SEC Filing | CenterPoint Energy, Inc.,

View:

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, 2005 OR [ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE TRANSITION PERIOD FROM __________ TO __________. ---------- Commission file number 1-13265 CENTERPOINT ENERGY RESOURCES CORP. (Exact name of registrant as specified in its charter) DELAWARE 76-0511406 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1111 LOUISIANA (713) 207-1111 HOUSTON, TEXAS 77002 (Registrant's telephone number, (Address and zip code of including area code) principal executive offices) 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 ----- ----- Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes No X ----- ----- As of November 1, 2005, 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, 2005 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements....................................................... 1 Statements of Consolidated Operations Three Months and Nine Months Ended September 30, 2004 and 2005 (unaudited)... 1 Consolidated Balance Sheets December 31, 2004 and September 30, 2005 (unaudited)......................... 2 Statements of Consolidated Cash Flows Nine Months Ended September 30, 2004 and 2005 (unaudited).................... 4 Notes to Unaudited Consolidated Financial Statements............................ 5 Item 2. Management's Narrative Analysis of the Results of Operations............... 16 Item 4. Controls and Procedures.................................................... 25 PART II. OTHER INFORMATION Item 1. Legal Proceedings.......................................................... 26 Item 5. Other Information.......................................................... 26 Item 6. Exhibits................................................................... 29 i

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. The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements: - state and federal legislative and regulatory actions or developments, constraints placed on our activities or business by the Public Utility Holding Company Act of 1935, as amended (1935 Act), the impact of the repeal of the 1935 Act and changes in or application of laws or regulations applicable to other aspects of our business and actions with respect to: - allowed rates of return; - rate structures; - recovery of investments; and - operation and construction of facilities; - timely rate increases, including recovery of costs; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital, receipt of certain financing approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - effectiveness of our risk management activities; - inability of various counterparties to meet their obligations to us; - non-payment of our services due to financial distress of our customers; - our ability to control costs; - the investment performance of CenterPoint Energy's employee benefit plans; ii

- our potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or to have the anticipated benefits to us; and - other factors we discuss in "Risk Factors" in Item 5 of Part II of this report beginning on page 26. Additional risk factors are described in other documents we file with the Securities and Exchange Commission. You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement. iii

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 (MILLIONS OF DOLLARS) (UNAUDITED) THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ------ ------ ------ ------ REVENUES ............................... $1,219 $1,732 $4,739 $5,663 ------ ------ ------ ------ EXPENSES: Natural gas ......................... 928 1,422 3,701 4,563 Operation and maintenance ........... 184 188 536 532 Depreciation and amortization ....... 47 50 139 149 Taxes other than income taxes ....... 28 32 107 108 ------ ------ ------ ------ Total ............................ 1,187 1,692 4,483 5,352 ------ ------ ------ ------ OPERATING INCOME ....................... 32 40 256 311 ------ ------ ------ ------ OTHER INCOME (EXPENSE): Interest and other finance charges .. (45) (39) (134) (136) Other, net .......................... 4 6 10 18 ------ ------ ------ ------ Total ............................ (41) (33) (124) (118) ------ ------ ------ ------ INCOME (LOSS) BEFORE INCOME TAXES ...... (9) 7 132 193 Income Tax (Expense) Benefit ........ 7 (3) (49) (66) ------ ------ ------ ------ NET INCOME (LOSS) ...................... $ (2) $ 4 $ 83 $ 127 ====== ====== ====== ====== See Notes to the Company's Interim Financial Statements 1

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONSOLIDATED BALANCE SHEETS (MILLIONS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- CURRENT ASSETS: Cash and cash equivalents .................................. $ 141 $ 107 Accounts and notes receivable, net ......................... 613 587 Accrued unbilled revenue ................................... 502 189 Accounts and notes receivable - affiliated companies, net .. 12 -- Materials and supplies ..................................... 25 32 Natural gas inventory ...................................... 174 310 Non-trading derivative assets .............................. 50 195 Taxes receivable ........................................... 155 1 Deferred tax asset ......................................... 12 2 Prepaid expenses ........................................... 9 10 Other ...................................................... 92 233 ------ ------ Total current assets .................................... 1,785 1,666 ------ ------ PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment .............................. 4,296 4,508 Less accumulated depreciation .............................. (462) (524) ------ ------ Property, plant and equipment, net ...................... 3,834 3,984 ------ ------ OTHER ASSETS: Goodwill, net .............................................. 1,741 1,744 Other intangibles, net ..................................... 20 19 Non-trading derivative assets .............................. 18 108 Accounts and notes receivable - affiliated companies, net .. 18 16 Other ...................................................... 117 138 ------ ------ Total other assets ...................................... 1,914 2,025 ------ ------ TOTAL ASSETS .................................................. $7,533 $7,675 ====== ====== See Notes to the Company's Interim Financial Statements 2

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) CONSOLIDATED BALANCE SHEETS -- (CONTINUED) (MILLIONS OF DOLLARS) (UNAUDITED) LIABILITIES AND STOCKHOLDER'S EQUITY DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- CURRENT LIABILITIES: Current portion of long-term debt ....................... $ 367 $ 6 Accounts payable ........................................ 799 784 Accounts and notes payable - affiliated companies, net .. -- 13 Taxes accrued ........................................... 78 63 Interest accrued ........................................ 58 46 Customer deposits ....................................... 60 60 Non-trading derivative liabilities ...................... 26 89 Accumulated deferred income taxes, net .................. -- 2 Other ................................................... 273 559 ------ ------ Total current liabilities ............................ 1,661 1,622 ------ ------ OTHER LIABILITIES: Accumulated deferred income taxes, net .................. 641 637 Non-trading derivative liabilities ...................... 6 14 Benefit obligations ..................................... 128 129 Other ................................................... 557 659 ------ ------ Total other liabilities .............................. 1,332 1,439 ------ ------ LONG-TERM DEBT ............................................. 2,001 1,986 ------ ------ COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 9) STOCKHOLDER'S EQUITY: Common stock ............................................ -- -- Paid-in capital ......................................... 2,232 2,292 Retained earnings ....................................... 305 332 Accumulated other comprehensive income .................. 2 4 ------ ------ Total stockholder's equity ........................... 2,539 2,628 ------ ------ TOTAL LIABILITIES AND STOCKHOLDER'S EQUITY .............. $7,533 $7,675 ====== ====== See Notes to the Company's Interim Financial Statements 3

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) STATEMENTS OF CONSOLIDATED CASH FLOWS (MILLIONS OF DOLLARS) (UNAUDITED) NINE MONTHS ENDED SEPTEMBER 30, ------------------------------- 2004 2005 ----- ----- CASH FLOWS FROM OPERATING ACTIVITIES: Net income ............................................................. $ 83 $ 127 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization ....................................... 139 149 Amortization of deferred financing costs ............................ 7 6 Deferred income taxes ............................................... 9 (2) Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net ................... 343 339 Accounts receivable/payable, affiliates .......................... (23) (10) Inventory ........................................................ (81) (134) Taxes receivable ................................................. 21 214 Accounts payable ................................................. (144) -- Fuel cost recovery ............................................... 43 (69) Interest and taxes accrued ....................................... (3) (26) Net non-trading derivative assets and liabilities ................ (18) 6 Margin deposits, net ............................................. 15 78 Short-term risk management activities, net ....................... 1 (19) Other current assets ............................................. (23) (41) Other current liabilities ........................................ (4) 65 Other assets ..................................................... (6) 6 Other liabilities ................................................ (8) -- Other, net .......................................................... (3) (2) ----- ----- Net cash provided by operating activities ........................ 348 687 ----- ----- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures ................................................... (170) (280) Decrease (increase) in notes receivable from affiliates ................ (83) 38 Other, net ............................................................. (4) (5) ----- ----- Net cash used in investing activities ............................ (257) (247) ----- ----- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings, net ................................. (63) -- Payments of long-term debt ............................................. -- (372) Decrease in notes payable with affiliates .............................. (32) (1) Debt issuance costs .................................................... (2) (1) Dividend to parent ..................................................... (12) (100) ----- ----- Net cash used in financing activities ............................ (109) (474) ----- ----- NET DECREASE IN CASH AND CASH EQUIVALENTS ................................. (18) (34) CASH AND CASH EQUIVALENTS AT BEGINNING OF THE PERIOD ...................... 34 141 ----- ----- CASH AND CASH EQUIVALENTS AT END OF THE PERIOD ............................ $ 16 $ 107 ===== ===== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest ............................................................... $ 137 $ 142 Income taxes ........................................................... 73 91 See Notes to the Company's Interim Financial Statements 4

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS (1) BACKGROUND AND BASIS OF PRESENTATION General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy Resources Corp. are the consolidated interim financial statements and notes (Interim Financial Statements) of CenterPoint Energy Resources Corp. and its subsidiaries (collectively, CERC Corp. or the Company). The Interim Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2004 (CERC Corp. Form 10-K). Background. The Company's operating subsidiaries own and operate natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. The Company's operations of its local distribution companies are conducted through two unincorporated divisions: Minnesota Gas and Southern Gas Operations, which includes Houston Gas. Through wholly owned subsidiaries, the Company owns two interstate natural gas pipelines and gas gathering systems, provides various ancillary services, and offers variable and fixed-price physical natural gas supplies to commercial and industrial customers and natural gas distributors. 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 of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the Texas Electric Choice Plan. CenterPoint Energy is a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). The 1935 Act and related rules and regulations impose a number of restrictions on the activities of CenterPoint Energy and those of its subsidiaries. The 1935 Act, among other things, 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 affiliated service, sales and construction contracts. On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act). Under that legislation, the 1935 Act is repealed effective February 8, 2006. After the effective date of the repeal, CenterPoint Energy and its subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, CenterPoint Energy and its subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy Act grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on CenterPoint Energy and its subsidiaries as a result of that rulemaking. 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 Company's Interim Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows 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. Note 2(e) (Regulatory Assets and Liabilities), Note 3 (Regulatory Matters), Note 5 (Derivative Instruments) and Note 9 (Commitments and Contingencies) to the consolidated annual financial statements in the CERC Corp. Form 5

10-K (CERC Corp. 10-K Notes) relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference. For information regarding environmental matters and legal proceedings, see Note 9 to the Interim Financial Statements. (2) NEW ACCOUNTING PRONOUNCEMENTS In May 2005, the Financial Accounting Standards Board (FASB) issued Statement of Financial Accounting Standards (SFAS) No. 154, "Accounting Changes and Error Corrections, a replacement of APB Opinion No. 20 and FASB Statement No. 3" (SFAS No. 154). SFAS No. 154 provides guidance on the accounting for and reporting of accounting changes and error corrections. It establishes, unless impracticable, retrospective application as the required method for reporting a change in accounting principle in the absence of explicit transition requirements specific to the newly adopted accounting principle. The correction of an error in previously issued financial statements is not an accounting change and must be reported as a prior-period adjustment by restating previously issued financial statements. SFAS No. 154 is effective for accounting changes and corrections of errors made in fiscal years beginning after December 15, 2005. In March 2005, the FASB issued FASB Interpretation No. (FIN) 47, "Accounting for Conditional Asset Retirement Obligations" (FIN 47). FIN 47 clarifies that an entity must record a liability for a "conditional" asset retirement obligation if the fair value of the obligation can be reasonably estimated. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. The Company is evaluating the effect of adoption of this new standard on its financial position, results of operations and cash flows. (3) REGULATORY MATTERS (a) Rate Cases. In November 2004, Southern Gas Operations filed an application for a $28 million base rate increase, as adjusted, with the Arkansas Public Service Commission (APSC). In September 2005, the APSC ordered an $11 million rate reduction, including a $10 million reduction relating to depreciation rates, which went into effect on September 25, 2005. In April 2005, the Railroad Commission of Texas (Railroad Commission) approved a settlement that increased Southern Gas Operations' base rate and service revenues by a combined $2 million in the unincorporated environs of its Beaumont/East Texas and South Texas Divisions. In June and August 2005, Southern Gas Operations filed requests to implement these rates within the incorporated cities located in its Beaumont/East Texas and South Texas Divisions. If these rates are approved in all jurisdictions as requested, Southern Gas Operations' base rate and service revenues are expected to increase by an additional $16 million annually. In June 2005, the Minnesota Public Utilities Commission (MPUC) approved a settlement which increases Minnesota Gas' base rates by approximately $9 million annually. An interim rate increase of $17 million had been implemented in October 2004. Substantially all of the excess amounts collected in interim rates over those approved in the final settlement were refunded to customers in the third quarter. On November 2, 2005, Minnesota Gas filed a request with the MPUC to increase annual rates by $41 million. It has requested that an interim rate increase of $35 million be implemented January 1, 2006. Any difference between the interim rates collected and the final rates would be subject to refund to customers. A decision by the MPUC is expected in the third quarter of 2006. (b) City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Southern Gas Operations had overcharged residential and small commercial customers in that city for gas costs under supply agreements in effect since 1992. That dispute was referred to the Railroad Commission by agreement of the parties for a determination of whether Southern Gas Operations has properly charged and collected for gas service to its residential and commercial customers in its Tyler distribution system in accordance with lawful filed tariffs during the period beginning November 1, 1992, and 6

ending October 31, 2002. In December 2004, the Railroad Commission conducted a hearing on the matter. On May 25, 2005, the Railroad Commission issued a final order finding that the Company had complied with its tariffs, acted prudently in entering into its gas supply contracts, and prudently managed those contracts. On August 10, 2005, the City of Tyler appealed this order to the Court of Appeals. (c) Settlement of FERC Audit. On June 27, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a subsidiary of CERC Corp., received an Order from FERC accepting the terms of a settlement agreed upon by CEGT with the Staff of the FERC's Office of Market Oversight and Investigations (OMOI). The settlement brought to a conclusion an investigation of CEGT initiated by OMOI in August 2003. Among other things, the investigation involved a comprehensive review of CEGT's relationship with its marketing affiliates and compliance with various FERC record-keeping and reporting requirements covering the period from January 1, 2001 through September 22, 2004. OMOI Staff took the position that some of CEGT's actions resulted in a limited number of violations of FERC's affiliate regulations or were in violation of certain record-keeping and administrative requirements. OMOI did not find any systematic violations of its rules governing communications or other relationships among affiliates. The settlement included two remedies: a payment of a $270,000 civil penalty and the execution of a compliance plan, applicable to both CEGT and CenterPoint Energy-Mississippi River Transmission Corporation (MRT). The compliance plan consists of a detailed set of Implementation Procedures that will facilitate compliance with FERC's Order No. 2004, the Standards of Conduct, which regulate behavior between regulated entities and their affiliates. The Company does not believe the compliance plan will have any material effect on CEGT's or MRT's ability to conduct their business. (4) DERIVATIVE FINANCIAL 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 in cash flows of its natural gas businesses on its operating results and cash flows. Cash Flow Hedges. During the nine months ended September 30, 2004 and 2005, hedge ineffectiveness was less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Company's Statements of Consolidated Operations under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of September 30, 2005, the Company expects $(0.4) million in accumulated other comprehensive loss to be reclassified into net income during the next twelve months. Other Derivative Financial Instruments. The Company also has natural gas contracts that are derivatives which are not hedged and are accounted for on a mark-to-market basis with changes in fair value reported through earnings. Load following services that the Company offers its natural gas customers create an inherent tendency for the Company to be either long or short natural gas supplies relative to customer purchase commitments. The Company measures and values all of its volumetric imbalances on a real-time basis to minimize its exposure to commodity price and volume risk. The Company does not engage in proprietary or speculative commodity trading. Unhedged positions are accounted for by adjusting the carrying amount of the contracts to market and recognizing any gain or loss in operating income, net. During the nine months ended September 30, 2004 and 2005, the Company recognized net gains (losses) related to unhedged positions amounting to $(4) million and $14 million, respectively. As of December 31, 2004, the Company had recorded short-term risk management assets and liabilities of $4 million and $5 million, respectively, included in other current assets and other current liabilities, respectively. As of September 30, 2005, the Company had recorded short-term risk management assets and liabilities of $55 million and $37 million, respectively, included in other current assets and other current liabilities, respectively. 7

A portion of CenterPoint Energy Services, Inc.'s (CES) activities include entering into transactions for the physical purchase, transportation and sale of natural gas at different locations (physical contracts). CES attempts to mitigate basis risk associated with these activities by entering into financial derivative contracts (financial contracts or financial basis swaps) to address market price volatility between the purchase and sale delivery points that can occur over the term of the physical contracts. The underlying physical contracts are accounted for on an accrual basis with all associated earnings not recognized until the time of actual physical delivery. The timing of the earnings impacts for the financial contracts differs from the physical contracts because the financial contracts meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are recorded at fair value as of each reporting balance sheet date with changes in value reported through earnings. Changes in prices between the delivery points (basis spreads) can and do vary daily resulting in changes to the fair value of the financial contracts. However, the economic intent of the financial contracts is to fix the actual net difference in the natural gas pricing at the different locations for the associated physical purchase and sale contracts throughout the life of the physical contracts and thus, when combined with the physical contracts' terms, provide an expected fixed gross margin on the physical contracts that will ultimately be recognized in earnings at the time of actual delivery of the natural gas. As of September 30, 2005, the mark-to-market value of the financial contracts described above reflected an unrealized loss of $3.6 million; however, the underlying expected fixed gross margin associated with delivery under the physical contracts combined with the price risk management provided through the financial contracts is $2.3 million. As described above, over the term of these financial contracts, the quarterly reported mark-to-market changes in value may vary significantly and the associated unrealized gains and losses will be reflected in CES' earnings. CES also sells physical gas and basis to its end-use customers who desire to lock in a future spread between a specific location and Henry Hub (NYMEX). As a result, CES incurs exposure to commodity basis risk related to these transactions, which it attempts to mitigate by buying offsetting financial basis swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the financial basis swaps as of each reporting balance sheet date with changes in value reported through earnings. However, the associated physical sales contracts are accounted for using the accrual basis, whereby earnings impacts are not recognized until the time of actual physical delivery. Although the timing of earnings recognition for the financial basis swaps differs from the physical contracts, the economic intent of the financial basis swaps is to fix the basis spread over the life of the physical contracts to an amount substantially the same as the portion of the basis spread pricing included in the physical contracts. In so doing, over the period that the financial basis swaps and related physical contracts are outstanding, actual cumulative earnings impacts for changes in the basis spread should be minimal, even though from a timing perspective there could be fluctuations in unrealized gains or losses associated with the changes in fair value recorded for the financial basis swaps. The cumulative earnings impact from the financial basis swaps recognized each reporting period is expected to be offset by the value realized when the related physical sales occur. As of September 30, 2005, the mark-to-market value of the financial basis swaps reflected an unrealized loss of $4.8 million. (5) GOODWILL AND INTANGIBLES Goodwill by reportable business segment is as follows (in millions): DECEMBER 31, 2004 SEPTEMBER 30, 2004 2005 ----------------- -------------- Natural Gas Distribution .. $1,085 $1,085 Pipelines and Gathering ... 601 604 Other Operations .......... 55 55 ------ ------ Total .................. $1,741 $1,744 ====== ====== The Company performs its goodwill impairment test at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon adoption of SFAS No. 142, "Goodwill and Other Intangible Assets," the Company initially selected January 1 as its annual goodwill impairment testing date. Since the time the Company selected the January 1 date, the Company's year-end closing and reporting process has been truncated in order to meet the accelerated reporting requirements of the SEC, resulting in significant constraints on the Company's human resources at year-end and during its first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, the Company changed the date on which it performs its 8

annual goodwill impairment test from January 1 to July 1. The Company believes the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow it to utilize additional resources in conducting the annual impairment evaluation of goodwill. The Company performed the test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. The Company believes that this accounting change is an alternative accounting principle that is preferable under the circumstances. The components of the Company's other intangible assets consist of the following: DECEMBER 31, 2004 SEPTEMBER 30, 2005 ----------------------- ----------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION -------- ------------ -------- ------------ (IN MILLIONS) Land use rights................................. $ 7 $(3) $ 7 $ (3) Other........................................... 21 (5) 22 (7) --- --- --- ---- Total........................................... $28 $(8) $29 $(10) === === === ==== The Company recognizes specifically identifiable intangibles, including land use rights and permits, when specific rights and contracts are acquired. The Company has no intangible assets with indefinite lives recorded as of September 30, 2005. 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 both the three months ended September 30, 2004 and 2005 was $0.4 million. Amortization expense for other intangibles for the nine months ended September 30, 2004 and 2005 was $1.3 million and $1.4 million, respectively. Estimated amortization expense for the remainder of 2005 is approximately $0.5 million and is approximately $2 million per year for each of the five succeeding fiscal years. (6) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) Long-Term Debt. Credit Facilities. In June 2005, the Company replaced its $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. The new credit facility terminates on June 30, 2010. Borrowings under this facility may be made at the London interbank offered rate (LIBOR) plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. As of September 30, 2005, such credit facility was not utilized. Junior Subordinated Debentures (Trust Preferred Securities). In June 1996, a Delaware statutory business trust created by CERC Corp. (CERC Trust) issued $173 million aggregate amount of convertible preferred securities to the public. CERC Trust used the proceeds of the offering to purchase convertible junior subordinated debentures issued by CERC Corp. having an interest rate and maturity date that correspond to the distribution rate and mandatory redemption date of the convertible preferred securities. 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 junior subordinated debentures represented CERC Trust's sole asset and its entire operations. The amount of outstanding junior subordinated debentures was included in long-term debt as of December 31, 2004. On July 1, 2005, the remaining $0.3 million of convertible preferred securities and the $6 million of related convertible junior subordinated debentures were called for redemption on August 1, 2005. Most of the convertible preferred securities were converted prior to the redemption date and the remaining securities were redeemed. 9

(b) Receivables Facility. In January 2005, the Company's $250 million receivables facility was extended to January 2006 and temporarily increased, for the period from January 2005 to June 2005, to $375 million to provide additional liquidity to the Company during the peak heating season of 2005. As of September 30, 2005, the Company had $141 million of advances under its receivables facility. Advances under the receivables facility averaged $173 million for the nine months ended September 30, 2005. Sales of receivables were approximately $447 million and $480 million for the three months ended September 30, 2004 and 2005, respectively, and $1.7 billion and $1.4 billion for the nine months ended September 30, 2004 and 2005, respectively. (7) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax): FOR THE THREE MONTHS FOR THE NINE MONTHS ENDED SEPTEMBER 30, ENDED SEPTEMBER 30, -------------------- ------------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) Net income (loss) ........................................... $(2) $ 4 $ 83 $127 --- --- ---- ---- Other comprehensive income (loss): Net deferred gain from cash flow hedges .................. 17 1 34 11 Reclassification of deferred gain from cash flow hedges realized in net income ................................ (6) (7) (14) (9) --- --- ---- ---- Other comprehensive income (loss) ........................... 11 (6) 20 2 --- --- ---- ---- Comprehensive income (loss) ................................. $ 9 $(2) $103 $129 === === ==== ==== The following table summarizes the components of accumulated other comprehensive income: DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- (IN MILLIONS) Net deferred gain from cash flow hedges... $2 $4 == == (8) RELATED PARTY TRANSACTIONS The following table summarizes receivables from, or payables to, CenterPoint Energy or its subsidiaries: DECEMBER 31, SEPTEMBER 30, 2004 2005 ------------ ------------- (IN MILLIONS) Accounts receivable from affiliates...................................... $ 4 $ 11 Accounts payable to affiliates........................................... (34) (28) Notes receivable from affiliates(1)...................................... 42 4 ---- ---- Accounts and notes receivable/(payable) -- affiliated companies, net.. $ 12 $(13) ==== ==== Long-term accounts receivable from affiliates............................ $ 64 $ 64 Long-term accounts payable to affiliates................................. (45) (48) Long-term notes payable to affiliates.................................... (1) -- ---- ---- Long-term accounts and notes receivable -- affiliated companies, net.. $ 18 $ 16 ==== ==== - ---------- (1) Represents money pool investments. For the three months ended September 30, 2004 and 2005, the Company had net interest income related to affiliate borrowings of $2.9 million and $0.9 million, respectively. For the nine months ended September 30, 2004 and 2005, the Company had net interest income related to affiliate borrowings of $7.0 million and $3.5 million, respectively. 10

The 1935 Act generally prohibits borrowings by CenterPoint Energy from its subsidiaries, including the Company, either through the money pool or otherwise. For the three and nine months ended September 30, 2004, the sales and services provided by the Company to Texas Genco Holdings, Inc. (Texas Genco), a former subsidiary of CenterPoint Energy, totaled $3 million and $20 million, respectively. For the three and nine months ended September 30, 2005, the Company provided no sales or services to CenterPoint Energy or its subsidiaries. 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 margins, 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 $29 million and $33 million for the three months ended September 30, 2004 and 2005, respectively, and $84 million and $93 million for the nine months ended September 30, 2004 and 2005, respectively, and are included primarily in operation and maintenance expenses. Pursuant to the tax sharing agreement with CenterPoint Energy, the Company received an allocation of CenterPoint Energy's tax benefits totaling $5 million and $60 million for the three and nine months ended September 30, 2005, respectively, which was recorded as an increase to additional paid-in capital. In the second quarter of 2005, the Company paid a dividend of $100 million to Utility Holding, LLC, the Company's parent. (9) COMMITMENTS AND CONTINGENCIES (a) 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 brought 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 of the Company's 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. The Company believes that there has been no systematic mismeasurement of gas and that the suits are without merit. The Company does not expect the ultimate outcome to have a material impact on its financial condition, results of operations or cash flows. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CenterPoint Energy, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil 11

conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against the Company with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against the Company seeking to recover alleged overcharges for gas or gas services allegedly provided by Southern Gas Operations to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CenterPoint Energy, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In November 2004, the Miller case was removed to federal district court in Texarkana, Arkansas. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. In June 2005, the Miller County case was remanded to state district court in Miller County. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney's fees. In these cases, the Company, CenterPoint Energy and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The allegations in these cases are similar to those asserted in the City of Tyler proceeding described in Note 3(b). The Company and CenterPoint Energy do not expect the outcome of these matters to have a material impact on the financial condition, results of operations or cash flows of either the Company or CenterPoint Energy. Pipeline Safety Compliance. In 2005, the Company received an order from the Minnesota Office of Pipeline Safety to remove certain components from a portion of its distribution system by December 2, 2005. Those components were installed by a predecessor company and are not in compliance with current state and federal codes. The Company estimates the amount of expenditures to locate and replace such components to be approximately $38 million. The Company is seeking to recover the capitalized expenditures, together with a return on those amounts through rates. Minnesota Cold Weather Rule. In December 2004, the MPUC opened an investigation to determine whether the Company's practices regarding restoring natural gas service during the period between October 15 and April 15 (Cold Weather Period) are in compliance with the MPUC's Cold Weather Rule (CWR), which governs disconnection and reconnection of customers during the Cold Weather Period. The Minnesota Office of the Attorney General (OAG) issued its report alleging the Company has violated the CWR and recommended a $5 million penalty. The Company filed its reply comments in July 2005. The Company and the OAG have reached agreement on procedures to be followed for the current Cold Weather Period beginning October 15, 2005. In addition, in June 2005, the Company was named in a suit filed on behalf of a purported class of customers who allege that the Company's conduct under the CWR was in violation of the Minnesota Consumer Fraud Act and the Minnesota Deceptive Trade Practices Act and was negligent and fraudulent. The Company believes that it has not knowingly and intentionally violated the CWR and intends to vigorously contest the lawsuit. The Company does not expect this matter to have a material adverse effect on its financial condition, results of operations or cash flows. (b) Environmental Matters. Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some 12

unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The Company does not expect the ultimate cost associated with resolving this matter to have a material impact on the financial condition, results of operations or cash flows of the Company. Manufactured Gas Plant Sites. The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, the Company has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company's Minnesota service territory. The Company believes that it has no liability with respect to two of these sites. At September 30, 2005, the Company had accrued $18 million for remediation of certain Minnesota sites. At September 30, 2005, the estimated range of possible remediation costs for these sites was $7 million to $42 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. As of September 30, 2005, the Company has collected a total of $13 million from insurance companies and its environmental tracker to be used for future environmental remediation. In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by the Company or may have been owned by one of its former affiliates. The Company has been named as a defendant in two lawsuits under which contribution is sought by private parties 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 has also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. In March 2005, the court considering the other suit for contribution granted the Company's motion to dismiss on the grounds that the Company was not an "operator" of the site as had been alleged. The plaintiff in that case has filed an appeal of the court's dismissal of the Company. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, the Company believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP. 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 does not expect the costs of any remediation of these sites to be material to the Company's financial condition, results of operations or cash flows. 13

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company's financial condition, results of operations or cash flows. (c) Other Proceedings. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management does not expect the disposition of these matters to have a material adverse effect on the Company's financial condition, results of operations or cash flows. (10) 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 has identified the following reportable business segments: Natural Gas Distribution, Pipelines and Gathering, and Other Operations. For descriptions of the reportable business segments, see Note 12 to the CERC Corp. 10-K Notes, which is incorporated herein by reference. The following tables summarize financial data for the Company's reportable business segments: FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2004 --------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) ------------- ------------ ------------- (IN MILLIONS) Natural Gas Distribution .. $1,146 $ 3 $ (2) Pipelines and Gathering ... 73 35 35 Other Operations .......... -- 1 (1) Eliminations .............. -- (39) -- ------ ---- ---- Consolidated .............. $1,219 $ -- $ 32 ====== ==== ==== FOR THE THREE MONTHS ENDED SEPTEMBER 30, 2005 --------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING CUSTOMERS REVENUES INCOME (LOSS) ------------- ------------ ------------- (IN MILLIONS) Natural Gas Distribution .. $1,651 $ -- $(12) Pipelines and Gathering ... 81 35 52 Other Operations .......... -- 2 -- Eliminations .............. -- (37) -- ------ ---- ---- Consolidated .............. $1,732 $ -- $ 40 ====== ==== ==== 14

FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2004 -------------------------------------------------------------- REVENUES FROM NET TOTAL ASSETS AS EXTERNAL INTERSEGMENT OPERATING OF DECEMBER 31, CUSTOMERS REVENUES INCOME (LOSS) 2004 ------------- ------------ ------------- --------------- (IN MILLIONS) Natural Gas Distribution............ $4,522 $ 3 $137 $4,798 Pipelines and Gathering............. 217 107 123 2,637 Other Operations.................... -- 6 (4) 792 Eliminations........................ -- (116) -- (694) ------ ----- ---- ------ Consolidated........................ $4,739 $ -- $256 $7,533 ====== ===== ==== ====== FOR THE NINE MONTHS ENDED SEPTEMBER 30, 2005 -------------------------------------------------------------- REVENUES FROM NET TOTAL ASSETS AS EXTERNAL INTERSEGMENT OPERATING OF SEPTEMBER 30, CUSTOMERS REVENUES INCOME (LOSS) 2005 ------------- ------------ ------------- --------------- (IN MILLIONS) Natural Gas Distribution............ $5,408 $ 3 $ 146 $ 5,338 Pipelines and Gathering............. 252 110 168 2,925 Other Operations.................... 3 5 (3) 603 Eliminations........................ -- (118) -- (1,191) ------ ----- ----- ------- Consolidated........................ $5,663 $ -- $ 311 $ 7,675 ====== ===== ===== ======= (11) EMPLOYEE BENEFIT PLANS The Company's employees participate in CenterPoint Energy's postretirement benefit plan. The Company's net periodic cost includes the following components relating to postretirement benefits: THREE MONTHS ENDED NINE MONTHS ENDED SEPTEMBER 30, SEPTEMBER 30, ------------------ ----------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) Service cost........................ $-- $-- $ 1 $ 1 Interest cost....................... 3 2 8 6 Expected return on plan assets...... -- -- (1) (1) Net amortization.................... -- -- 1 1 Other ............................. -- 1 1 1 --- --- --- --- Net periodic cost................ $ 3 $ 3 $10 $ 8 === === === === The Company previously disclosed in its financial statements for the year ended December 31, 2004, that it expected to contribute $16 million to its postretirement benefits plan in 2005. As of September 30, 2005, $8 million has been contributed. 15

ITEM 2. MANAGEMENT'S NARRATIVE ANALYSIS OF THE RESULTS OF OPERATIONS The following narrative analysis should be read in combination with our Interim Financial Statements 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 of Reliant Energy, Incorporated (Reliant Energy). CenterPoint Energy is a registered public utility holding company under the Public Utility Holding Company Act of 1935, as amended (1935 Act). For information about the 1935 Act, please read " -- Liquidity -- Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends." 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 2 (Management's Discussion and Analysis of Financial Condition and Results of Operations) and Item 3 (Quantitative and Qualitative Disclosures About Market Risk) of Part I and the following Part II items of Form 10-Q: Item 2 (Unregistered Sales of Equity 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 our revenue and expense items between the three and nine months ended September 30, 2004 and the three and nine months ended September 30, 2005. Reference is made to "Management's Narrative Analysis of the Results of Operations" in Item 7 of the Annual Report on Form 10-K of CERC Corp. for the year ended December 31, 2004 (CERC Corp. Form 10-K). REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 On August 8, 2005, President Bush signed into law the Energy Policy Act of 2005 (Energy Act). Under that legislation, the 1935 Act is repealed effective February 8, 2006. After the effective date of repeal, CenterPoint Energy and its subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, CenterPoint Energy and its subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the Securities and Exchange Commission (SEC) under the 1935 Act. The Energy Act grants to the Federal Energy Regulatory Commission (FERC) authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on CenterPoint Energy and its subsidiaries as a result of that rulemaking. CONSOLIDATED RESULTS OF OPERATIONS Our results of operations are affected by, among other things, seasonal fluctuations in the demand for natural gas and price movements of energy commodities, 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 beginning on page 26 and "Management's Narrative Analysis of the Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of the CERC Corp. Form 10-K, which is incorporated herein by reference. 16

The following table sets forth our consolidated results of operations for the three and nine months ended September 30, 2004 and 2005, 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, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2004 2005 2004 2005 ------ ------ ------ ------ (IN MILLIONS) Revenues............................. $1,219 $1,732 $4,739 $5,663 ------ ------ ------ ------ Expenses: Natural gas....................... 928 1,422 3,701 4,563 Operation and maintenance......... 184 188 536 532 Depreciation and amortization..... 47 50 139 149 Taxes other than income taxes..... 28 32 107 108 ------ ------ ------ ------ Total Expenses................. 1,187 1,692 4,483 5,352 ------ ------ ------ ------ Operating Income..................... 32 40 256 311 Interest and Other Finance Charges... (45) (39) (134) (136) Other Income, net.................... 4 6 10 18 ------ ------ ------ ------ Income (Loss) Before Income Taxes.... (9) 7 132 193 Income Tax (Expense) Benefit......... 7 (3) (49) (66) ------ ------ ------ ------ Net Income (Loss).................... $ (2) $ 4 $ 83 $ 127 ====== ====== ====== ====== THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 We reported net income of $4 million for the three months ended September 30, 2005 as compared to a net loss of $2 million for the same period in 2004. The increase in net income of $6 million was primarily due to increased operating income of $17 million in our Pipelines and Gathering business segment offset by an increase in the operating loss in our Natural Gas Distribution business segment of $10 million. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 We reported net income of $127 million for the nine months ended September 30, 2005 as compared to $83 million for the same period in 2004. The increase in net income of $44 million was primarily due to increased operating income of $45 million in our Pipelines and Gathering business segment and increased operating income of $9 million in our Natural Gas Distribution business segment. This increase was partially offset by increased income tax expense of $17 million due to higher pre-tax income, which was reduced by a favorable tax audit adjustment recorded in the second quarter of 2005. RESULTS OF OPERATIONS BY BUSINESS SEGMENT The following tables present operating income for our Natural Gas Distribution and Pipelines and Gathering business segments for the three and nine months ended September 30, 2004 and 2005. For information regarding factors that may affect the future results of operations of our business segments, please read "Risk Factors -- Principal Risk Factors Associated with Our Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and "-- Other Risks" in Item 5 of Part II of this report beginning on page 26. 17

NATURAL GAS DISTRIBUTION The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- (IN MILLIONS, EXCEPT CUSTOMER DATA) Revenues .................................. $ 1,149 $ 1,651 $ 4,525 $ 5,411 ---------- ---------- ---------- ---------- Expenses: Natural gas ............................ 959 1,456 3,776 4,644 Operation and maintenance .............. 133 141 416 414 Depreciation and amortization .......... 36 39 106 116 Taxes other than income taxes .......... 23 27 90 91 ---------- ---------- ---------- ---------- Total expenses ...................... 1,151 1,663 4,388 5,265 ---------- ---------- ---------- ---------- Operating Income (Loss).................... $ (2) $ (12) $ 137 $ 146 ========== ========== ========== ========== Throughput (in billion cubic feet (Bcf)): Residential ............................ 15 9 121 107 Commercial and industrial .............. 39 38 171 158 Non-rate regulated ..................... 113 160 419 491 Elimination (1) ........................ (32) (26) (105) (104) ---------- ---------- ---------- ---------- Total Throughput .................... 135 181 606 652 ========== ========== ========== ========== Average number of customers: Residential ............................ 2,777,212 2,820,629 2,791,722 2,835,306 Commercial and industrial .............. 242,111 244,249 245,895 246,370 Non-rate regulated ..................... 6,249 6,515 6,234 6,520 ---------- ---------- ---------- ---------- Total ............................... 3,025,572 3,071,393 3,043,851 3,088,196 ========== ========== ========== ========== - ---------- (1) Elimination of intrasegment sales. THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Our Natural Gas Distribution business segment reported an operating loss of $12 million for the three months ended September 30, 2005 as compared to an operating loss of $2 million for the same period in 2004. Increases in operating income from rate increases ($3 million) and increased margins from our non-rate regulated natural gas sales business ($11 million) were more than offset by the impact of certain derivative transactions as discussed below ($8 million), increases in operation and maintenance expenses ($8 million) primarily related to higher bad debt expense ($5 million), increased depreciation expense primarily due to higher plant balances ($3 million) and higher taxes other than income taxes ($4 million). A portion of CenterPoint Energy Services, Inc.'s (CES) activities include entering into transactions for the physical purchase, transportation and sale of natural gas at different locations (physical contracts). CES attempts to mitigate basis risk associated with these activities by entering into financial derivative contracts (financial contracts or financial basis swaps) to address market price volatility between the purchase and sale delivery points that can occur over the term of the physical contracts. The underlying physical contracts are accounted for on an accrual basis with all associated earnings not recognized until the time of actual physical delivery. The timing of the earnings impacts for the financial contracts differs from the physical contracts because the financial contracts meet the definition of a derivative under SFAS No. 133, "Accounting for Derivative Instruments" (SFAS No. 133), and are recorded at fair value as of each reporting balance sheet date with changes in value reported through earnings. Changes in prices between the delivery points (basis spreads) can and do vary daily resulting in changes to the fair value of the financial contracts. However, the economic intent of the financial contracts is to fix the actual net difference in the natural gas pricing at the different locations for the associated physical purchase and sale contracts throughout the life of the physical contracts and thus, when combined with the physical contracts' terms, provide an expected fixed gross margin on the physical contracts that will ultimately be recognized in earnings at the time of actual delivery of the natural gas. As of September 30, 2005, the mark-to-market value of the financial contracts described above reflected an unrealized loss of $3.6 million; however, the underlying expected fixed gross margin 18

associated with delivery under the physical contracts combined with the price risk management provided through the financial contracts is $2.3 million. As described above, over the term of these financial contracts, the quarterly reported mark-to-market changes in value may vary significantly and the associated unrealized gains and losses will be reflected in CES' earnings. CES also sells physical gas and basis to its end-use customers who desire to lock in a future spread between a specific location and Henry Hub (NYMEX). As a result, CES incurs exposure to commodity basis risk related to these transactions, which it attempts to mitigate by buying offsetting financial basis swaps. Under SFAS No. 133, CES records at fair value and marks-to-market the financial basis swaps as of each reporting balance sheet date with changes in value reported through earnings. However, the associated physical sales contracts are accounted for using the accrual basis, whereby earnings impacts are not recognized until the time of actual physical delivery. Although the timing of earnings recognition for the financial basis swaps differs from the physical contracts, the economic intent of the financial basis swaps is to fix the basis spread over the life of the physical contracts to an amount substantially the same as the portion of the basis spread pricing included in the physical contracts. In so doing, over the period that the financial basis swaps and related physical contracts are outstanding, actual cumulative earnings impacts for changes in the basis spread should be minimal, even though from a timing perspective there could be fluctuations in unrealized gains or losses associated with the changes in fair value recorded for the financial basis swaps. The cumulative earnings impact from the financial basis swaps recognized each reporting period is expected to be offset by the value realized when the related physical sales occur. As of September 30, 2005, the mark-to-market value of the financial basis swaps reflected an unrealized loss of $4.8 million. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Our Natural Gas Distribution business segment reported operating income of $146 million for the nine months ended September 30, 2005 as compared to $137 million for the same period in 2004. Increases in operating income from rate increases ($19 million) and increased margins from our non-rate regulated natural gas sales business ($13 million) were partially offset by the impact of certain derivative transactions as discussed above ($8 million) and the impact of milder weather and decreased throughput net of continued customer growth with the addition of approximately 42,000 customers since September 2004 ($10 million). Operation and maintenance expense decreased $2 million. Excluding an $8 million charge recorded in the first quarter of 2004 for severance costs associated with staff reductions, operation and maintenance expenses increased by $6 million primarily due to increased bad debt expense ($7 million), partially offset by lower claims expense ($5 million) and the capitalization of previously incurred restructuring expenses as allowed by a regulatory order from the Railroad Commission of Texas ($5 million). Additionally, operating income was unfavorably impacted by increased depreciation expense primarily due to higher plant balances ($10 million). During the third quarter of 2005, our east Texas, Louisiana and Mississippi natural gas service areas were affected by Hurricanes Katrina and Rita. Damage to our facilities was limited, but approximately 10,000 homes and businesses were damaged to such an extent that they will not be taking service for the foreseeable future. The impact on the Natural Gas Distribution business segment's operating income was not material. 19

PIPELINES AND GATHERING The following table provides summary data of our Pipelines and Gathering business segment for the three and nine months ended September 30, 2004 and 2005: THREE MONTHS ENDED SEPTEMBER 30, NINE MONTHS ENDED SEPTEMBER 30, -------------------------------- ------------------------------- 2004 2005 2004 2005 ---- ---- ---- ---- (IN MILLIONS) Revenues .......................... $108 $116 $324 $362 ---- ---- ---- ---- Expenses: Natural gas .................... 6 -- 33 25 Operation and maintenance ...... 52 47 122 121 Depreciation and amortization .. 11 12 33 34 Taxes other than income taxes .. 4 5 13 14 ---- ---- ---- ---- Total expenses .............. 73 64 201 194 ---- ---- ---- ---- Operating Income .................. $ 35 $ 52 $123 $168 ==== ==== ==== ==== Throughput (in Bcf): Natural Gas Sales .............. 1 -- 8 4 Transportation ................. 181 199 658 700 Gathering ...................... 79 92 233 262 Elimination (1) ................ -- (1) (5) (4) ---- ---- ---- ---- Total Throughput ............ 261 290 894 962 ==== ==== ==== ==== - ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO THREE MONTHS ENDED SEPTEMBER 30, 2004 Our Pipelines and Gathering business segment reported operating income of $52 million for the three months ended September 30, 2005 compared to $35 million for the same period in 2004. Operating margins (revenues less natural gas costs) increased by $14 million primarily due to increased demand for certain transportation and ancillary services ($13 million) and increased throughput and demand for services related to our core gas gathering operations ($6 million), partially offset by reductions in project-related revenues ($6 million). Additionally, operation and maintenance expenses decreased by $5 million primarily due to a reduction in project-related expenses ($6 million), offset by increased litigation costs ($4 million) recorded in the third quarter of 2005. NINE MONTHS ENDED SEPTEMBER 30, 2005 COMPARED TO NINE MONTHS ENDED SEPTEMBER 30, 2004 Our Pipelines and Gathering business segment reported operating income of $168 million for the nine months ended September 30, 2005 compared to $123 million for the same period in 2004. Operating margins (revenues less natural gas costs) increased by $46 million primarily due to increased demand for certain transportation and ancillary services ($31 million), increased throughput and demand for services related to our core gas gathering operations ($20 million), partially offset by reductions in project-related revenues ($10 million). Additionally, operation and maintenance expenses decreased by $1 million primarily due to a reduction in project-related expenses ($9 million), offset by increased litigation costs ($4 million) recorded in the third quarter of 2005. CERTAIN FACTORS AFFECTING FUTURE EARNINGS For information on other developments, factors and trends that may have an impact on our future earnings, please read "Management's Narrative Analysis of Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of Part II of the CERC Corp. Form 10-K, which is incorporated herein by reference, and "Risk Factors" in Item 5 of Part II of this report beginning on page 26. LIQUIDITY 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 for the last three months of 20

2005 are approximately $145 million of capital expenditures. We expect that borrowings under our credit facility, anticipated cash flows from operations and borrowings from affiliates under the money pool described below will be sufficient to meet our cash needs for 2005. Cash needs may also be met by issuing securities in the capital markets. The 1935 Act currently regulates our financing ability, as more fully described in "--Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends" below. On October 25, 2005, CenterPoint Energy Gas Transmission Company (CEGT), a subsidiary of CERC Corp., executed a definitive Precedent Agreement with XTO Energy Inc. (XTO) for CEGT to transport approximately 600 million cubic feet per day of XTO's natural gas production for ten years. To fulfill the requirements of the agreement, CEGT will construct a new 168-mile pipeline between Carthage, Texas and its Perryville Hub in northeast Louisiana. The $375 million pipeline will have an initial design capacity of approximately one Bcf per day. Pending authorization by FERC, the pipeline could be in service as early as the winter of 2006-2007. This agreement is expected to cause an increase in our estimated capital requirements of approximately $5 million, $353 million and $17 million in 2005, 2006 and 2007, respectively, for our Pipelines and Gathering business segment from what was previously disclosed in the CERC Corp. Form 10-K. Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. We have a bankruptcy remote subsidiary, which we consolidate, which was formed for the sole purpose of buying receivables created by us and selling those receivables to an unrelated third-party. This transaction is accounted for as a sale of receivables under the provisions of SFAS No. 140, "Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities," and, as a result, the related receivables are excluded from the Consolidated Balance Sheet. In January 2005, the $250 million facility was extended to January 2006 and temporarily increased, for the period from January 2005 to June 2005, to $375 million. As of September 30, 2005, we had $141 million of advances under our receivables facility. Credit Facilities. In June 2005, we replaced our $250 million three-year revolving credit facility with a $400 million five-year revolving credit facility. The new credit facility terminates on June 30, 2010. Borrowings under this facility may be made at the London interbank offered rate (LIBOR) plus 55 basis points, including the facility fee, based on current credit ratings. An additional utilization fee of 10 basis points applies to borrowings whenever more than 50% of the facility is utilized. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. Our $400 million credit facility contains covenants, including a total debt to capitalization covenant of 65% and an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest covenant. Borrowings under our $400 million credit facility are available notwithstanding that a material adverse change has occurred or litigation that could be expected to have a material adverse effect has occurred, so long as other customary terms and conditions are satisfied. As of November 1, 2005, our $400 million credit facility was not utilized. Securities Registered with the SEC. At September 30, 2005, we had a shelf registration statement covering $500 million principal of debt securities. Temporary Investments. On September 30, 2005, we had temporary external investments of $74 million. Our temporary external investments were reduced by $325 million in July 2005 when the proceeds from the liquidation of such investments were used to pay our maturing debt. As of November 1, 2005, we had temporary external investments in a money market fund of $1.2 million. Such investments may be utilized to meet our cash flow needs. Money Pool. We participate in a "money pool" through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The money pool's net funding requirements are generally met by borrowings of CenterPoint Energy. The terms of the money pool are in accordance with requirements currently applicable to registered public utility holding companies under the 1935 Act and under an order from the SEC relating to our financing activities dated June 29, 2005 (June 2005 Financing Order). Our money pool borrowing limit under the existing order is $600 million. At November 1, 2005, we had no investments in or borrowings from the money pool. The money pool may not provide sufficient funds to meet our cash needs. 21

Impact on Liquidity of a Downgrade in Credit Ratings. As of November 1, 2005, 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: MOODY'S S&P FITCH - ------------------- ------------------- ------------------- RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ------ ---------- ------ ---------- ------ ---------- Baa3 Stable BBB Stable BBB Stable - ---------- (1) A "stable" outlook from Moody's indicates that Moody's does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed. (2) An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term. (3) A "stable" outlook from Fitch encompasses a one-to-two year horizon as to the likely ratings direction. We cannot assure you that these ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings, the willingness of suppliers to extend credit lines to us on an unsecured basis and the execution of our commercial strategies. A decline in credit ratings could increase borrowing costs under our $400 million revolving credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and would negatively impact our ability to complete capital market transactions as more fully described in " -- Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends" below. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce margins of our Natural Gas Distribution business segment. As described above under "-- Credit Facilities," our $400 million credit facility does not contain a material adverse change clause with respect to borrowings. CES, one of our wholly owned subsidiaries, provides comprehensive natural gas sales and services to industrial and commercial customers, electric generators and natural gas utilities throughout the central United States. In order to hedge its exposure to natural gas prices, CES has agreements with provisions standard for the industry that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. We estimate that as of September 30, 2005, unsecured credit limits extended to CES by counterparties could aggregate $115 million; however, utilized credit capacity is significantly lower. In addition, we purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on our S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly. Cross Defaults. Under CenterPoint Energy's revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. Pursuant to the indenture governing CenterPoint Energy's senior notes, 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. As of November 1, 2005, CenterPoint Energy had issued six series of senior notes aggregating $1.4 billion in principal amount under this indenture. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities. Other Factors that Could Affect Cash Requirements. In addition to the above factors, our liquidity and capital resources could be affected by: 22

- - cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment, particularly given gas price levels and volatility; - - acceleration of payment dates on certain gas supply contracts under certain circumstances as a result of increased gas prices and concentration of suppliers; - - increased costs related to the acquisition of gas; - - increases in interest expense in connection with debt refinancings and borrowings under our credit facility; - - various regulatory actions; - - slower customer payments and increased write-offs of receivables due to higher gas prices; - - restoration costs and revenues losses resulting from natural disasters such as hurricanes; and - - various of the risks identified in "Risk Factors" in Item 5 of Part II of this report beginning on page 26. Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends. Our bank facility and our receivables facility limit our debt as a percentage of our total capitalization to 65% and contain an EBITDA to interest covenant. Our parent, CenterPoint Energy, is a registered public utility holding company under the 1935 Act. The 1935 Act and related rules and regulations impose a number of restrictions on our parent's activities and those of its subsidiaries, including us. The 1935 Act, among other things, limits our parent's ability and the ability of its regulated subsidiaries, including us, to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. On August 8, 2005, President Bush signed into law the Energy Act. Under that legislation, the 1935 Act is repealed effective February 8, 2006. After the effective date of repeal, CenterPoint Energy and its subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, CenterPoint Energy and its subsidiaries remain subject to the provisions of the 1935 Act and the terms of orders issued by the SEC under the 1935 Act. The Energy Act grants to FERC authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by FERC and state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act, and on September 16, 2005, FERC issued proposed rules for public comment. It is presently unknown what, if any, specific obligations under those rules may be imposed on CenterPoint Energy and its subsidiaries as a result of that rulemaking. The June 2005 Financing Order establishes limits on the amount of external debt and equity securities that can be issued by CenterPoint Energy and its regulated subsidiaries, including us, without additional authorization but generally permits CenterPoint Energy to refinance its existing obligations and those of its regulated subsidiaries, including us. We are in compliance with the authorized limits. The order also generally permits utilization of our undrawn credit facilities. Unless we obtain a further order from the SEC, as of October 31, 2005, we are authorized to issue an additional $367 million of debt or preferred securities. In the June 2005 Financing Order, the SEC "reserved jurisdiction" over a number of matters, meaning that an order will be required from the SEC before we may conduct those activities. However, an order regarding the activities over which the SEC has reserved jurisdiction generally can be issued by the SEC more quickly than orders on other matters, although there is no assurance that a release of jurisdiction will be granted on a given matter or the terms under which such an order may be issued. In the June 2005 Financing Order, the SEC reserved jurisdiction over all authority otherwise granted if the common equity level of CenterPoint Energy falls below its level as of March 31, 2005 (11.4% net of securitization debt) or if the common equity ratio of either us or CenterPoint Energy Houston Electric, LLC, another wholly owned subsidiary of CenterPoint Energy, falls below 30%. Among the other transactions over which the SEC reserved jurisdiction are: (i) issuance of securities by CenterPoint Energy or any of its subsidiaries, including us, unless our and the issuer's other securities which are rated have an investment grade rating from at least one nationally recognized statistical rating organization, (ii) further investment in inactive 23

subsidiaries and (iii) payment of dividends by us from capital or unearned surplus. The June 2005 Financing Order also contains certain requirements for interest rates, maturities, issuance expenses and use of proceeds in connection with securities issued by us or any of our subsidiaries. So long as the common equity of CenterPoint Energy is less than 30% of its capitalization, the SEC also reserved jurisdiction over the use of proceeds from authorized financings for the acquisition of additional energy-related or gas-related companies. Finally, the SEC reserved jurisdiction over the issuance of $500 million in incremental debt and preferred securities by us. The total authorized amount of debt and preferred securities that could be outstanding during the authorization period, including the amounts over which the SEC has reserved jurisdiction and undrawn amounts under our revolving credit facility, is $3.256 billion. The foregoing and the following restrictions contained in the June 2005 Financing Order, along with other restrictions contained in that order, will cease to apply to us on February 8, 2006. The 1935 Act limits the payment of dividends to payment from current and retained earnings unless specific authorization is obtained to pay dividends from other sources. The June 2005 Financing Order also requires that we maintain a ratio of common equity to total capitalization of 30%. At September 30, 2005, our ratio was 57%. Relationship with CenterPoint Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to the consolidated financial statements in the CERC Form 10-K (CERC 10-K Notes). We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors of CenterPoint Energy. IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets" (SFAS No. 142). Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge. Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques. 24

We perform our goodwill impairment test at least annually and evaluate goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. Upon adoption of SFAS No. 142, we initially selected January 1 as our annual goodwill impairment testing date. Since the time we selected the January 1 date, our year-end closing and reporting process has been truncated in order to meet the accelerated periodic reporting requirements of the SEC resulting in significant constraints on our human resources at year-end and during our first fiscal quarter. Accordingly, in order to meet the accelerated reporting deadlines and to provide adequate time to complete the analysis each year, beginning in the third quarter of 2005, we changed the date on which we perform our annual goodwill impairment test from January 1 to July 1. We believe the July 1 alternative date will alleviate the resource constraints that exist during the first quarter and allow us to utilize additional resources in conducting the annual impairment evaluation of goodwill. We performed the test at July 1, 2005, and determined that no impairment charge for goodwill was required. The change is not intended to delay, accelerate or avoid an impairment charge. We believe that this accounting change is an alternative accounting principle that is preferable under the circumstances. UNBILLED REVENUES Revenues related to the sale and/or delivery of natural gas are generally recorded when natural gas is delivered to customers. However, the determination of sales to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, amounts of natural gas delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. NEW ACCOUNTING PRONOUNCEMENTS See Note 2 to the Interim Financial Statements for a discussion of new accounting pronouncements that affect us. 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, 2005 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, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 25

PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a description of certain legal and regulatory proceedings affecting us, please review Notes 3 and 9 to our Interim Financial Statements, "Business -- Regulation" and " -- Environmental Matters" in Item 1 of the CERC Corp. Form 10-K, "Legal Proceedings" in Item 3 of the CERC Corp. Form 10-K and Notes 3, 9(c) and (d) to the CERC Corp. 10-K Notes, each of which is incorporated herein by reference. ITEM 5. OTHER INFORMATION RISK FACTORS PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES RATE REGULATION OF OUR BUSINESS MAY DELAY OR DENY OUR ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER OUR COSTS. Our rates for our local distribution companies are regulated by certain municipalities and state commissions based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of our costs and enable us to earn a reasonable return on our invested capital. OUR BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO LESS NATURAL GAS BEING MARKETED, AND OUR PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION, STORAGE, GATHERING, TREATING AND PROCESSING OF NATURAL GAS, WHICH COULD LEAD TO LOWER PRICES, EITHER OR WHICH COULD HAVE AN ADVERSE IMPACT ON OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. 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 we market, sell or transport 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, WHICH COULD AFFECT THE ABILITY OF OUR SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS. 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, on the regulated side, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into our tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which we operate and increase the risk that our suppliers or customers fail or are unable to meet their obligations. Additionally, increasing gas prices could create the need for us to provide collateral in order to purchase gas. 26

IF WE WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF OUR SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON OUR OPERATIONS. Our contract with Laclede Gas Company, one of our pipeline's customers, is currently scheduled to expire in 2007. To the extent the pipeline is unable to extend this contract or the contract is renegotiated at rates substantially less than the rates provided in the current contract, there could be an adverse effect on our results of operations, financial condition and cash flows. A DECLINE IN OUR CREDIT RATING COULD RESULT IN US HAVING TO PROVIDE COLLATERAL IN ORDER TO PURCHASE GAS. If our credit rating were to decline, we might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when we were experiencing significant working capital requirements or otherwise lacked liquidity, we might be unable to obtain the necessary natural gas to meet our contractual distribution obligations, and our results of operations, financial condition and cash flows would be adversely affected. OUR INTERSTATE PIPELINES' AND NATURAL GAS GATHERING AND PROCESSING BUSINESS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. Our interstate pipelines and natural gas gathering and processing business 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 CONSOLIDATED FINANCIAL CONDITION IF WE ARE UNABLE TO ARRANGE FUTURE FINANCINGS ON ACCEPTABLE TERMS, OUR ABILITY TO REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED. As of September 30, 2005, we had $2.0 billion of outstanding indebtedness. As of September 30, 2005, approximately $152 million principal amount of this debt must be paid through 2006. The success of our future financing efforts may depend, at least in part, on: - general economic and capital market conditions; - credit availability from financial institutions and other lenders; - investor confidence in us and the markets in which we operate; - maintenance of acceptable credit ratings by us and by CenterPoint Energy; - market expectations regarding our future earnings and probable cash flows; - market perceptions of our ability to access capital markets on reasonable terms; - provisions of relevant tax and securities laws; and - our ability to obtain approval of specific financing transactions under the 1935 Act prior to the effective date of the repeal of the 1935 Act. 27

Our current credit ratings are discussed in "Management's Narrative Analysis of the Results of Operations -- Liquidity -- Impact on Liquidity of a Downgrade in Credit Ratings" in Item 2 of Part I of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms. THE FINANCIAL CONDITION AND LIQUIDITY OF OUR PARENT COMPANY COULD AFFECT OUR ACCESS TO CAPITAL, OUR CREDIT STANDING AND OUR FINANCIAL CONDITION. Our ratings and credit may be impacted by CenterPoint Energy's credit standing. As of September 30, 2005, CenterPoint Energy and its subsidiaries other than us have approximately $1.3 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. CenterPoint Energy and its other subsidiaries may not 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 credit ratings could be adversely affected. WE ARE AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY. CENTERPOINT ENERGY CAN EXERCISE SUBSTANTIAL CONTROL OVER OUR DIVIDEND POLICY AND BUSINESS AND OPERATIONS AND COULD DO SO IN A MANNER THAT IS ADVERSE TO OUR INTERESTS. We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following: - our payment of dividends; - decisions on our financings and our capital raising activities; - mergers or other business combinations; and - our acquisition or disposition of assets. There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. Under the 1935 Act, our ability to pay dividends is restricted by the SEC's requirement that common equity as a percentage of total capitalization must be at least 30% after the payment of any dividend. Under our credit facility and our receivables facility, our ability to pay dividends is restricted by a covenant that debt as a percentage of total capitalization may not exceed 65%. THE USE OF DERIVATIVE CONTRACTS BY US AND OUR SUBSIDIARIES IN THE NORMAL COURSE OF BUSINESS COULD RESULT IN FINANCIAL LOSSES THAT NEGATIVELY IMPACT OUR RESULTS OF OPERATIONS AND THOSE OF OUR SUBSIDIARIES. We use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We could recognize financial losses as a result of volatility in the market values of these contracts, or if a counterparty fails to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management's judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts. 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 its subsidiaries, including us, are subject to regulation by the SEC under the 1935 Act. The 1935 Act, among other things, limits the ability of a holding company and its regulated subsidiaries to issue 28

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 affiliated service, sales and construction contracts. CenterPoint Energy received an order from the SEC under the 1935 Act on June 29, 2005 relating to its financing activities, which is effective until June 30, 2008. Unforeseen events could result in capital needs in excess of currently authorized amounts, necessitating further authorization from the SEC. Approval of filings under the 1935 Act can take extended periods. The Energy Policy Act of 2005 repeals the 1935 Act effective in 2006. We cannot predict at this time the effect of the repeal on our business. OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms and the insurance proceeds received for any loss of or any damage to any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows. ITEM 6. 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. REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ------------------------------------------------ ------------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 1-13265 3(a)(1) 31, 1997 3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 1-13265 3(a)(2) Energy Corp. with and into HI Merger, Inc. 31, 1997 dated August 6, 1997 3.1.3 - Certificate of Amendment changing the name Form 10-K for the year ended December 1-13265 3(a)(3) to Reliant Energy Resources Corp. 31, 1998 3.1.4 - Certificate of Amendment changing the name Form 10-Q for the quarter ended June 1-13265 3(a)(4) to CenterPoint Energy Resources Corp. 30, 2003 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 1-13265 3(b) 31, 1997 4.1 - $400,000,000 Credit Agreement, dated as of Form 8-K dated June 29, 2005 1-13265 4.1 June 30, 2005, among CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders +18.1 - Preferability Letter re: Change in Accounting Principle +31.1 - Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan +31.2 - Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock 29

REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ------------------------------------------------ ------------------------------------- ------------ --------- +32.1 - Section 1350 Certification of David M. McClanahan +32.2 - Section 1350 Certification of Gary L. Whitlock +99.1 - Items incorporated by reference from the CERC Corp. Form 10-K. Item 1 "Business-- Regulation" and "-- Environmental Matters," Item 3 "Legal Proceedings" and Item 7 "Management's Narrative Analysis of the Results of Operations-- Certain Factors Affecting Future Earnings" and Notes 2(e) (Regulatory Assets and Liabilities), 3 (Regulatory Matters), 5 (Derivative Instruments), 9 (Commitments and Contingencies) and 12 (Reportable Business Segments). 30

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 9, 2005 31

EXHIBIT INDEX 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. REPORT OR SEC FILE OR EXHIBIT REGISTRATION REGISTRATION EXHIBIT NUMBER DESCRIPTION STATEMENT NUMBER REFERENCE - ------- ------------------------------------------------ ------------------------------------- ------------ --------- 3.1.1 - Certificate of Incorporation of RERC Corp. Form 10-K for the year ended December 1-13265 3(a)(1) 31, 1997 3.1.2 - Certificate of Merger merging former NorAm Form 10-K for the year ended December 1-13265 3(a)(2) Energy Corp. with and into HI Merger, Inc. 31, 1997 dated August 6, 1997 3.1.3 - Certificate of Amendment changing the name Form 10-K for the year ended December 1-13265 3(a)(3) to Reliant Energy Resources Corp. 31, 1998 3.1.4 - Certificate of Amendment changing the name Form 10-Q for the quarter ended June 1-13265 3(a)(4) to CenterPoint Energy Resources Corp. 30, 2003 3.2 - Bylaws of RERC Corp. Form 10-K for the year ended December 1-13265 3(b) 31, 1997 4.1 - $400,000,000 Credit Agreement, dated as of Form 8-K dated June 29, 2005 1-13265 4.1 June 30, 2005, among CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders +18.1 - Preferability Letter re: Change in Accounting Principle +31.1 - Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan +31.2 - Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock +32.1 - Section 1350 Certification of David M. McClanahan +32.2 - Section 1350 Certification of Gary L. Whitlock +99.1 - Items incorporated by reference from the CERC Corp. Form 10-K. Item 1 "Business-- Regulation" and "-- Environmental Matters," Item 3 "Legal Proceedings" and Item 7 "Management's Narrative Analysis of the Results of Operations-- Certain Factors Affecting Future Earnings" and Notes 2(e) (Regulatory Assets and Liabilities), 3 (Regulatory Matters), 5 (Derivative Instruments), 9 (Commitments and Contingencies) and 12 (Reportable Business Segments).

Exhibit 18.1 November 9, 2005 CenterPoint Energy Resources Corp. Houston, Texas 77002 Dear Sirs/Madams: At your request, we have read the description included in your Quarterly Report on Form 10-Q to the Securities and Exchange Commission for the quarter ended September 30, 2005, of the facts relating to the change in the date of annual goodwill impairment tests under Statement of Financial Accounting Standards No. 142, "Goodwill and Other Intangible Assets". We believe, on the basis of the facts so set forth and other information furnished to us by appropriate officials of the Company, that the accounting change described in your Form 10-Q is to an alternative accounting principle that is preferable under the circumstances. We have not audited any consolidated financial statements of CenterPoint Energy Resources Corp. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2004. Therefore, we are unable to express, and we do not express, an opinion on the facts set forth in the above-mentioned Form 10-Q, on the related information furnished to us by officials of the Company, or on the financial position, results of operations, or cash flows of CenterPoint Energy Resources Corp. and its consolidated subsidiaries as of any date or for any period subsequent to December 31, 2004. Yours truly, /s/ Deloitte & Touche LLP Houston, Texas

EXHIBIT 31.1 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 9, 2005 /s/ David M. McClanahan ------------------------------------- David M. McClanahan President and Chief Executive Officer

EXHIBIT 31.2 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 9, 2005 /s/ Gary L. Whitlock ----------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer

EXHIBIT 32.1 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the "Company") on Form 10-Q for the period ended September 30, 2005 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ David M. McClanahan - -------------------------------------------- David M. McClanahan President and Chief Executive Officer November 9, 2005

EXHIBIT 32.2 CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 In connection with the Quarterly Report of CenterPoint Energy Resources Corp. (the "Company") on Form 10-Q for the period ended September 30, 2005 (the "Report"), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that: 1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and 2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. /s/ Gary L. Whitlock - -------------------------------------------- Gary L. Whitlock Executive Vice President and Chief Financial Officer November 9, 2005

EXHIBIT 99.1 ITEM 1. BUSINESS REGULATION We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below. PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 As a subsidiary of a registered public utility holding company, we are subject to a comprehensive regulatory scheme imposed by the Securities and Exchange Commission (SEC) in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are generally required to obtain approval from the SEC under the 1935 Act. CenterPoint Energy received an order from the SEC under the 1935 Act on June 30, 2003 and supplemental orders thereafter relating to its financing activities and those of its regulated subsidiaries, including us, as well as other matters. The orders are effective until June 30, 2005. As of December 31, 2004, the orders generally permitted CenterPoint Energy and its subsidiaries, including us, to issue securities to refinance indebtedness outstanding at June 30, 2003, and authorized CenterPoint Energy and its subsidiaries, including us, to issue certain incremental external debt securities and common and preferred stock through June 30, 2005 in specified amounts, without prior authorization from the SEC. The orders also contain certain requirements regarding ratings of CenterPoint Energy's securities, interest rates, maturities, issuance expenses and use of proceeds. The orders require that we maintain a ratio of common equity to total capitalization of at least 30%. We intend to file an application for approval of our post-June 30, 2005 financing activities. The United States Congress from time to time considers legislation 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. FEDERAL ENERGY REGULATORY COMMISSION The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in intrastate commerce that are not first sales. The FERC regulates, 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. 1

On November 25, 2003, the FERC issued Order No. 2004, the final rule modifying the Standards of Conduct applicable to electric and natural gas transmission providers, governing the relationship between regulated transmission providers and certain of their affiliates. During 2004, the FERC Order was amended three times. The rule significantly changes and expands the regulatory burdens of the Standards of Conduct and applies essentially the same standards to jurisdictional electric transmission providers and natural gas pipelines. On February 9, 2004, our natural gas pipeline subsidiaries filed Implementation Plans required under the new rule. Those subsidiaries were further required to post their Implementation Procedures on their websites by September 22, 2004, and to be in compliance with the requirements of the new rule by that date. STATE AND LOCAL REGULATION In almost all communities in which we provide natural gas distribution services, we operate under franchises, certificates or licenses obtained from state and local authorities. The terms of the franchises, with various expiration dates, typically range from 10 to 30 years, though franchises in Arkansas are perpetual. None of our material franchises expire in the near term. We expect to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of our retail natural gas sales by our local distribution divisions are subject to traditional cost-of-service regulation at rates regulated by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and municipalities we serve. In 2004, the City of Houston, 28 other cities and the Railroad Commission approved a settlement that increased Houston Gas' base rate and service charge revenues by approximately $14 million annually. In February 2004, the Louisiana Public Service Commission (LPSC) approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its South Louisiana Division by approximately $2 million annually. In July 2004, Minnesota Gas filed an application for a general rate increase of $22 million with the Minnesota Public Utilities Commission (MPUC). Minnesota Gas and the Minnesota Department of Commerce have agreed to a settlement of all issues, including an annualized increase in the amount of $9 million, subject to approval by the MPUC. A final decision on this rate relief request is expected from the MPUC in the second quarter of 2005. Interim rates of $17 million on an annualized basis became effective on October 1, 2004, subject to refund. In July 2004, the LPSC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its North Louisiana Division by approximately $7 million annually. In October 2004, Southern Gas Operations filed an application for a general rate increase of approximately $3 million with the Railroad Commission for rate relief in the unincorporated areas of its Beaumont, East Texas and South Texas Divisions. The Railroad Commission staff has begun its review of the request, and a decision is anticipated in April 2005. In November 2004, Southern Gas Operations filed an application for a general rate increase of approximately $34 million with the Arkansas Public Service Commission (APSC). The APSC staff has begun its review of the request, and a decision is anticipated in the second half of 2005. In December 2004, the OCC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in Oklahoma by approximately $3 million annually. 2

DEPARTMENT OF TRANSPORTATION In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (the Act). This legislation applies to our interstate pipelines as well as our intrastate pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities, in accordance with the requirements of the legislation, over a 10-year period. In December 2003, the Department of Transportation Office of Pipeline Safety issued the final regulations to implement the Act. These regulations became effective on February 14, 2004 and provided guidance on, among other things, the areas that should be classified as HCA. Our interstate pipelines developed and implemented a written pipeline integrity management program in 2004, meeting the Department of Transportation Office of Pipeline Safety requirement of having the program in place by December 17, 2004. Our interstate and intrastate pipelines and our natural gas distribution companies anticipate that compliance with the new regulations will require increases in both capital and operating cost. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we anticipate compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period. ENVIRONMENTAL MATTERS Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines and gas gathering and processing systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as: - restricting the way we can handle or dispose of our wastes; - limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species; - requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and - enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations. In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to: - construct or acquire new equipment; - acquire permits for facility operations; - modify or replace existing and proposed equipment; and - clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities. 3

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment. The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance. We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental remediation activities in which we are presently engaged will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations. AIR EMISSIONS Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to any other similarly situated companies. WATER DISCHARGES Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations. 4

HAZARDOUS WASTE Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that are subject to RCRA or comparable state law requirements. LIABILITY FOR REMEDIATION The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as "Superfund," and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released, and companies that disposed or arranged for disposal of hazardous substances at offsite locations such as landfills. Although petroleum as well as natural gas is excluded from CERCLA's definition of "hazardous substance," in the course of our ordinary operations we generate wastes that may fall within the definition of a "hazardous substance." CERCLA authorizes the United States Environmental Protection Agency (EPA) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies. LIABILITY FOR PREEXISTING CONDITIONS Hydrocarbon Contamination. We and certain of our subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. We believe the ultimate cost associated with resolving this matter will not have a material impact on our financial condition or results of operations. 5

Manufactured Gas Plant Sites. We and our predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, we have completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in our Minnesota service territory. We believe that we have no liability with respect to two of these sites. At December 31, 2004, we had accrued $18 million for remediation of certain Minnesota sites. At December 31, 2004, the estimated range of possible remediation costs for these sites was $7 million to $42 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. We have utilized an environmental expense tracker mechanism in our rates in Minnesota to recover estimated costs in excess of insurance recovery. As of December 31, 2004, we have collected or accrued $13 million from insurance companies and ratepayers to be used for future environmental remediation. In addition to the Minnesota sites, the EPA and other regulators have investigated MGP sites that we owned or operated or may have been owned or operated by one of our former affiliates. We have been named as a defendant in lawsuits under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by our former affiliates or divisions. We have also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. We are investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, we believe we are not liable as a former owner or operator of those sites under CERCLA and applicable state statutes, and are vigorously contesting those suits and our designation as a PRP. Mercury Contamination. Our pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. We have found this type of contamination at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows. Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. 6

ITEM 3. LEGAL PROCEEDINGS For a brief description of certain legal and regulatory proceedings affecting us, please read "Regulation" and "Environmental Matters" in Item 1 of this report and Notes 3, 9(c) and 9(d) to our consolidated financial statements, which information is incorporated herein by reference. 7

ITEM 7. MANAGEMENT'S NARRATIVE ANALYSIS OF RESULTS OF OPERATIONS CERTAIN FACTORS AFFECTING FUTURE EARNINGS Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including: - state and federal legislative and regulatory actions or developments, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business; - timely rate increases, including recovery of costs; - industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns; - the timing and extent of changes in commodity prices, particularly natural gas; - changes in interest rates or rates of inflation; - weather variations and other natural phenomena; - the timing and extent of changes in the supply of natural gas; - commercial bank and financial market conditions, our access to capital, the costs of such capital, receipt of certain financing approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets; - actions by rating agencies; - inability of various counterparties to meet their obligations to us; - non-payment of our services due to financial distress of our customers; - our ability to control costs; - the investment performance of CenterPoint Energy's employee benefit plans; - our internal restructuring or other restructuring options that may be pursued; - our potential business strategies, including acquisitions or dispositions of assets or businesses, which cannot be assured to be completed or beneficial to us; and - other factors discussed in Item 1 of this report under "Risk Factors." 8

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (e) REGULATORY ASSETS AND LIABILITIES The Company applies the accounting policies established in SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71) to the accounts of the utility operations of the Natural Gas Distribution business segment and to some of the accounts of the Pipelines and Gathering business segment. The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2003 and 2004: DECEMBER 31, ----------------------- 2003 2004 --------- --------- (IN MILLIONS) Regulatory assets in other long-term assets............... $ 34 $ 21 Regulatory liabilities in other long-term liabilities..... (434) (433) --------- --------- Total................................................... $ (400) $ (412) ========= ========= If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write-off or write-down these regulatory assets and liabilities. The Company's rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2003 and 2004, these removal costs of $415 million and $428 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. The Company has also identified other asset retirement obligations that cannot be estimated because the assets associated with the retirement obligations have an indeterminate life. 9

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 3. REGULATORY MATTERS (a) RATE CASES In 2004, the City of Houston, 28 other cities and the Railroad Commission of Texas (Railroad Commission) approved a settlement that increased Houston Gas' base rate and service charge revenues by approximately $14 million annually. In February 2004, the Louisiana Public Service Commission (LPSC) approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its South Louisiana Division by approximately $2 million annually. In July 2004, Minnesota Gas filed an application for a general rate increase of $22 million with the Minnesota Public Utilities Commission (MPUC). Minnesota Gas and the Minnesota Department of Commerce have agreed to a settlement of all issues, including an annualized increase in the amount of $9 million, subject to approval by the MPUC. A final decision on this rate relief request is expected from the MPUC in the second quarter of 2005. Interim rates of $17 million on an annualized basis became effective on October 1, 2004, subject to refund. In July 2004, the LPSC approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in its North Louisiana Division by approximately $7 million annually. In October 2004, Southern Gas Operations filed an application for a general rate increase of approximately $3 million with the Railroad Commission for rate relief in the unincorporated areas of its Beaumont, East Texas and South Texas Divisions. The Railroad Commission staff has begun its review of the request, and a decision is anticipated in April 2005. In November 2004, Southern Gas Operations filed an application for a general rate increase of approximately $34 million with the Arkansas Public Service Commission (APSC). The APSC staff has begun its review of the request, and a decision is anticipated in the second half of 2005. In December 2004, the Oklahoma Corporation Commission approved a settlement that increased Southern Gas Operations' base rate and service charge revenues in Oklahoma by approximately $3 million annually. (b) CITY OF TYLER, TEXAS DISPUTE In July 2002, the City of Tyler, Texas, asserted that Southern Gas Operations had overcharged residential and small commercial customers in that city for gas costs under supply agreements in effect since 1992. That dispute has been referred to the Railroad Commission by agreement of the parties for a determination of whether Southern Gas Operations has properly charged and collected for gas service to its residential and commercial customers in its Tyler distribution system in accordance with lawful filed tariffs during the period beginning November 1, 1992, and ending October 31, 2002. In December 2004, the Railroad Commission conducted a hearing on the matter and is expected to issue a ruling in March or April of 2005. In a parallel action now in the Court of Appeals in Austin, Southern Gas Operations is challenging the scope of the Railroad Commission's inquiry which goes beyond the issue of whether Southern Gas Operations had properly followed its tariffs to include a review of Southern Gas Operations' historical gas purchases. The Company believes such a review is not permitted by law and is beyond what the parties requested in the joint petition that initiated the proceeding at the Railroad Commission. The Company believes that all costs for Southern Gas Operations' Tyler distribution system have been properly included and recovered from customers pursuant to Southern Gas Operations' filed tariffs. 10

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 5. DERIVATIVE INSTRUMENTS The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative financial instruments such as physical forward contracts, swaps and options (Energy Derivatives) to mitigate the impact of changes in its natural gas businesses on its operating results and cash flows. (a) NON-TRADING ACTIVITIES Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, the Company enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas (non-trading energy derivatives). The Company applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. The Company analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because the Company's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, the Company facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions. During 2004, hedge ineffectiveness of $0.4 million was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges, and in 2003 and 2002, no hedge ineffectiveness was recognized. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive loss. Once the anticipated transaction occurs, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Company's Statements of Consolidated Income under the caption "Natural Gas." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2004, the Company expects $5 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. The maximum length of time the Company is hedging its exposure to the variability in future cash flows for forecasted transactions on existing financial instruments is primarily two years with a limited amount of exposure up to five years. The Company's policy is not to exceed five years in hedging its exposure. 11

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Other Derivative Financial Instruments. The Company also has natural gas contracts which are derivatives which are not hedged. Load following services that the Company offers its natural gas customers create an inherent tendency to be either long or short natural gas supplies relative to customer purchase commitments. The Company measures and values all of its volumetric imbalances on a real time basis to minimize its exposure to commodity price and volume risk. The aggregate Value at Risk (VaR) associated with these operations is calculated daily and averaged $0.2 million with a high of $1 million during 2004. The Company does not engage in proprietary or speculative commodity trading. Unhedged positions are accounted for by adjusting the carrying amount of the contracts to market and recognizing any gain or loss in operating income, net. During 2004, the Company recognized net gains related to unhedged positions amounting to $7 million and as of December 31, 2004 had recorded short-term risk management assets and liabilities of $4 million and $5 million, respectively, included in other current assets and other current liabilities, respectively. (b) CREDIT RISKS In addition to the risk associated with price movements, credit risk is also inherent in the Company's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of the Company as of December 31, 2003 and 2004 (in millions): DECEMBER 31, 2003 DECEMBER 31, 2004 -------------------- --------------------- INVESTMENT INVESTMENT GRADE(1)(2) TOTAL GRADE(1)(2) TOTAL(3) ----------- ----- ----------- -------- Energy marketers........................................... $ 24 $ 35 $ 10 $ 17 Financial institutions..................................... 21 21 50 50 Other...................................................... -- 1 1 1 ----- ----- ----- ----- Total.................................................... $ 45 $ 57 $ 61 $ 68 ===== ===== ===== ===== - ------------ (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 encompass 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 $17 million non-trading derivative asset includes a $6 million asset due to trades with Reliant Energy Services, Inc. (Reliant Energy Services), a former affiliate. As of December 31, 2004, Reliant Energy Services did not have an investment grade rating. (c) GENERAL POLICY CenterPoint Energy has established a Risk Oversight Committee composed of corporate and business segment officers that oversees all commodity price and credit risk activities, including the Company's trading, marketing, risk management services and hedging activities. The committee's duties are to establish the Company'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 the Company's risk management policies and procedures and trading limits established by the CenterPoint Energy's board of directors. The Company'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. 12

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 9. COMMITMENTS AND CONTINGENCIES (a) COMMITMENTS Environmental Capital Commitments. The Company has various commitments for capital and environmental expenditures. The Company anticipates no significant capital and other special project expenditures between 2005 and 2009 for environmental compliance. Fuel Commitments. Fuel commitments include several long-term natural gas contracts related to the Company's natural gas distribution operations, which have various quantity requirements and durations that are not classified as non-trading derivative assets and liabilities in the Company's Consolidated Balance Sheets as of December 31, 2004 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for natural gas supply contracts are approximately $807 million in 2005, $401 million in 2006, $193 million in 2007, $29 million in 2008 and $1 million in 2009. 13

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (b) LEASE COMMITMENTS The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases, principally consisting of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions): 2005.................................. $ 20 2006.................................. 16 2007.................................. 12 2008.................................. 11 2009.................................. 6 2010 and beyond....................... 26 ------ Total........................... $ 91 ====== Total rental expense for all operating leases was $31 million, $28 million and $30 million in 2002, 2003 and 2004, respectively. (c) LEGAL MATTERS Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought 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 of the Company's 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. The Company believes that there has been no systematic mismeasurement of gas and that the suits are without merit. The Company does not expect that the ultimate outcome will have a material impact on its financial condition or results of operations. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CenterPoint Energy, Entex Gas Marketing Company, and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. Subsequently the plaintiffs added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Gas Transmission Company, United Gas, Inc., Louisiana Unit Gas Transmission Company, CenterPoint Energy Pipeline Services, Inc., and CenterPoint Energy Trading and Transportation Group, Inc. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against the Company with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against the Company seeking to recover alleged overcharges for gas or gas services allegedly provided by Southern Gas 14

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Operations to a purported class of certain consumers of natural gas and gas service without advance approval by the LPSC. In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CenterPoint Energy, Entex Gas Marketing Company, CenterPoint Energy Gas Transmission Company, CenterPoint Energy Field Services, CenterPoint Energy Pipeline Services, Inc., Mississippi River Transmission Corp. and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in at least the states of Arkansas, Louisiana, Mississippi, Oklahoma and Texas. At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish cases have been stayed pending the resolution of the respective proceedings by the LPSC. The plaintiffs in the Miller County case seek class certification, but the proposed class has not been certified. In November 2004, the Miller case was removed to federal district court in Texarkana, Arkansas. In February 2005, the Wharton County case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs in the Wharton County case moved to dismiss the case and agreed not to refile the claims asserted unless the Miller County case is not certified as a class action or is later decertified. The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney's fees. In these cases, the Company, CenterPoint Energy and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. The Company and CenterPoint Energy do not anticipate that the outcome of these matters will have a material impact on the financial condition or results of operations of either the Company or CenterPoint Energy. (d) ENVIRONMENTAL MATTERS Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution. Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The Company believes the ultimate cost associated with resolving this matter will not have a material impact on the financial condition or results of operations of the Company. Manufactured Gas Plant Sites. The Company and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, the Company has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in the Company's Minnesota service territory. The Company believes that it has no liability with respect to two of these sites. At December 31, 2004, the Company had accrued $18 million for remediation of certain Minnesota sites. At December 31, 2004, the estimated range of possible remediation costs for these sites was $7 million to $42 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. As of December 31, 2004, the Company has collected or accrued $13 million from insurance companies and ratepayers to be used for future environmental remediation. 15

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by the Company or may have been owned by one of its former affiliates. The Company has been named as a defendant in lawsuits under which contribution is sought by private parties 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 has also been identified as a PRP by the State of Maine for a site that is the subject of one of the lawsuits. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, the Company believes it is not liable as a former owner or operator of those sites under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting those suits and its designation as a PRP. Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows. Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows. OTHER PROCEEDINGS In 2005, the Company received a communication from a regulatory agency indicating that the agency had ordered a predecessor company to remove certain components from a portion of its distribution system prior to the date the Company acquired it. Those components are not in compliance with current state and federal codes, and it is possible that some of those components remain in the Company's system. The Company has not completed its analysis of the cost to locate and replace such components; however, the Company believes that the disposition of this matter will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company's management regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company's management believes that the disposition of these matters will not have a material adverse effect on the Company's financial condition, results of operations or cash flows. 16

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS 12. REPORTABLE BUSINESS SEGMENTS Because the Company is an indirect wholly owned subsidiary of CenterPoint Energy, the Company's determination of reportable business 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 business 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 business segments. The Company's reportable business segments include the following: Natural Gas Distribution, Pipelines and Gathering and Other Operations. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers and non-rate regulated retail gas marketing operations for commercial and industrial customers. Pipelines and Gathering includes the interstate natural gas pipeline operations and the natural gas gathering and pipeline services businesses. Other Operations consists primarily of other corporate operations which support all of the Company's business operations. Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. The Company accounts for intersegment sales as if the sales were to third parties, that is, at current market prices. 17

CENTERPOINT ENERGY RESOURCES CORP. AND SUBSIDIARIES (AN INDIRECT WHOLLY OWNED SUBSIDIARY OF CENTERPOINT ENERGY, INC.) NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Financial data for business segments and products and services are as follows: NATURAL GAS PIPELINES AND OTHER RECONCILING DISTRIBUTION GATHERING OPERATIONS ELIMINATIONS CONSOLIDATED ------------ ------------- ---------- ------------ ------------ (IN MILLIONS) AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2002: Revenues from external customers and affiliates....................... 3,953 (1) 255 (2) -- -- 4,208 Intersegment revenues.................. 7 119 -- (126) -- Depreciation and amortization.......... 126 41 -- -- 167 Operating income....................... 198 153 2 -- 353 Total assets........................... 4,428 2,500 206 (685) 6,449 Expenditures for long-lived assets..... 196 70 -- -- 266 AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2003: Revenues from external customers and affiliates....................... 5,406 (1) 244 (2) -- -- 5,650 Intersegment revenues.................. 29 163 9 (201) -- Depreciation and amortization.......... 136 40 -- -- 176 Operating income (loss)................ 202 158 (1) -- 359 Total assets........................... 4,661 2,519 388 (715) 6,853 Expenditures for long-lived assets..... 199 66 -- -- 265 AS OF AND FOR THE YEAR ENDED DECEMBER 31, 2004: Revenues from external customers and affiliates....................... 6,681 (1) 306 (2) (4) -- 6,983 Intersegment revenues.................. 3 145 5 (153) -- Depreciation and amortization.......... 143 44 -- -- 187 Operating income (loss)................ 222 180 (9) -- 393 Total assets........................... 4,798 2,637 792 (694) 7,533 Expenditures for long-lived assets..... 197 73 (1) -- 269 - --------------------- (1) Included in the Natural Gas Distribution revenues from external customers and affiliates are sales to RRI, a former affiliate, of $9 million for the year ended December 31, 2002, and sales to Texas Genco, of $26 million, $28 million and $20 million for the years ended December 31, 2002, 2003 and 2004, respectively. (2) Included in the Pipelines and Gathering revenues from external customers and affiliates are sales to RRI, a former affiliate, of $33 million for the year ended December 31, 2002, and sales to Texas Genco of $2 million, $3 million and $2 million for the years ended December 31, 2002, 2003 and 2004, respectively. YEAR ENDED DECEMBER 31, ------------------------------- 2002 2003 2004 --------- --------- --------- (IN MILLIONS) REVENUES BY PRODUCTS AND SERVICES: Retail gas sales.................................... $ 3,857 $ 5,310 $ 6,583 Gas transportation.................................. 255 244 306 Energy products and services........................ 96 96 94 --------- --------- --------- Total............................................. $ 4,208 $ 5,650 $ 6,983 ========= ========= ========= 18