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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

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. ii

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. 5

(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. 6

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 8

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. 9

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. 10

(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 23

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 24

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. 26

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. 28

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. 32

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 33

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.

EXHIBIT 12 CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES (THOUSANDS OF DOLLARS)

EXHIBIT 31(a) CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 12, 2003 /s/ David M. McClanahan ------------------------------------- David M. McClanahan President and Chief Executive Officer

EXHIBIT 31(b) CERTIFICATIONS I, Gary L. Whitlock, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy Resources Corp.; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report; 4. The registrant's other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have: (a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; (b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and (c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and 5. The registrant's other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions): (a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and (b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting. Date: November 12, 2003 /s/ Gary L. Whitlock ---------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer

EXHIBIT 32(a) CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) (the "Act"), I, David M. McClanahan, President and Chief Executive Officer of CenterPoint Energy Resources Corp. (the "Company"), hereby certify, to the best of my knowledge: (1) The Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 (the "Report"), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 12, 2003 /s/ David M. McClanahan ----------------------------- David M. McClanahan President and Chief Executive Officer

EXHIBIT 32(b) CERTIFICATION PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 (SUBSECTIONS (a) AND (b) OF SECTION 1350, CHAPTER 63 OF TITLE 18, UNITED STATES CODE) Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 (Subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) (the "Act"), I, Gary L. Whitlock, Executive Vice President and Chief Financial Officer of CenterPoint Energy Resources Corp. (the "Company"), hereby certify, to the best of my knowledge: (1) The Company's Quarterly Report on Form 10-Q for the quarter ended September 30, 2003 (the "Report"), fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and (2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Dated: November 12, 2003 /s/ Gary L. Whitlock ------------------------------ Gary L. Whitlock Executive Vice President and Chief Financial Officer

Exhibit 99(a) ITEM 1. BUSINESS REGULATION We are subject to regulation by various federal, state, local and foreign governmental agencies, including the regulations described below. PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 As a subsidiary of a registered public utility holding company, we are subject to a comprehensive regulatory scheme imposed by the SEC in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are generally required to obtain approval from the SEC under the 1935 Act. Prior to the Restructuring, CenterPoint Energy and Reliant Energy obtained an order from the SEC that authorized the Restructuring transactions, including the Distribution, and granted CenterPoint Energy certain authority with respect to system financing, dividends and other matters. The financing authority granted by that order will expire on June 30, 2003, and CenterPoint Energy must obtain a further order from the SEC under the 1935 Act, related, among other things, to the financing activities of CenterPoint Energy and its subsidiaries, including us, subsequent to June 30, 2003. In a July 2002 order, the SEC limited the aggregate amount of our external borrowings to $2.7 billion. Our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. In addition, the order restricts our ability to pay dividends out of capital accounts to the extent current or retained earnings are insufficient for those dividends. Under these restrictions, we are permitted to pay dividends in excess of our current or retained earnings in an amount up to $100 million. In 2002, we obtained authority from each state in which such authority was required to restructure in a manner that would allow CenterPoint Energy to claim an exemption from registration under the 1935 Act. CenterPoint Energy has concluded that a restructuring would not be beneficial and has elected to remain a registered holding company under the 1935 Act. FEDERAL ENERGY REGULATORY COMMISSION The transportation and sale or resale of natural gas in interstate commerce is subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended. The FERC has jurisdiction over, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates. In February 2000, the FERC issued Order No. 637, which introduced several measures to increase competition for interstate pipeline transportation services. Order No. 637 authorizes interstate pipelines to propose term-differentiated and peak/off-peak rates, and requires pipelines to make tariff filings to expand pipeline service options for customers. Both of our natural gas pipeline subsidiaries made two Order No. 637 1

compliance filings in 2000, and both obtained uncontested settlements filed with the FERC in 2001. In 2002, the FERC issued orders accepting both settlements, subject to certain modifications. The FERC has denied requests for rehearing and clarification of the orders and has accepted, with modification, the compliance tariff filed under one of the orders and ordered additional revised tariff sheets to be filed under the other order. STATE AND LOCAL REGULATION In almost all communities in which we provide natural gas distribution services, we operate under franchises, certificates or licenses obtained from state and local authorities. The terms of the franchises, with various expiration dates, typically range from 10 to 30 years. None of our material franchises expires before 2005. We expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of our retail natural gas sales are subject to traditional cost-of-service regulation at rates regulated by the relevant state public service commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and municipalities we serve. Arkansas Rate Case. In November 2001, Arkla filed a rate request in Arkansas seeking rates to yield approximately $47 million in additional annual gross revenue. In August 2002, a settlement was approved by the Arkansas Public Service Commission (APSC) which is expected to result in an increase in base rates of approximately $32 million annually. In addition, the APSC approved a gas main replacement surcharge which is expected to provide $2 million of additional gross revenue in 2003 and additional amounts in subsequent years. The new rates included in the final settlement were effective with all bills rendered on and after September 21, 2002. Oklahoma Rate Case. In May 2002, Arkla filed a request in Oklahoma to increase its base rates by $13.7 million annually. In December 2002, a settlement was approved by the Oklahoma Corporation Commission which is expected to result in an increase in base rates of approximately $7.3 million annually. The new rates included in the final settlement were effective with all bills rendered on and after December 29, 2002. City of Tyler, Texas, Gas Costs Review. By letter to Entex dated July 31, 2002, the City of Tyler, Texas, forwarded various computations of what it believes to be excessive costs ranging from $2.8 million to $39.2 million for gas purchases by Entex for resale to residential and small commercial customers in that city under supply agreements in effect since 1992. Entex's gas costs for its Tyler system are recovered from customers pursuant to tariffs approved by the city and filed with both the city and the Railroad Commission. Pursuant to an agreement, on January 29, 2003, Entex and the city filed a Joint Petition for Review of Charges for Gas Sales (Joint Petition) with the Railroad Commission. The Joint Petition requests that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. We believe that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs and that the city has no legal or factual support for the statements made in its letter. DEPARTMENT OF TRANSPORTATION In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002. This legislation applies to our interstate pipelines as well as our intra-state pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires companies to assess the integrity of their pipeline transmission and distribution facilities in areas of high population concentration and further requires companies to perform remediation activities in accordance with the requirements of the legislation over a 10-year period. In January 2003, the U.S. Department of Transportation published a notice of proposed rulemaking to implement provisions of the legislation. The Department of Transportation is expected to issue final rules by the end of 2003. 2

While we anticipate that increased capital and operating expenses will be required to comply with the legislation, we will not be able to quantify the level of spending required until the Department of Transportation's final rules are issued. ENVIRONMENTAL MATTERS GENERAL ENVIRONMENTAL ISSUES We are subject to numerous federal, state and local requirements relating to the protection of the environment and the safety and health of personnel and the public. These requirements relate to a broad range of our activities, including: the discharge of pollutants into water and soil; the proper handling of solid, hazardous, and toxic materials; and waste, noise, and safety and health standards applicable to the workplace. In order to comply with these requirements, we will spend substantial amounts from time to time to construct, modify and retrofit equipment, and to clean up or decommission disposal or fuel storage areas and other locations as necessary. Our facilities are subject to state and federal laws and regulations governing the discharge of pollutants into the air and waterways. In many cases we must obtain permits or other governmental authorizations that prescribe the parameters for discharges from our facilities. There are ongoing efforts to modify standards relating to both the discharge of pollutants into streams and waterways and to air quality. These efforts may result in more restrictive regulations and permit terms applicable to our facilities in the future. We anticipate no significant capital and other special project expenditures between 2002 and 2006 for environmental compliance. If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980, or CERCLA, owners and operators of facilities from which there has been a release or threatened release of hazardous substances, together with those who have transported or arranged for the disposal of those substances, are liable for: - the costs of responding to that release or threatened release; and - the restoration of natural resources damaged by any such release. We are not aware of any liabilities under CERCLA that would have a material adverse effect on us, our financial position, results of operations or cash flows. LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION Manufactured Gas Plant Sites. We and our predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory, two of which we believe were neither owned nor operated by us, and for which we believe we have no liability. At December 31, 2002, we had accrued $19 million for remediation of the Minnesota sites. At December 31, 2002, the estimated range of possible remediation costs was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. We have an environmental expense tracker mechanism in our rates in Minnesota. We have collected $12 million at December 31, 2002 to be used for future environmental remediation. 3

We have received notices from the United States Environmental Protection Agency and others regarding our status as a PRP for sites in other states. Based on current information, we have not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Hydrocarbon Contamination. In August 2001, a number of Louisiana residents who live near the Wilcox Aquifer filed suit in the 1st Judicial District Court, Caddo Parish, Louisiana against us and others. The suit alleges that we and the other defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by the defendants and is the sole or primary drinking water aquifer in the area. The monetary damages sought are unspecified. In April 2002, a separate suit with identical allegations against the same parties was filed in the same court. Additionally in January 2003, a third suit with similar allegations was filed against the same parties in the 26th Judicial Court, Bossier Parish, Louisiana. Mercury Contamination. Like similar companies, our pipeline and natural gas distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area around the meters with elemental mercury. We have found this type of contamination in the past, and we have conducted remediation at sites found to be contaminated. Although we are not aware of additional specific sites, it is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the cost of any remediation of these sites will not be material to our financial position, results of operations or cash flows. ITEM 3. LEGAL PROCEEDINGS For a brief descriptions of certain legal and regulatory proceedings affecting us, see "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 10(c) and 10(d) to our consolidated financial statements. 4

EXHIBIT 99(b) MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on numerous factors including: - state and federal legislative and regulatory actions or developments, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business and actions; - timely rate increases including recovery of costs; - the successful and timely completion of our capital projects; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - our pursuit of potential business strategies, including acquisitions or dispositions of assets; - changes in business strategy or development plans; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - unanticipated changes in operating expenses and capital expenditures; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - legal and administrative proceedings and settlements; - changes in tax laws; - inability of various counterparties to meet their obligations with respect to our financial instruments; - any lack of effectiveness of our disclosure controls and procedures; - changes in technology; - significant changes in our relationship with our employees, including the availability of qualified personnel and the potential adverse effects if labor disputes or grievances were to occur; - significant changes in critical accounting policies; - acts of terrorism or war, including any direct or indirect effect on our business resulting from terrorist attacks such as occurred on September 11, 2001 or any similar incidents or responses to those incidents; - the availability and price of insurance; - political, legal, regulatory and economic conditions and developments in the United States; and - other factors discussed in Item 1 of this report under "Risk Factors." 1

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (e) REGULATORY MATTERS CERC applies the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the accounts of the utility operations of Natural Gas Distribution and MRT. As of December 31, 2001 and 2002, CERC had recorded $6 million and $12 million, respectively, of net regulatory assets. If, as a result of changes in regulation or competition, CERC's ability to recover these assets and liabilities would not be probable, CERC would be required to write off or write down these regulatory assets and liabilities. In addition, CERC would be required to determine any impairment of the carrying costs of plant and inventory assets. Arkansas Rate Case In November 2001, Arkla filed a rate request in Arkansas seeking rates to yield approximately $47 million in additional annual gross revenue. In August 2002, a settlement was approved by the Arkansas Public Service Commission (APSC) that is expected to result in an increase in base rates of approximately $32 million annually. In addition, the APSC approved a gas main replacement surcharge that is expected to provide $2 million of additional gross revenue in 2003 and additional amounts in subsequent years. The new rates included in the final settlement were effective with all bills rendered on and after September 21, 2002. Oklahoma Rate Case In May 2002, Arkla filed a request in Oklahoma to increase its base rates by $13.7 million annually. In December 2002, a settlement was approved by the Oklahoma Corporation Commission that is expected to result in an increase in base rates of approximately $7.3 million annually. The new rates included in the final settlement were effective with all bills rendered on and after December 29, 2002. 2

5. DERIVATIVE INSTRUMENTS Effective January 1, 2001, CERC adopted SFAS No. 133, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires that derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative instrument as hedging (a) the exposure to changes in the fair value of an asset or liability (Fair Value Hedge), (b) the exposure to variability in expected future cash flows (Cash Flow Hedge), or (c) the foreign currency exposure of a net investment in a foreign operation. For a derivative not designated as a hedging instrument, the gain or loss is recognized in earnings in the period it occurs. Adoption of SFAS No. 133 on January 1, 2001 resulted in a cumulative after-tax increase in accumulated other comprehensive income of $38 million. The adoption also increased current assets, long-term assets, current liabilities and long-term liabilities by approximately $88 million, $5 million, $53 million and $2 million, respectively, in CERC's Consolidated Balance Sheet. CERC is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. CERC utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes and cash flows of its natural gas businesses on its operating results and cash flows. (a) Non-Trading Activities Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, CERC enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas. CERC applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. CERC analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because CERC's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, CERC facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions. During 2002, no hedge ineffectiveness was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, CERC realizes in net income the deferred gains and losses recognized in accumulated other comprehensive income. During the year ended December 31, 2002, there was a $0.9 million deferred loss recognized in earnings as a result of the discontinuance of cash flow hedges because it was no longer probable that the forecasted 3

transaction would occur. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive income is reclassified and included in CERC's Statements of Consolidated Income under the caption "Natural Gas and Purchased Power." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2002, CERC expects $17 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. The maximum length of time CERC is hedging its exposure to the variability in future cash flows for forecasted transactions on existing financial instruments is primarily two years with a limited amount of exposure up to three years. CERC's policy is not to exceed five years in hedging its exposure. (b) CREDIT RISKS In addition to the risk associated with price movements, credit risk is also inherent in CERC's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of CERC as of December 31, 2001 and 2002:

- --------------- (1) "Investment Grade" is primarily determined using publicly available credit ratings along with the consideration of credit support (such as parent company guarantees) and collateral, which encompasses cash and standby letters of credit. (2) For unrated counterparties, the Company performs financial statement analysis, considering contractual rights and restrictions and collateral, to create a synthetic credit rating. (3) The $22 million non-trading derivative asset includes a $15 million asset due to trades with Reliant Energy Services, an affiliate until the date of the Distribution. As of December 31, 2002, Reliant Energy Services did not have an Investment Grade rating. (c) GENERAL POLICY CenterPoint Energy has established a Risk Oversight Committee comprised of corporate and business segment officers that oversees all commodity price and credit risk activities, including CenterPoint Energy's trading, marketing, risk management services and hedging activities. The committee's duties are to establish CenterPoint Energy's commodity risk policies, allocate risk capital within limits established by CenterPoint Energy's board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with CenterPoint Energy's risk management policies and procedures and trading limits established by CenterPoint Energy's board of directors. CenterPoint Energy's policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument. 4

7. TRUST PREFERRED SECURITIES In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Corp. accounts for CERC Trust as a wholly owned consolidated subsidiary. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. The convertible junior subordinated debentures represent CERC Trust's sole asset and its entire operations. CERC Corp. considers its obligation under the Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the convertible preferred securities, taken together, to constitute a full and unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect to the convertible preferred securities. The convertible preferred securities are mandatorily redeemable upon the repayment of the convertible junior subordinated debentures at their stated maturity or earlier redemption. Effective January 7, 2003, the convertible preferred securities are convertible at the option of the holder into $33.62 of cash and 2.34 shares of CenterPoint Energy common stock for each $50 of liquidation value. As of December 31, 2001 and 2002, $0.4 million liquidation amount of convertible preferred securities were outstanding. The securities, and their 5

underlying convertible junior subordinated debentures, bear interest at 6.25% and mature in June 2026. Subject to some limitations, CERC Corp. has the option of deferring payments of interest on the convertible junior subordinated debentures. During any deferral or event of default, CERC Corp. may not pay dividends on its common stock to CenterPoint Energy. As of December 31, 2002, no interest payments on the convertible junior subordinated debentures had been deferred. 8. EMPLOYEE BENEFIT PLANS (a) PENSION PLANS Substantially all of CERC's employees participate in CenterPoint Energy's qualified non-contributory pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. As a result, certain employees participating in the plan as of December 31, 1998 are eligible to receive the greater of the accrued benefit calculated under the prior plan through 2008 or the cash balance formula. CenterPoint Energy's funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to CERC based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy's participating subsidiaries. Pension benefit was $21 million for the year ended December 31, 2000. CERC recognized pension expense of $1 million and $13 million for the years ended December 31, 2001 and 2002, respectively. In addition to the Plan, CERC participates in CenterPoint Energy's non-qualified pension plan, which allows participants to retain the benefits to which they would have been entitled under the qualified pension plan except for federally mandated limits on these benefits or on the level of salary on which these benefits may be calculated. The expense associated with the non-qualified pension plan was $13 million, $5 million and $2 million for the years ended December 31, 2000, 2001 and 2002, respectively. As of December 31, 2001, CenterPoint Energy allocated $94 million of pension assets, $40 million of non-qualified pension liabilities and $2 million minimum pension liabilities to CERC. As of December 31, 2002, CenterPoint Energy has not allocated such pension assets or liabilities to CERC. This change in method of allocation had no impact on pension expense recorded for the year ended December 31, 2002. 6

10. COMMITMENTS AND CONTINGENCIES (a) ENVIRONMENTAL CAPITAL COMMITMENTS CERC has various commitments for capital and environmental expenditures. CERC anticipates no significant capital and other special project expenditures between 2003 and 2007 for environmental compliance. (b) Lease Commitments The following table sets forth information concerning CERC's obligations under non-cancelable long-term operating leases, principally consisting of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions):

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

Total rental expense for all operating leases was $33 million, $31 million and $27 million in 2000, 2001 and 2002, respectively. (c) Environmental Matters Hydrocarbon Contamination. On August 24, 2001, 37 plaintiffs filed suit against Reliant Energy Gas Transmission Company (REGT), Reliant Energy Pipeline Services, Inc., RERC Corp., RES, other Reliant Energy entities and third parties, in the 1st Judicial District Court, Caddo Parish, Louisiana. The petition has now been supplemented seven times. As of November 21, 2002, there were 695 plaintiffs, a majority of whom are Louisiana residents. In addition to the Reliant Energy entities, the plaintiffs have sued the State of Louisiana through its Department of Environmental Quality, several individuals, some of whom are present employees of the State of Louisiana, the Bayou South Gas Gathering Company, L.L.C., Martin Timber Company, Inc., and several trusts. Additionally on April 4, 2002, two plaintiffs filed a separate suit with identical allegations against the same parties in the same court. More recently, on January 6, 2003, two other plaintiffs filed a third suit of similar allegations against CenterPoint Energy, as well as other defendants, in Bossier Parish (26th Judicial District Court). 7

The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility." This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. This site was originally leased and operated by predecessors of REGT in the late 1940s and was operated until Arkansas Louisiana Gas Company ceased operations of the plant in the late 1970s. Beginning about 1985, the predecessors of certain Reliant Energy defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they own or lease. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. As of December 31, 2002, CERC is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory, two of which CERC believes were neither owned nor operated by CERC, and for which CERC believes it has no liability. At December 31, 2001 and 2002, CERC had accrued $23 million and $19 million, respectively, for remediation of the Minnesota sites. At December 31, 2002, the estimated range of possible remediation costs was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has an environmental expense tracker mechanism in its rates in Minnesota. CERC has collected $12 million at December 31, 2002 to be used for future environmental remediation. CERC has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for sites in other states. Based on current information, CERC has not been able to quantify a range of environmental expenditures for potential remediation expenditures with respect to other MGP sites. Mercury Contamination. CERC's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by CERC at some sites in the past, and CERC has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by CERC and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, CERC believes that the costs of any remediation of these sites will not be material to CERC's financial condition, results of operations or cash flows. 8

Other Environmental. From time to time CERC has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Considering the information currently known about such sites and the involvement of CERC in activities at these sites, CERC does not believe that these matters will have a material adverse effect on CERC's financial position, results of operations or cash flows. Department of Transportation In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002. This legislation applies to CERC's interstate pipelines as well as its intra-state pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires companies to assess the integrity of their pipeline transmission and distribution facilities in areas of high population concentration and further requires companies to perform remediation activities, in accordance with the requirements of the legislation, over a 10-year period. 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 CERC anticipates that increased capital and operating expenses will be required to comply with the requirements of the legislation, it will not be able to quantify the level of spending required until the Department of Transportation's final rules are issued. (d) OTHER LEGAL MATTERS Natural Gas Measurement Lawsuits. In 1997, a suit was filed under the Federal False Claims Act against RERC Corp. (now CERC Corp.) and certain of its subsidiaries alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In addition, CERC Corp., CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, Inc. and CenterPoint Energy-Mississippi River Transmission Corporation are defendants in a class action filed in May 1999 against approximately 245 pipeline companies and their affiliates. The plaintiffs in the case purport to represent a class of natural gas producers and fee royalty owners who allege that they have been subject to systematic gas mismeasurement by the defendants for more than 25 years. The plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. The action is currently pending in state court in Stevens County, Kansas. Motions to dismiss and class certification issues have been briefed and argued. 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 9

Petition requests that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs and that the city has no legal or factual support for the statements made in its letter. Gas Recovery Suits. In October 2002, a suit was filed in state district court in Wharton County, Texas, against CenterPoint Energy, CERC, Entex Gas Marketing Company, and others alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utility Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to residential and small commercial consumers of natural gas. In February 2003, a similar suit was filed against CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by CERC. The plaintiffs in both cases seek restitution for alleged overcharges, exemplary damages and penalties. CERC denies that it has overcharged any of its customers for natural gas and believes that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. Other Proceedings. CERC is involved in other proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Management currently believes that the disposition of these matters will not have a material adverse effect on CERC's financial position, results of operations or cash flows. 10

13. REPORTABLE SEGMENTS Because CERC Corp. is a wholly owned subsidiary of CenterPoint Energy, CERC's determination of reportable segments considers the strategic operating units under which CenterPoint Energy manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to segments. Reportable business segments from previous years have been restated to conform to the 2002 presentation. CERC accounts for intersegment sales as if the sales were to third parties, that is, at current market prices. Beginning in the first quarter of 2002, CERC began to evaluate performance on an earnings (loss) before interest expense, distribution on trust preferred securities and income taxes (EBIT) basis. Prior to 2002, CERC evaluated performance on the basis of operating income. EBIT, as defined, is shown because it is a measure CERC uses to evaluate the performance of its business segments and CERC believes it is a measure of financial performance that may be used as a means to analyze and compare companies on the basis of operating performance. CERC expects that some analysts and investors will want to review EBIT when evaluating CERC. EBIT is not defined under accounting principles generally accepted in the United States (GAAP), should not be considered in isolation or as a substitute for a measure of performance prepared in accordance with GAAP and is not indicative of operating income from operations as determined under GAAP. Additionally, CERC's computation of EBIT may not be comparable to other similarly titled measures computed by other companies, because all companies do not calculate it in the same fashion. CERC's reportable business segments include the following: Natural Gas Distribution, Pipelines and Gathering, Wholesale Energy and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers, and some non-rate regulated retail gas marketing operations. Pipelines and Gathering includes the interstate natural gas pipeline operations and natural gas gathering and pipeline services. Reliant Energy Services was previously reported within the Wholesale Energy segment. Other Operations includes unallocated general corporate expenses and non-operating investments. During 2000, Reliant Energy transferred RERC's non-rate regulated retail gas marketing from Other Operations to Natural Gas Distribution and RERC's natural gas gathering business from Wholesale Energy to Pipelines and Gathering. On December 31, 2000, RERC Corp. transferred all of the outstanding stock of RESI, Arkla Finance and RE Europe Trading, all wholly owned subsidiaries of 11

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

- --------------- (1) Included in revenues from external customers are revenues from sales to Reliant Resources, a former affiliate, of $816 million, $181 million and $42 million for the years ended December 31, 2000, 2001 and 2002, respectively. 12