors affecting our ability to issue securities or take other actions to
adjust our capitalization include:

o covenants and other provisions in our credit facility, receivables
facility and other borrowing agreements; and

o 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 contains a provision that could, under certain circumstances,
limit the amount of dividends that could be paid by us.

Our parent 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 activities. The 1935 Act, among other things, limits our
ability to issue debt and equity securities without prior authorization,
restricts the source of dividend payments to current and retained earnings
without prior authorization, regulates sales and acquisitions of certain assets
and businesses and governs affiliate transactions.

We received an order from the SEC relating to our financing activities on
June 30, 2003 (June 2003 Financing Order), which is effective until June 30,
2005. The June 2003 Financing Order establishes limits on the amount of external
debt we can issue without additional authorization. We are in compliance with
the authorized limits. We obtained an additional order from the SEC in October
2003 authorizing us to issue up to an additional $50 million of debt securities
in connection with retiring the TERM Notes. The June 2003 Financing Order
permits the following additional financing activities:

o refinancings of our existing external debt;

o utilization of the undrawn portion of our bank facility; and

o the issuance of an aggregate $250 million of preferred stock and
preferred securities.

22

The June 2003 Financing Order requires that if we 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 ours and of CenterPoint Energy must be rated investment grade by at least one
NRSRO. The June 2003 Financing Order also contains certain requirements for
interest rates, maturities, issuance expenses and use of proceeds. The SEC has
reserved jurisdiction over the issuance of $450 million additional debt by us.
We would need an additional order from the SEC for authority to issue this debt.
Under the June 2003 Financing Order, our common equity as a percentage of total
capitalization must be at least 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. We believe the following accounting policies involve the application of
critical accounting estimates.

IMPAIRMENT OF LONG-LIVED ASSETS

Long-lived assets recorded in our Consolidated Balance Sheets primarily
consist of property, plant and equipment (PP&E). Net PP&E comprises $3.3 billion
or 55% of our total assets as of September 30, 2003. We make judgments and
estimates in conjunction with the carrying value of these assets, including
amounts to be capitalized, depreciation and amortization methods and useful
lives. We evaluate our PP&E for impairment whenever indicators of impairment
exist. During 2002, no such indicators of impairment existed. Accounting
standards require that if the sum of the undiscounted expected future cash flows
from a company's asset is less than the carrying value of the asset, an asset
impairment must be recognized in the financial statements. The amount of
impairment recognized is calculated by subtracting the fair value of the asset
from the carrying value of the asset.

IMPAIRMENT OF GOODWILL AND INDEFINITE-LIVED INTANGIBLE ASSETS

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

We recorded goodwill associated with the acquisition of our Natural Gas
Distribution and Pipelines and Gathering operations in 1997. We reviewed our
goodwill for impairment as of January 1, 2003. We computed the fair value of the
Natural Gas Distribution and the Pipelines and Gathering operations as the sum
of the discounted estimated net future cash flows applicable to each of these
operations. We determined that the fair value for each of the Natural Gas
Distribution operations and the Pipelines and Gathering operations exceeded
their corresponding carrying value, including unallocated goodwill. We also
concluded that no interim impairment indicators existed

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subsequent to this initial evaluation. As of September 30, 2003, we had recorded
$1.7 billion of goodwill. Future evaluations of the carrying value of goodwill
could be significantly impacted by our estimates of cash flows associated with
our Natural Gas Distribution and Pipelines and Gathering operations, regulatory
matters, and estimated operating costs.

UNBILLED REVENUES

Revenues related to the sale and/or delivery of natural gas are generally
recorded when natural gas is delivered to customers. However, the determination
of sales to individual customers is based on the reading of their meters, which
is performed on a systematic basis throughout the month. At the end of each
month, amounts of natural gas delivered to customers since the date of the last
meter reading are estimated and the corresponding unbilled revenue is estimated.
Unbilled natural gas sales are estimated based on estimated purchased gas
volumes, estimated lost and unaccounted for gas and tariffed rates in effect.
Accrued unbilled revenues recorded in the Consolidated Balance Sheets as of
December 31, 2002 and September 30, 2003 were $284 million and $142 million,
respectively, related to our Natural Gas Distribution business segment.

NEW ACCOUNTING PRONOUNCEMENTS

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

We have identified no asset retirement obligations. Our rate-regulated
businesses recognize removal costs as a component of depreciation expense in
accordance with regulatory treatment. As of September 30, 2003, these removal
costs of $393 million do not represent SFAS No. 143 asset retirement
obligations, but rather embedded regulatory liabilities.

In April 2002, the Financial Accounting Standards Board (FASB) issued SFAS
No. 145, "Rescission of FASB Statements No. 4, 44, and 64, Amendment of FASB
Statement No. 13, and Technical Corrections" (SFAS No. 145). SFAS No. 145
eliminates the current requirement that gains and losses on debt extinguishment
must be classified as extraordinary items in the income statement. Instead, such
gains and losses will be classified as extraordinary items only if they are
deemed to be unusual and infrequent. SFAS No. 145 also requires that capital
leases that are modified so that the resulting lease agreement is classified as
an operating lease be accounted for as a sale-leaseback transaction. The changes
related to debt extinguishment are effective for fiscal years beginning after
May 15, 2002, and the changes related to lease accounting are effective for
transactions occurring after May 15, 2002. We have applied this guidance as it
relates to lease accounting and the accounting provisions related to debt
extinguishment. Upon adoption of SFAS No. 145, any gain or loss on
extinguishment of debt that was classified as an extraordinary item in prior
periods is required to be reclassified. No such reclassification was required in
the three months or nine months ended September 30, 2002.

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

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provisions of SFAS No. 146 on January 1, 2003. The adoption of SFAS No. 146 had
no effect on our consolidated financial statements.

In June 2002, the EITF reached a consensus on EITF No. 02-03, "Issues
Involved in Accounting for Derivative Contracts Held for Trading Purposes and
Contracts Involved in Energy Trading and Risk Management Activities" (EITF No.
02-3) that all mark-to-market gains and losses on energy trading contracts
should be shown net in the income statement whether or not settled physically.
An entity should disclose the gross transaction volumes for those energy-trading
contracts that are physically settled. The EITF did not reach a consensus on
whether recognition of dealer profit, or unrealized gains and losses at
inception of an energy-trading contract, is appropriate in the absence of quoted
market prices or current market transactions for contracts with similar terms.
The FASB staff indicated that until such time as a consensus is reached, the
FASB staff will continue to hold the view that previous EITF consensus do not
allow for recognition of dealer profit, unless evidenced by quoted market prices
or other current market transactions for energy trading contracts with similar
terms and counterparties. The consensus on presenting gains and losses on energy
trading contracts net is effective for financial statements issued for periods
ending after July 15, 2002. Upon application of the consensus, comparative
financial statements for prior periods should be reclassified to conform to the
consensus. Our adoption of EITF No. 02-03 on January 1, 2003 only impacted the
year ended December 31, 2000 and had no effect on our interim financial
statements.

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

In January 2003, the FASB issued FIN 46, "Consolidation of Variable
Interest Entities, an Interpretation of Accounting Research Bulletin No. 51"
(FIN 46). FIN 46 requires certain variable interest entities to be consolidated
by the primary beneficiary of the entity if the equity investors in the entity
do not have the characteristics of a controlling financial interest or do not
have sufficient equity at risk for the entity to finance its activities without
additional subordinated financial support from other parties. FIN 46 is
effective for all new variable interest entities created or acquired after
January 31, 2003. On October 9, 2003, the FASB deferred the application of FIN
46 until the end of the first interim or annual period ending after December 15,
2003 for variable interest entities created before February 1, 2003. The FASB is
currently considering several amendments to FIN 46, and we will analyze the
impact, if any, these changes may have on our consolidated financial statements
upon ultimate implementation of FIN 46. We do not expect the adoption of FIN 46
to have a material effect on our consolidated financial statements.

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 our 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 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, we reclassified $0.5 million of trust
preferred securities as long-term debt and began to

25

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 Operations.
SFAS No. 150 does not permit restatement of prior periods. The adoption of SFAS
No. 150 did not impact our net income.

ITEM 4. 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 September 30, 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 September 30, 2003 that has
materially affected, or is reasonably likely to materially affect, our internal
controls over financial reporting.

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PART II. OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS.

For a description of certain legal and regulatory proceedings affecting us,
please review Note 10 to our Interim Financial Statements, "Business --
Regulation" and "Business -- Environmental Matters" in Item 1 of the Annual
Report on Form 10-K of CERC Corp. (CERC Corp. 10-K) for the year ended December
3, 2002, "Legal Proceedings" in Item 3 of the CERC Corp. 10-K and Notes 10(c)
and (d) to the CERC Corp. 8-K Notes, each of which is incorporated herein by
reference.

ITEM 5. OTHER INFORMATION.

RISK FACTORS

PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES

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 consumers 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 INTERSTATE
PIPELINES' CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS.

Contracts with two of our interstate pipelines' significant customers,
CenterPoint Energy Arkla and Laclede Gas Company, are currently scheduled to
expire in 2005 and 2007, respectively. To the extent the pipelines are unable to
extend these contracts or the contracts are renegotiated at rates substantially
different than the rates

27

provided in the current contracts, there could be an adverse effect on our
results of operations, financial condition and cash flows.

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

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

OUR REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

A substantial portion of our revenues are derived from natural gas sales
and transportation. Thus, our revenues and results of operations are subject to
seasonality, weather conditions and other changes in natural gas usage, with
revenues being higher during the winter months.

RISK FACTORS ASSOCIATED WITH OUR FINANCIAL CONDITION

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

As of September 30, 2003, we had $2.4 billion of outstanding indebtedness.
Approximately $658 million principal amount of this debt must be paid through
2006. Included in the approximately $658 million is $140 million principal
amount of TERM notes that were retired in November 2003. 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:

o general economic and capital market conditions;

o credit availability from financial institutions and other lenders;

o investor confidence in us and the markets in which we operate;

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

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

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

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

o provisions of relevant tax and securities laws; and

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

Our current credit ratings are discussed in "Management's Narrative
Analysis of the Results of Operations of CenterPoint Energy Resources Corp. and
Subsidiaries -- Liquidity -- Impact on Liquidity of a Downgrade in Credit
Ratings" in Item 2 of Part I 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.

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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 $3.2 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. On October 7, 2003, Moody's
Investors Services, Inc. placed CenterPoint Energy's senior unsecured credit
rating on review for downgrade, reflecting concerns that may lead to a
downgrade. 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:

o our payment of dividends;

o decisions on our financings and our capital raising activities;

o mergers or other business combinations; and

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

The United States Congress is currently considering legislation which 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.

29

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 on commercially reasonable terms or that the
insurance proceeds received for any loss of or any damage to any of our
facilities will be sufficient to restore the loss or damage without negative
impact on our results of operations, financial condition and cash flows. The
costs of our insurance coverage have increased significantly in recent months
and may continue to increase in the future.

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

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

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K.

(a) Exhibits.

The following exhibits are filed herewith:

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

(b) Reports on Form 8-K.

On September 18, 2003, we filed a Current Report on Form 8-K dated
September 15, 2003, announcing that the Federal Energy Regulatory Commission
issued a Show Cause Order to CenterPoint Energy Gas Transmission Company, one of
our natural gas pipeline subsidiaries (Item 5). We also furnished information
under Item 9 of that form regarding a slide presentation and information
regarding our external debt balances expected to be presented to various members
of the financial and investment community from time to time.

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.

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SIGNATURES

Pursuant to the requirements 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.

CENTERPOINT ENERGY RESOURCES CORP.

By: /s/ James S. Brian
------------------------------------------------------
James S. Brian
Senior Vice President and Chief Accounting Officer

Date: November 12, 2003

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INDEX TO EXHIBITS

The following exhibits are filed herewith:

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