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UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-Q (Mark One) [X] QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 FOR THE QUARTERLY PERIOD ENDED JUNE 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 1-31447 CENTERPOINT ENERGY, INC. (Exact name of registrant as specified in its charter) TEXAS 74-0694415 (State or other jurisdiction of (I.R.S. Employer Identification No.) incorporation or organization) 1111 LOUISIANA HOUSTON, TEXAS 77002 (713) 207-1111 (Address and zip code of principal (Registrant's telephone number, executive offices) including area code) ---------------------------- 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 [X] No [_] As of August 1, 2005, CenterPoint Energy, Inc. had 309,549,770 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC. QUARTERLY REPORT ON FORM 10-Q FOR THE QUARTER ENDED JUNE 30, 2005 TABLE OF CONTENTS PART I. FINANCIAL INFORMATION Item 1. Financial Statements................................................................ 1 Statements of Consolidated Income Three Months and Six Months Ended June 30, 2004 and 2005 (unaudited)............... 1 Consolidated Balance Sheets December 31, 2004 and June 30, 2005 (unaudited).................................... 2 Statements of Consolidated Cash Flows Six Months Ended June 30, 2004 and 2005 (unaudited)................................ 4 Notes to Unaudited Consolidated Financial Statements.................................... 5 Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries................................. 31 Item 3. Quantitative and Qualitative Disclosures about Market Risk.......................... 49 Item 4. Controls and Procedures............................................................. 50 PART II. OTHER INFORMATION Item 1. Legal Proceedings................................................................... 51 Item 4. Submission of Matters to a Vote of Security Holders................................. 51 Item 5. Other Information................................................................... 52 Item 6. Exhibits............................................................................ 58 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: - the timing and amount of our recovery of the true-up components; - state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, 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, 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 cost 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 for our services due to financial distress of our customers, including Reliant Energy, Inc. (formerly named Reliant Resources, Inc.) (RRI); - the outcome of the pending lawsuits against us, Reliant Energy, Incorporated and RRI; ii

- the ability of RRI to satisfy its obligations to us, including indemnity obligations; - our ability to control costs; - the investment performance of our 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 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 52. 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, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED INCOME (THOUSANDS OF DOLLARS, EXCEPT PER SHARE AMOUNTS) (UNAUDITED) THREE MONTHS ENDED SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------------- ---------------------------- 2004 2005 2004 2005 ------------ ------------ ------------ ------------ REVENUES......................................................... $ 1,700,382 $ 1,932,256 $ 4,228,200 $ 4,694,064 ------------ ------------ ------------ ------------ EXPENSES: Natural gas.................................................... 1,010,613 1,192,626 2,772,490 3,140,962 Operation and maintenance...................................... 297,638 324,776 613,480 637,847 Depreciation and amortization.................................. 120,074 135,837 236,292 265,610 Taxes other than income taxes.................................. 86,176 92,705 180,164 187,366 ------------ ------------ ------------ ------------ Total...................................................... 1,514,501 1,745,944 3,802,426 4,231,785 ------------ ------------ ------------ ------------ OPERATING INCOME................................................. 185,881 186,312 425,774 462,279 ------------ ------------ ------------ ------------ OTHER INCOME (EXPENSE): Gain (loss) on Time Warner investment.......................... 15,581 (18,177) (8,872) (59,291) Gain (loss) on indexed debt securities......................... (17,891) 23,819 9,123 63,348 Interest and other finance charges............................. (188,984) (179,652) (371,957) (352,992) Interest on transition bonds................................... (9,547) (9,077) (19,221) (18,297) Return on true-up balance...................................... -- 35,475 -- 69,557 Other, net..................................................... 12,425 6,936 13,932 10,748 ------------ ------------ ------------ ------------ Total...................................................... (188,416) (140,676) (376,995) (286,927) ------------ ------------ ------------ ------------ INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE INCOME TAXES AND EXTRAORDINARY ITEM............................................. (2,535) 45,636 48,779 175,352 Income Tax Expense............................................. (191) (17,931) (22,607) (80,995) ------------ ------------ ------------ ------------ INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE EXTRAORDINARY ITEM........................................................... (2,726) 27,705 26,172 94,357 DISCONTINUED OPERATIONS: Income (Loss) from Texas Genco, net of tax................... 75,636 (2,988) 131,922 10,685 Minority Interest in Income from Texas Genco................. (15,258) -- (26,855) -- Loss on Disposal of Texas Genco, net of tax................. -- (735) -- (13,972) ------------ ------------ ------------ ------------ Total...................................................... 60,378 (3,723) 105,067 (3,287) ------------ ------------ ------------ ------------ INCOME BEFORE EXTRAORDINARY ITEM................................. 57,652 23,982 131,239 91,070 EXTRAORDINARY ITEM, NET OF TAX................................... -- 30,441 -- 30,441 ------------ ------------ ------------ ------------ NET INCOME....................................................... $ 57,652 $ 54,423 $ 131,239 $ 121,511 ============ ============ ============ ============ BASIC EARNINGS PER SHARE: Income (Loss) from Continuing Operations....................... $ (0.01) $ 0.09 $ 0.09 $ 0.30 Discontinued Operations, net of tax............................ 0.20 (0.01) 0.34 (0.01) Extraordinary Item, net of tax................................. -- 0.10 -- 0.10 ------------ ------------ ------------ ------------ Net Income..................................................... $ 0.19 $ 0.18 $ 0.43 $ 0.39 ============ ============ ============ ============ DILUTED EARNINGS PER SHARE: Income (Loss) from Continuing Operations....................... $ (0.01) $ 0.09 $ 0.08 $ 0.28 Discontinued Operations, net of tax............................ 0.20 (0.01) 0.34 (0.01) Extraordinary Item, net of tax................................. -- 0.08 -- 0.08 ------------ ------------ ------------ ------------ Net Income..................................................... $ 0.19 $ 0.16 $ 0.42 $ 0.35 ============ ============ ============ ============ See Notes to the Company's Interim Financial Statements 1

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (THOUSANDS OF DOLLARS) (UNAUDITED) ASSETS DECEMBER 31, JUNE 30, 2004 2005 -------------- -------------- CURRENT ASSETS: Cash and cash equivalents................................................ $ 164,645 $ 408,162 Investment in Time Warner common stock................................... 420,882 361,590 Accounts receivable, net................................................. 741,715 511,846 Accrued unbilled revenues................................................ 576,252 271,779 Natural gas inventory.................................................... 174,232 167,514 Materials and supplies................................................... 77,902 77,674 Non-trading derivative assets............................................ 50,219 67,638 Taxes receivable......................................................... -- 6,368 Current assets of discontinued operations................................ 513,768 -- Prepaid expenses and other current assets................................ 116,909 112,226 -------------- -------------- Total current assets................................................... 2,836,524 1,984,797 -------------- -------------- PROPERTY, PLANT AND EQUIPMENT: Property, plant and equipment............................................ 10,963,569 11,182,282 Less accumulated depreciation and amortization........................... (2,777,176) (2,908,991) -------------- -------------- Property, plant and equipment, net..................................... 8,186,393 8,273,291 -------------- -------------- OTHER ASSETS: Goodwill, net............................................................ 1,740,510 1,744,252 Other intangibles, net................................................... 58,068 57,062 Regulatory assets........................................................ 3,349,944 2,928,968 Non-trading derivative assets............................................ 17,682 56,349 Non-current assets of discontinued operations............................ 1,051,158 -- Other.................................................................... 921,678 844,972 -------------- -------------- Total other assets..................................................... 7,139,040 5,631,603 -------------- -------------- TOTAL ASSETS......................................................... $ 18,161,957 $ 15,889,691 ============== ============== See Notes to the Company's Interim Financial Statements 2

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS - (CONTINUED) (THOUSANDS OF DOLLARS) (UNAUDITED) LIABILITIES AND SHAREHOLDERS' EQUITY DECEMBER 31, JUNE 30, 2004 2005 -------------- -------------- CURRENT LIABILITIES: Current portion of transition bond long-term debt....................... $ 46,806 $ 49,352 Current portion of other long-term debt................................. 1,789,182 1,748,083 Indexed debt securities derivative...................................... 341,575 278,227 Accounts payable........................................................ 868,023 546,262 Taxes accrued........................................................... 609,025 117,313 Interest accrued........................................................ 151,365 158,282 Non-trading derivative liabilities...................................... 26,323 13,124 Regulatory liabilities.................................................. 225,158 -- Accumulated deferred income taxes, net.................................. 260,958 286,357 Current liabilities of discontinued operations.......................... 448,974 -- Other................................................................... 419,811 440,659 -------------- -------------- Total current liabilities............................................. 5,187,200 3,637,659 -------------- -------------- OTHER LIABILITIES: Accumulated deferred income taxes, net.................................. 2,415,143 2,472,727 Unamortized investment tax credits...................................... 53,690 49,937 Non-trading derivative liabilities...................................... 6,413 5,873 Benefit obligations..................................................... 440,110 451,562 Regulatory liabilities.................................................. 1,081,370 744,260 Non-current liabilities of discontinued operations...................... 420,393 -- Other................................................................... 259,120 295,637 -------------- -------------- Total other liabilities............................................... 4,676,239 4,019,996 -------------- -------------- LONG-TERM DEBT: Transition bonds........................................................ 628,903 610,462 Other................................................................... 6,564,113 6,440,756 -------------- -------------- Total long-term debt.................................................. 7,193,016 7,051,218 -------------- -------------- COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 11) SHAREHOLDERS' EQUITY: Common stock (308,045,215 shares and 309,396,223 shares outstanding at December 31, 2004 and June 30, 2005, respectively)................. 3,080 3,094 Additional paid-in capital.............................................. 2,891,335 2,907,227 Retained deficit........................................................ (1,727,571) (1,689,435) Accumulated other comprehensive loss.................................... (61,342) (40,068) -------------- -------------- Total shareholders' equity............................................ 1,105,502 1,180,818 -------------- -------------- TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY.......................... $ 18,161,957 $ 15,889,691 ============== ============== See Notes to the Company's Interim Financial Statements 3

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES STATEMENTS OF CONSOLIDATED CASH FLOWS (THOUSANDS OF DOLLARS) (UNAUDITED) SIX MONTHS ENDED JUNE 30, ----------------------------------- 2004 2005 ------------- -------------- CASH FLOWS FROM OPERATING ACTIVITIES: Net income.............................................................. $ 131,239 $ 121,511 Discontinued operations, net of tax..................................... (105,067) 3,287 Extraordinary item, net of tax.......................................... -- (30,441) ------------- -------------- Income from continuing operations....................................... 26,172 94,357 Adjustments to reconcile income from continuing operations to net cash provided by operating activities: Depreciation and amortization......................................... 236,292 265,610 Amortization of deferred financing costs.............................. 43,665 39,521 Deferred income taxes................................................. 56,696 48,074 Investment tax credit................................................. (3,753) (3,753) Unrealized loss on Time Warner investment............................. 8,872 59,291 Unrealized gain on indexed debt securities............................ (9,123) (63,348) Changes in other assets and liabilities: Accounts receivable and unbilled revenues, net...................... 314,086 575,509 Inventory........................................................... 33,212 9,044 Taxes receivable.................................................... 48,304 (6,368) Accounts payable.................................................... (121,283) (321,474) Fuel cost over (under) recovery/surcharge........................... 53,376 (47,220) Non-trading derivatives, net........................................ (9,847) 1,252 Interest and taxes accrued.......................................... (40,026) (424,590) Excess tax deduction related to share-based payment arrangements.... -- (1,447) Net regulatory assets and liabilities............................... (157,728) (132,876) Other current assets................................................ 4,547 (3,045) Other current liabilities........................................... (14,867) (8,426) Other assets........................................................ (8,540) 1,753 Other liabilities................................................... (5,463) 18,117 Other, net............................................................ 21,045 6,166 ------------- -------------- Net cash provided by operating activities......................... 475,637 106,147 ------------- -------------- CASH FLOWS FROM INVESTING ACTIVITIES: Capital expenditures.................................................... (209,769) (301,345) Proceeds from sale of Texas Genco....................................... -- 700,000 Dividends received from Texas Genco..................................... 32,382 -- Other, net.............................................................. (10,566) (1,106) ------------- -------------- Net cash provided by (used in) investing activities............... (187,953) 397,549 ------------- -------------- CASH FLOWS FROM FINANCING ACTIVITIES: Decrease in short-term borrowings, net.................................. (63,000) -- Long-term revolving credit facilities, net.............................. 137,500 (119,000) Proceeds from long-term debt............................................ 229,050 -- Payments of long-term debt.............................................. (513,927) (61,303) Debt issuance costs..................................................... (13,388) (6,177) Payment of common stock dividends....................................... (61,366) (83,338) Proceeds from issuance of common stock, net............................. 6,879 8,192 Excess tax deduction related to share-based payment arrangements........ -- 1,447 Other, net.............................................................. (2) -- ------------- -------------- Net cash used in financing activities............................... (278,254) (260,179) ------------- -------------- CASH FLOWS FROM DISCONTINUED OPERATIONS: Cash provided by (used in) operating activities......................... 77,741 (66,012) Cash provided by (used in) investing activities......................... (37,625) 374,198 Cash used in financing activities....................................... (40,116) (308,186) ------------- -------------- Net cash provided by discontinued operations........................ -- -- ------------- -------------- NET INCREASE IN CASH AND CASH EQUIVALENTS................................. 9,430 243,517 CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD.......................... 86,922 164,645 ------------- -------------- CASH AND CASH EQUIVALENTS AT END OF PERIOD................................ $ 96,352 $ 408,162 ============== ============== SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: Cash Payments: Interest................................................................ $ 365,799 $ 328,817 Income taxes............................................................ 34,159 457,008 See Notes to the Company's Interim Financial Statements 4

CENTERPOINT ENERGY, INC. 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, Inc. are the consolidated interim financial statements and notes (Interim Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, 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 CenterPoint Energy for the year ended December 31, 2004 (CenterPoint Energy Form 10-K). Background. CenterPoint Energy, Inc. is 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 (Texas electric restructuring law). 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 the Company and those of its subsidiaries. The 1935 Act, among other things, limits the ability of the Company and its subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. On July 29, 2005, Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush is expected to sign in early August. Under that legislation, the 1935 Act is repealed six months after the enactment of the Energy Act. After the effective date of repeal, the Company and its subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, the Company 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 transfers to the Federal Energy Regulatory Commission (FERC) certain functions performed by the SEC under the 1935 Act, including the requirement that holding companies and their subsidiaries maintain certain books and records and make them available for review by FERC and, through FERC, to state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act. It is presently unknown what, if any, specific obligations under those rules may be imposed on the Company and its subsidiaries as result of that rulemaking. The Company's operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of June 30, 2005, the Company's indirect wholly owned subsidiaries included: - CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and - CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns gas distribution systems. The operations of its local distribution companies are conducted through three unincorporated divisions: Houston Gas, Minnesota Gas and Southern Gas Operations. Through wholly owned subsidiaries, CERC 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. On April 13, 2005, the Company sold Texas Genco Holdings, Inc. (Texas Genco), whose primary remaining asset was its ownership interest in a nuclear generating facility, to Texas Genco LLC in exchange for a cash payment to the Company of $700 million. See Note 2 for further discussion. 5

Basis of Presentation. The preparation of financial statements in conformity with accounting principles generally accepted 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 and results of operations for the respective periods. Amounts reported in the Company's Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests. In addition, certain amounts from the prior year have been reclassified to conform to the Company's presentation of financial statements in the current year. These reclassifications do not affect net income. Note 2(d) (Long-Lived Assets and Intangibles), Note 2(e) (Regulatory Assets and Liabilities), Note 4 (Regulatory Matters), Note 5 (Derivative Instruments), Note 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and Note 11 (Commitments and Contingencies) to the consolidated annual financial statements in the CenterPoint Energy Form 10-K (CenterPoint Energy Notes) relate to certain contingencies. These notes, as updated herein, are incorporated herein by reference. For information regarding certain legal and regulatory proceedings and environmental matters, see Note 11 to the Interim Financial Statements. (2) DISCONTINUED OPERATIONS In July 2004, the Company announced its agreement to sell its majority-owned generating subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco distributed $2.231 billion in cash to the Company. Following that sale, Texas Genco's principal remaining asset was its ownership interest in a nuclear generating facility. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to the Company of $700 million, was completed on April 13, 2005. The Company recorded after-tax income of $60 million and $105 million for the three and six months ended June 30, 2004, respectively, related to the operations of Texas Genco. The Company recorded an after-tax loss of $3 million for each of the three and six month periods ended June 30, 2005. General corporate overhead, previously allocated to Texas Genco from the Company, was $5 million and $10 million for the three and six months ended June 30, 2004, respectively, and was less than $1 million for each of the three and six month periods ended June 30, 2005. These amounts will not be eliminated by the sale of Texas Genco and were excluded from income from discontinued operations and reflected as general corporate overhead of the Company in income from continuing operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). The Interim Financial Statements present these operations as discontinued operations in accordance with SFAS No. 144. Interest expense of $12 million and $24 million for the three and six months ended June 30, 2004, respectively, was reclassified to discontinued operations of Texas Genco related to the applicable amounts of CenterPoint Energy's term loan and revolving credit facility debt that would have been assumed to be paid off with any proceeds from the sale of Texas Genco during those respective periods in accordance with SFAS No. 144. Revenues related to Texas Genco included in discontinued operations for the three and six months ended June 30, 2004 were $553 million and $992 million, respectively. Revenues for the three and six months ended June 30, 2005 were $5 million and $62 million, respectively. Income from these discontinued operations for the three and six months ended June 30, 2004 is reported net of income tax expense of $41 million and $71 million, respectively. Income from these discontinued operations for the three and six months ended June 30, 2005 is reported net of income tax expense (benefit) of $(2) million and $4 million, respectively. 6

(3) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS (a) Stock-Based Incentive Compensation Plans. The Company has long-term incentive compensation plans (LICPs) that provide for the issuance of stock-based incentives, including performance-based shares, performance-based units, restricted shares and stock options to directors, officers and key employees. A maximum of approximately 37 million shares of CenterPoint Energy common stock are authorized to be issued under these plans. Performance-based shares, performance-based units and restricted shares are granted to employees without cost to the participants. The performance shares and units vest three years after the grant date based upon the performance of the Company over a three-year cycle. The restricted shares vest at various times ranging from one-year to the end of a three-year period. Upon vesting, the shares are issued to the plan participants. Option awards are generally granted with an exercise price equal to the average of the high and low sales price of the Company's stock at the date of grant. These options awards generally become exercisable in one-third increments on each of the first through third anniversaries of the grant date and have 10-year contractual terms. No options were granted during the three and six months ended June 30, 2005. Effective January 1, 2005, the Company adopted SFAS No. 123 (Revised 2004), "Share-Based Payment" (SFAS 123(R)) using the modified prospective transition method. Under this method, the Company records compensation expense at fair value for all awards it grants after the date it adopts the standard. In addition, the Company is required to record compensation expense at fair value (as previous awards continue to vest) for the unvested portion of previously granted stock option awards that were outstanding as of the date of adoption. Pre-adoption awards of time-based restricted stock and performance-based restricted stock will continue to be expensed using the guidance contained in Accounting Principles Board Opinion No. 25. The adoption of SFAS 123(R) did not have a material impact on the Company's results of operations, financial condition or cash flows. The Company recorded LICP compensation expense of $2 million and $4 million for the three and six months ended June 30, 2004, respectively. LICP compensation expense for the three and six months ended June 30, 2005 was $2 million and $6 million, respectively. The total income tax benefit recognized related to such arrangements was $1 million and $2 million for the three and six months ended June 30, 2004, respectively. Income tax benefit for the three and six months ended June 30, 2005 was $1 million and $2 million, respectively. No compensation cost was capitalized as a part of inventory and fixed assets in either of the three or six month periods ended June 30, 2004 and 2005. Pro forma information for the three and six months ended June 30, 2004 is provided to take into account the amortization of stock-based compensation to expense on a straight-line basis over the vesting period. Had compensation costs been determined as prescribed by SFAS No. 123(R), the Company's net income and earnings per share would have been as follows (in millions, except per share amounts): THREE MONTHS SIX MONTHS ENDED ENDED JUNE 30, 2004 JUNE 30, 2004 ------------- ------------- Net Income: As reported.............................................. $ 58 $ 131 Total stock-based employee compensation determined under the fair value based method............................ -- (2) -------- -------- Pro forma................................................ $ 58 $ 129 ======== ======== Basic Earnings Per Share: As reported.............................................. $ 0.19 $ 0.43 Pro forma................................................ 0.19 0.42 Diluted Earnings Per Share: As reported.............................................. 0.19 0.42 Pro forma................................................ 0.19 0.42 7

The following tables summarize the methods used to measure compensation cost for the various types of awards granted under the LICPs: FOR AWARDS GRANTED BEFORE JANUARY 1, 2005 AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - --------------------------- ---------------------------------------------------------------------------- Performance shares Initially measured using fair value and expected achievement levels on the date of grant. Compensation cost is then periodically adjusted to reflect changes in market prices and achievement through the settlement date. Performance units Initially measured using the award's target unit value of $100 that reflects expected achievement levels on the date on grant. Compensation cost is then periodically adjusted to reflect changes in achievement through the settlement date. Time-based restricted stock Measured using fair value on the grant date. Stock options Estimated using the Black-Scholes option valuation method. FOR AWARDS GRANTED AS OF AND AFTER JANUARY 1, 2005 AWARD TYPE METHOD USED TO DETERMINE COMPENSATION COST - --------------------------- ---------------------------------------------------------------------------- Performance shares Measured using fair value and expected achievement levels on the grant date. Time-based restricted stock Measured using fair value on the grant date. For awards granted before January 1, 2005, forfeitures of awards were measured upon their occurrence. For awards granted as of and after January 1, 2005, forfeitures are estimated on the date of grant and are adjusted as required through the remaining vesting period. The following tables summarize the Company's LICP activity for the three and six months ended June 30, 2005: STOCK OPTIONS OUTSTANDING OPTIONS THREE MONTHS ENDED JUNE 30, 2005 -------------------------------- WEIGHTED- AVERAGE SHARES EXERCISE (THOUSANDS) PRICE ----------- ----- Outstanding at March 31, 2005 .................. 15,693 $ 15.62 Canceled ..................................... (509) 16.28 Exercised .................................... (296) 6.33 ----------- Outstanding at June 30, 2005 ................... 14,888 15.78 =========== NON-VESTED OPTIONS THREE MONTHS ENDED JUNE 30, 2005 -------------------------------- WEIGHTED- AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------- Outstanding at March 31, 2005.............. 4,032 $ 1.76 Vested................................... -- -- Canceled................................. -- -- ----------- Outstanding at June 30, 2005............... 4,032 1.76 =========== 8

OUTSTANDING OPTIONS SIX MONTHS ENDED JUNE 30, 2005 ----------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC SHARES EXERCISE LIFE VALUE (THOUSANDS) PRICE (YEARS) (MILLIONS) ----------- --------- ----------- ---------- Outstanding at December 31, 2004 ....... 16,159 $ 15.42 Canceled ............................. (663) 15.74 Exercised ............................ (608) 6.35 ------ Outstanding at June 30, 2005 ........... 14,888 15.78 4.6 $ 30 ====== Exercisable at June 30, 2005 ........... 12,931 16.78 4.0 22 ====== NON-VESTED OPTIONS SIX MONTHS ENDED JUNE 30, 2005 ------------------------------ WEIGHTED- AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------- Outstanding at December 31, 2004 ................. 6,854 $ 1.61 Vested ......................................... (2,770) 1.40 Canceled ....................................... (52) 1.90 ------ Outstanding at June 30, 2005 ..................... 4,032 1.76 ====== PERFORMANCE SHARES OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED JUNE 30, 2005 --------------------------------- WEIGHTED- AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------- Outstanding at March 31, 2005 ...................... 1,594 $ 9.25 Granted .......................................... -- -- Canceled ......................................... (5) 5.64 Vested and released to participants .............. (2) 5.64 ----- Outstanding at June 30, 2005 ....................... 1,587 9.27 ===== OUTSTANDING SHARES SIX MONTHS ENDED JUNE 30, 2005 ----------------------------------------------- REMAINING AVERAGE AGGREGATE CONTRACTUAL INTRINSIC SHARES LIFE VALUE (THOUSANDS) (YEARS) (MILLIONS) ----------- ----------- ---------- Outstanding at December 31, 2004 ............. 1,169 Granted .................................... 945 Canceled ................................... (154) Vested and released to participants ........ (373) ----- Outstanding at June 30, 2005 ................. 1,587 1.6 $ 16 ===== NON-VESTED SHARES SIX MONTHS ENDED JUNE 30, 2005 ------------------------------ WEIGHTED- AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------- Outstanding at December 31, 2004 .................. 756 $ 5.70 Granted ......................................... 945 12.13 Canceled ........................................ (94) 10.19 Vested and released to participants ............. (20) 5.64 ----- Outstanding at June 30, 2005 ...................... 1,587 9.27 ===== The non-vested and outstanding shares displayed in the above tables assume that shares are issued at the maximum performance level (150%). In addition, the aggregate intrinsic value reflects the impacts of current expectations of achievement and stock price. 9

PERFORMANCE-BASED UNITS OUTSTANDING AND NON-VESTED UNITS THREE MONTHS ENDED JUNE 30, 2005 --------------------------------- WEIGHTED- AVERAGE UNITS GRANT DATE (THOUSANDS) FAIR VALUE ----------- ---------- Outstanding at March 31, 2005 ................ 35 $ 100.00 Canceled .................................. -- -- Vested and released to participants ....... -- -- ----- Outstanding at June 30, 2005 ................. 35 100.00 ===== OUTSTANDING AND NON-VESTED UNITS SIX MONTHS ENDED JUNE 30, 2005 --------------------------------------------------------------- REMAINING WEIGHTED- AVERAGE AGGREGATE AVERAGE CONTRACTUAL INTRINSIC UNITS GRANT DATE LIFE VALUE (THOUSANDS) FAIR VALUE (YEARS) (MILLIONS) ----------- ---------- ------------ ---------- Outstanding at December 31, 2004 ............. 37 $ 100.00 Canceled .................................. (1) 100.00 Vested and released to participants ....... (1) 100.00 ----- Outstanding at June 30, 2005 ................. 35 100.00 1.5 $ 3 ===== The aggregate intrinsic value reflects the value of the performance units given current expectations of performance through the end of the cycle. TIME-BASED RESTRICTED STOCK OUTSTANDING AND NON-VESTED SHARES THREE MONTHS ENDED JUNE 30, 2005 --------------------------------- WEIGHTED- AVERAGE SHARES GRANT DATE (THOUSANDS) FAIR VALUE ----------- ----------- Outstanding at March 31, 2005 ................ 986 $ 8.71 Granted ................................... -- -- Canceled .................................. (3) 7.01 Vested and released to participants ....... (9) 7.60 ------- Outstanding at June 30, 2005 ................. 974 8.72 ======= OUTSTANDING AND NON-VESTED SHARES SIX MONTHS ENDED JUNE 30, 2005 ---------------------------------------------------------- WEIGHTED- REMAINING AVERAGE AVERAGE AGGREGATE GRANT CONTRACTUAL INTRINSIC SHARES DATE LIFE VALUE (THOUSANDS) FAIR VALUE (YEARS) (MILLIONS) ------------ ----------- ----------- ---------- Outstanding at December 31, 2004 ............. 769 $ 7.49 Granted ................................... 277 12.13 Canceled .................................. (43) 9.75 Vested and released to participants ....... (29) 6.92 ------- Outstanding at June 30, 2005 ................. 974 8.72 1.4 $ 13 ======= The weighted-average grant-date fair values of awards granted were as follows for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, --------------------------- 2004 2005 --------- ------- Options ........................... $ -- $ -- Performance units ................. 100.00 -- Performance shares ................ -- -- Time-based restricted stock ....... 11.29 -- 10

SIX MONTHS ENDED JUNE 30, ------------------------- 2004 2005 ---- ---- Options............................................. $ 1.86 $ -- Performance units................................... 100.00 -- Performance shares.................................. -- 12.13 Time-based restricted stock......................... 10.91 12.13 The total intrinsic value of awards received by participants were as follows for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, --------------------------- 2004 2005 ---- ---- (IN MILLIONS) Options exercised................................... $ 1 $ 2 SIX MONTHS ENDED JUNE 30, --------------------------- 2004 2005 ---- ---- (IN MILLIONS) Options exercised.................................... $ 2 $ 4 Performance shares................................... 7 5 As of June 30, 2005, there was $17 million of total unrecognized compensation cost related to non-vested LICP arrangements. That cost is expected to be recognized over a weighted-average period of 2 years. Cash received from LICPs was less than $1 million and $2 million for the three and six months ended June 30, 2004, respectively. Cash received from LICPs was $2 million and $4 million for the three and six months ended June 30, 2005, respectively. The actual tax benefit realized for tax deductions related to LICPs totaled $1 million and $4 million for the three and six months ended June 30, 2004, respectively. Tax benefits realized for the three and six months ended June 30, 2005 was $1 million and $4 million, respectively. The Company has a policy of issuing new shares in order to satisfy share-based payments related to LICPs. For further information, please read Note 9 to the CenterPoint Energy Form 10-K. 11

(b) Employee Benefit Plans. The Company's net periodic cost includes the following components relating to pension and postretirement benefits: THREE MONTHS ENDED JUNE 30, -------------------------------------------------------- 2004 2005 -------------------------- -------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) Service cost...................... $ 10 $ 1 $ 8 $ -- Interest cost..................... 25 8 25 7 Expected return on plan assets.... (26) (3) (35) (3) Net amortization.................. 10 3 9 3 Other............................. 3 -- -- -- -------- -------------- -------- ------------ Net periodic cost................. $ 22 $ 9 $ 7 $ 7 ======== ============== ======== ============ SIX MONTHS ENDED JUNE 30, -------------------------------------------------------- 2004 2005 -------------------------- -------------------------- PENSION POSTRETIREMENT PENSION POSTRETIREMENT BENEFITS BENEFITS BENEFITS BENEFITS -------- -------------- -------- -------------- (IN MILLIONS) Service cost...................... $ 20 $ 2 $ 17 $ 1 Interest cost..................... 51 16 48 14 Expected return on plan assets.... (52) (6) (69) (6) Net amortization.................. 19 6 19 5 Other............................. 3 2 -- -- -------- -------------- -------- ------------ Net periodic cost................. $ 41 $ 20 $ 15 $ 14 ======== ============== ======== ============ Included in the net periodic cost for the three and six months ended June 30, 2004 is $4 million and $8 million, respectively, of expense related to Texas Genco's participants, which is reflected in discontinued operations in the Statements of Consolidated Income. Contributions to the pension plan are not required in 2005; however, the Company expects to make a contribution. The Company previously disclosed in its consolidated financial statements for the year ended December 31, 2004, that it expected to contribute $29 million to its postretirement benefits plan in 2005. As of June 30, 2005, $11 million of contributions have been made. In addition to the Company's non-contributory pension plan, the Company maintains a non-qualified benefit restoration plan. The net periodic cost associated with this plan for the three months ended June 30, 2004 and 2005 was $1 million and $2 million, respectively, and $3 million for each of the six months ended June 30, 2004 and 2005. (4) NEW ACCOUNTING PRONOUNCEMENTS In May 2005, the Financial Accounting Standards Board (FASB) issued 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 does not expect the adoption of this standard to have a material effect on its financial position, results of operations or cash flows. (5) REGULATORY MATTERS (a) Recovery of True-Up Balance. The Texas electric restructuring law provides for the Public Utility Commission of Texas (Texas Utility Commission) to conduct a "true-up" proceeding to determine CenterPoint Houston's stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its stranded cost true-up application with the Texas Utility Commission. CenterPoint Houston had requested recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. Both CenterPoint Houston and other parties filed appeals of the True-Up Order, and those appeals remain pending before a state district court in Travis County, Texas. The court held a hearing on the appeal in early August 2005, with a decision currently expected in the near future. There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). In March 2005, the 12

Texas Utility Commission issued a financing order that authorized the issuance of transition bonds. Although several parties originally appealed the financing order, only two have maintained appeals. CenterPoint Houston will not be able to issue transition bonds while an appeal is pending. Prior to the appeal, it had been expected that approximately $1.8 billion in transition bonds could be issued by mid-2005 under the terms of the financing order. On August 4, 2005, the District Court affirmed the financing order. Texas law provides for any further appeals to be filed directly with the Texas Supreme Court within 15 days. On July 14, 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC to collect approximately $570 million over 14 years plus interest at an annual rate of 11.075%. Based on the accrual of interest provided for in the CTC order, CenterPoint Houston expects that this amount will increase to approximately $600 million by the end of the third quarter which is when the CTC is expected to be implemented. The CTC order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years. The CTC order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. CenterPoint Houston cannot implement the CTC until the Texas Utility Commission takes final action on the motions for rehearing. Under the True-Up Order, CenterPoint Houston is allowed a return until the true-up balance is recovered. The rate of return is based on CenterPoint Houston's cost of capital, established in the Texas Utility Commission's final order issued in October 2001, which is derived from CenterPoint Houston's cost to finance assets (debt return) and an allowance for earnings on shareholders' investment (equity return). Consequently, in accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans," the rate of return has been bifurcated into a debt return component and an equity return component. CenterPoint Houston was allowed a return on the true-up balance of $65 million and $127 million for the three months and six months ended June 30, 2005, respectively. The debt return of $35 million and $69 million for the three months and six months ended June 30, 2005, respectively, was accrued and included in other income in the Company's Statements of Consolidated Income. The debt return will continue to be recognized as earned going forward. The equity return of $30 million and $58 million for the three months and six months ended June 30, 2005, respectively, will be recognized in income as it is collected through rates in the future. As of June 30, 2005, the Company has recorded a regulatory asset of $296 million related to the debt return on its true-up balance and has not recorded an allowed equity return of $205 million on its true-up balance because such return will be recognized as it is collected through rates in the future. Net income for both the three months and six months ended June 30, 2005 included an after-tax extraordinary gain of $30 million ($0.08 per diluted share) reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission. As a result of a settlement reached in a separate proceeding involving Reliant Energy, Inc.'s (RRI) Price-to-Beat, excess mitigation credits were terminated as of April 29, 2005. As a result of this settlement, the Company has applied the remaining unrefunded excess mitigation credits of approximately $522 million to reduce the regulatory asset related to stranded costs as of June 30, 2005. (b) Final Fuel Reconciliation. The results of the Texas Utility Commission's final decision related to CenterPoint Houston's final fuel reconciliation are a component of the True-Up Order. CenterPoint Houston has appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation plus interest of $10 million. A hearing on this issue was held before a district court in Travis County on April 22, 2005 and a judgment was entered from the district court on May 13, 2005 affirming the Texas Utility Commission's decision. CenterPoint Houston filed an appeal to the Court of Appeals on June 9, 2005. (c) Rate Cases. In November 2004, Southern Gas Operations filed an application for a general rate increase with the Arkansas Public Service Commission (APSC). Southern Gas Operations' adjusted request, if approved, would increase base rates by approximately $28 million annually. The APSC staff has made a recommendation to the APSC for a rate decrease of $13 million. Hearings in the rate case are scheduled to begin in early August 2005 with billings under new rates expected to begin in the fourth quarter. 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 13

environs of its Beaumont/East Texas and South Texas Divisions. In June 2005, Southern Gas Operations filed a request to implement these rates within substantially all of the incorporated cities located in its Beaumont/East Texas and South Texas Divisions. If these rates are approved 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. A liability has been recorded for the excess of amounts collected in interim rates over those approved in the final settlement, which excess will be refunded to customers in the third quarter. (d) 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 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. An appeal from this order could be taken by the City of Tyler to the Court of Appeals and ultimately to the Texas Supreme Court, but no appeal has been filed to date. (e) City of Houston Franchise. On June 27, 2005, CenterPoint Houston accepted an ordinance granting CenterPoint Houston a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the Additional Amount will be adjusted annually based on the annual increase or decrease in kWh delivered by CenterPoint Houston within the City of Houston. The New Franchise Ordinance requires the City of Houston to modify CenterPoint Houston's tariff to allow CenterPoint Houston to recover the Additional Amount from retail electric providers serving end-use retail electric customers within the City of Houston boundaries. CenterPoint Houston filed a request with the City of Houston to implement a tariff rider to collect the Additional Amount, but subsequently asked the City of Houston to abate further consideration of that application pending a review by counsel for the City of Houston and CenterPoint Houston regarding the implementation of the New Franchise Ordinance. CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, CenterPoint Houston retains the right to recover from the City of Houston any portion of the Additional Amount paid (or to refuse to pay any portion not yet paid) for which CenterPoint Houston is denied recovery by any regulatory authority. Additionally, the New Franchise Ordinance provides that the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case. 14

(f) 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 its sister pipeline, 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. (6) 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 six months ended June 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 June 30, 2005, the Company expects $12 million in accumulated other comprehensive income 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. 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 aggregate Value at Risk (VaR) associated with these operations is calculated daily and averaged $0.3 million with a high of $1 million during the first six months of 2005. 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 six months ended June 30, 2004 and 2005, the Company recognized net gains (losses) related to unhedged positions amounting to $(2) million and $6 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 June 30, 2005, the Company had recorded short-term risk management assets and liabilities of $3 million and $3 million, respectively, included in other current assets and other current liabilities, respectively. Interest Rate Swaps. During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive loss and is 15

being amortized into interest expense over the life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive loss for the six months ended June 30, 2004 and 2005, was $13 million and $15 million, respectively. Embedded Derivative. The Company's $575 million of convertible senior notes, issued May 19, 2003 and $255 million of convertible senior notes, issued December 17, 2003, contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the balance sheet. The value of the contingent interest components was not material at issuance or at June 30, 2005. (7) GOODWILL AND INTANGIBLES Goodwill by reportable business segment is as follows (in millions): DECEMBER 31, JUNE 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 completed its annual evaluation of goodwill for impairment as of January 1, 2005 and no impairment was indicated. The components of the Company's other intangible assets consist of the following: DECEMBER 31, 2004 JUNE 30, 2005 --------------------------- -------------------------- CARRYING ACCUMULATED CARRYING ACCUMULATED AMOUNT AMORTIZATION AMOUNT AMORTIZATION --------- ------------ -------- ------------ (IN MILLIONS) Land use rights.................................... $ 55 $ (12) $ 55 $ (13) Other.............................................. 21 (6) 21 (6) --------- ---------- -------- ---------- Total.......................................... $ 76 $ (18) $ 76 $ (19) ========= ========== ======== ========== 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 June 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 40 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 June 30, 2004 and 2005 was $0.6 million and for both the six months ended June 30, 2004 and 2005 was $1.2 million. Estimated amortization expense for the remainder of 2005 and the five succeeding fiscal years is as follows (in millions): 2005........................................ $ 1 2006........................................ 3 2007........................................ 3 2008........................................ 3 2009........................................ 3 2010........................................ 2 ------- Total..................................... $ 15 ======= 16

(8) COMPREHENSIVE INCOME The following table summarizes the components of total comprehensive income (net of tax): FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED JUNE 30, JUNE 30, -------------------------- ------------------------- 2004 2005 2004 2005 ------- --------- ------- --------- (IN MILLIONS) Net income........................................... $ 57 $ 54 $ 131 $ 121 ------- ------- ------- --------- Other comprehensive income: Net deferred gain from cash flow hedges............ 8 1 16 10 Reclassification of deferred loss (gain) from cash flow hedges realized in net income............... (1) 2 1 8 Other comprehensive income from discontinued operations....................................... -- 4 -- 4 ------- ------- ------- --------- Other comprehensive income........................... 7 7 17 22 ------- ------- ------- --------- Comprehensive income ................................ $ 64 $ 61 $ 148 $ 143 ======= ======= ======= ========= The following table summarizes the components of accumulated other comprehensive loss: DECEMBER 31, JUNE 30, 2004 2005 ------------ -------- (IN MILLIONS) Minimum pension liability adjustment............................................... $ (6) $ (6) Net deferred loss from cash flow hedges............................................ (52) (34) Other comprehensive loss from discontinued operations.............................. (3) -- ------------ -------- Total accumulated other comprehensive loss ........................................ $ (61) $ (40) ============ ======== (9) CAPITAL STOCK CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2004, 308,045,381 shares of CenterPoint Energy common stock were issued and 308,045,215 shares of CenterPoint Energy common stock were outstanding. At June 30, 2005, 309,396,389 shares of CenterPoint Energy common stock were issued and 309,396,223 shares of CenterPoint Energy common stock were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2004 and June 30, 2005. CenterPoint Energy declared a dividend of $0.10 per share in each of the first and second quarters of 2004. On January 26, 2005, the Company's board of directors declared a dividend of $0.10 per share of common stock payable on March 10, 2005 to shareholders of record as of the close of business on February 16, 2005. On March 3, 2005, the Company's board of directors declared a dividend of $0.10 per share of common stock payable on March 31, 2005 to shareholders of record as of the close of business on March 16, 2005. This additional first quarter dividend was declared in lieu of the regular second quarter dividend to address technical restrictions that might limit the Company's ability to pay a regular dividend during the second quarter of this year. Due to the limitations imposed under the 1935 Act, the Company may declare and pay dividends only from earnings in the specific quarter in which the dividend is paid, absent specific authorization from the SEC approving payment of the quarterly dividend from capital or unearned surplus. There can be no assurance, however, that the SEC would authorize such payments. As a result of the seasonal nature of the Company's utility businesses, the first quarter is generally the strongest quarter for the Company's gas distribution business. On June 2, 2005, the Company's board of directors declared a dividend of $0.07 per share of common stock payable on June 30, 2005 to shareholders of record as of the close of business on June 15, 2005. Although dividends are subject to consideration and approval of the Company's Board of Directors, subject to the Board's determination, the Company currently intends to pay a 2005 annual dividend of $0.40 per share in keeping with the Company's historic levels and subject to remaining in compliance with the dividend payment limitations imposed under the 1935 Act. 17

(10) LONG-TERM DEBT AND RECEIVABLES FACILITY (a) Long-term Debt. In June 2005, CERC Corp. 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 June 30, 2005, such credit facility was not utilized. In March 2005, the Company replaced its $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 100 basis points based on current credit ratings. An additional utilization fee of 12.5 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 June 30, 2005, borrowings of $120 million were outstanding under the revolving credit facility. In March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit rating. An additional utilization fee of 12.5 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 June 30, 2005, there were no borrowings outstanding under the revolving credit facility. CenterPoint Houston also established a $1.31 billion credit facility in March 2005. This facility is available to be utilized only to refinance CenterPoint Houston's $1.31 billion term loan maturing in November 2005 in the event that proceeds from the issuance of transition bonds are not sufficient to repay such term loan. Drawings may be made under this credit facility until November 2005, at which time any outstanding borrowings are converted to term loans maturing in November 2007. Under this facility, (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be used to repay borrowings under the facility. Based on CenterPoint Houston's current credit ratings, borrowings under the facility may be made at LIBOR plus 75 basis points. The interest rate under the term loan which this facility would replace is LIBOR plus 975 basis points. Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. Any drawings under this facility must be secured by CenterPoint Houston's general mortgage bonds in the same principal amount and bearing the same interest rate as such drawings. Convertible Debt. In March 2005, the Company filed a registration statement relating to an offer to exchange its $575 million aggregate principal amount of 3.75% convertible senior notes due 2023 for a new series of 3.75% convertible senior notes due 2023. This registration statement was declared effective by the SEC on July 19, 2005 at which time the Company commenced the exchange offer. The exchange offer expires on August 17, 2005. The Company has commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force (EITF) Issue No. 04-8, "Accounting Issues Related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share" (EITF 04-8). Under that guidance, because settlement of the principal portion of new notes will be made in cash rather than stock, exchanging new notes for old notes will allow the Company to exclude the portion of the conversion value of the new notes attributable to their principal amount from its computation of diluted earnings per share from continuing operations. See Note 12 for the impact on diluted earnings per share related to these securities. Junior Subordinated Debentures (Trust Preferred Securities). In February 1997, a Delaware statutory business trust created by CenterPoint Energy (HL&P Capital Trust II) issued to the public $100 million aggregate amount of capital securities. The trust used the proceeds of the offering to purchase junior subordinated debentures issued by CenterPoint Energy having an interest rate and maturity date that correspond to the distribution rate and the mandatory redemption date of the capital securities. The amount of outstanding junior subordinated debentures discussed above was included in long-term debt as of December 31, 2004 and June 30, 2005. 18

The junior subordinated debentures are the trust's sole assets and their entire operations. CenterPoint Energy considers its obligations under the Amended and Restated Declaration of Trust, Indenture, Guaranty Agreement and, where applicable, Agreement as to Expenses and Liabilities, relating to the capital securities, taken together, to constitute a full and unconditional guarantee by CenterPoint Energy of the trust's obligations with respect to the capital securities. The capital securities are mandatorily redeemable upon the repayment of the related series of junior subordinated debentures at their stated maturity or earlier redemption. Subject to some limitations, CenterPoint Energy has the option of deferring payments of interest on the junior subordinated debentures. During any deferral or event of default, CenterPoint Energy may not pay dividends on its capital stock. As of June 30, 2005, no interest payments on the junior subordinated debentures had been deferred. The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of the capital securities of the trust described above and the identity and similar terms of the related series of junior subordinated debentures are as follows: AGGREGATE LIQUIDATION AMOUNTS AS OF DISTRIBUTION MANDATORY -------------------------- RATE/ REDEMPTION DECEMBER 31, JUNE 30, INTEREST DATE/ TRUST 2004 2005 RATE MATURITY DATE JUNIOR SUBORDINATED DEBENTURES - ----- ------------ -------- ------------ ------------- ------------------------------ (IN MILLIONS) HL&P Capital Trust II...... $ 100 $ 100 8.257% February 2037 8.257% Junior Subordinated Deferrable Interest Debentures Series B 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. The convertible junior subordinated debentures represent CERC Trust's sole asset and its entire operations. CERC Corp. considers its obligation under the Amended and Restated Declaration of Trust, Indenture and Guaranty Agreement relating to the convertible preferred securities, taken together, to constitute a full and unconditional guarantee by CERC Corp. of CERC Trust's obligations with respect to the convertible preferred securities. The amount of outstanding junior subordinated debentures was included in long-term debt as of December 31, 2004 and June 30, 2005. The convertible preferred securities were mandatorily redeemable upon the repayment of the convertible junior subordinated debentures at their stated maturity or earlier redemption. Effective January 7, 2003, the convertible preferred securities were convertible at the option of the holder into $33.62 of cash and 2.34 shares of CenterPoint Energy common stock for each $50 of liquidation value. As of both December 31, 2004 and June 30, 2005, the liquidation amount of convertible preferred securities outstanding was $0.3 million. The securities, and their underlying convertible junior subordinated debentures, bore interest at 6.25% and had a June 2026 maturity date. Subject to some limitations, CERC Corp. had the option of deferring payments of interest on the convertible junior subordinated debentures. During any deferral or event of default, CERC Corp. could not pay dividends on its common stock to CenterPoint Energy. As of June 30, 2005, no interest payments on the convertible junior subordinated debentures had been deferred. On July 1, 2005, the $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. (b) Receivables Facility. In January 2005, CERC'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 CERC during the peak heating season of 2005. As of June 30, 2005, CERC had $181 million of advances under its receivables facility. The average outstanding balance on the receivables facility was $181 million for the six months ended June 30, 2005. Sales of receivables were approximately $0.6 billion and $0.4 billion for the three months ended June 30, 2004 and 2005, respectively, and $1.3 billion and $0.9 billion for the six months ended June 30, 2004 and 2005, respectively. 19

(11) COMMITMENTS AND CONTINGENCIES (a) Legal Matters. RRI Indemnified Litigation The Company, CenterPoint Houston or their predecessor, Reliant Energy, and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and RRI, the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys' fees and other costs, arising out of the lawsuits described below under Electricity and Gas Market Manipulation Cases and Other Class Action Lawsuits. Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. The ultimate outcome of these matters cannot be predicted at this time. Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in both federal and state courts in California and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other western states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit, attorneys' fees and divestiture of assets. To date, several of the electricity complaints have been dismissed by the trial court and are on appeal, and several of the dismissals have been affirmed by appellate courts. Others remain in the early procedural stages. One of the gas complaints has also been dismissed and is on appeal. The other gas cases remain in the early procedural stages. The Company's former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally. RRI, some of its subsidiaries and, in some cases, former corporate officers or employees of some of those companies have been named as defendants in these suits. The Company or its predecessor, Reliant Energy, has been named in approximately 30 of these lawsuits, which were instituted between 2001 and 2005 and are pending in California state courts in San Diego County and in federal district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento, San Jose and Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases. On July 6, 2004 and on October 12, 2004, the Ninth Circuit affirmed the Company's removal to federal district court of two electric cases brought by the California Attorney General and affirmed the federal court's dismissal of these cases based upon the filed rate doctrine and federal preemption. On April 18, 2005, the Supreme Court of the United States denied the Attorney General's petition for certiorari in one of these cases. No petition for certiorari was filed in the other case, and both of these cases are now finally resolved in favor of the defendants. In one other case filed by the California Attorney General, a claim for injunctive relief remains pending, with a trial currently scheduled to begin in federal district court in February 2006. Several cases that are now pending in state court in San Diego County were originally filed in several California state courts but were removed by the defendants to federal district court. When the federal district court remanded those cases, they were coordinated in front of one San Diego state court. In July 2005, that San Diego state court refused to dismiss certain of those cases based on defendants' claims of federal preemption and the filed rate doctrine. Other Class Action Lawsuits. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant Energy have been consolidated in federal district court in Houston. RRI and certain of its former and current executive officers are named as defendants. The consolidated complaint also names RRI, Reliant Energy, the underwriters of the initial public offering of RRI's common stock in May 2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as defendants. The consolidated amended complaint seeks monetary relief purportedly on behalf of purchasers of common stock of Reliant Energy or RRI during certain time periods ranging from February 2000 to May 2002, and purchasers of common stock that can be traced to the RRI Offering. The plaintiffs allege, among other things, that the defendants misrepresented their revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In January 2004, the trial judge dismissed 20

the plaintiffs' allegations that the defendants had engaged in fraud, but claims based on alleged misrepresentations in the registration statement issued in the RRI Offering remain. In June 2004, the plaintiffs filed a motion for class certification, which the court granted in February 2005. The defendants appealed the court's order certifying the class and asked the trial court to reconsider its ruling certifying the class. In July 2005, the parties announced that they had reached a settlement in this matter, subject to court approval. The terms of the settlement do not require a payment by the Company. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits have been dismissed without prejudice. The Company and certain current and former members of its benefits committee are the remaining defendants in the third lawsuit. That lawsuit alleges that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint seeks monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. Both the plaintiffs and the defendants have pending motions for summary judgement before the court. The court is expected to establish a trial date for this case later in the fall. In October 2002, a derivative action was filed in the federal district court in Houston against the directors and officers of the Company. The complaint set forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleged that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleged breach of fiduciary duty in connection with the spin-off of RRI and the RRI Offering. The complaint sought monetary damages on behalf of the Company as well as equitable relief in the form of a constructive trust on the compensation paid to the defendants. The Company's board of directors investigated that demand and similar allegations made in a June 28, 2002 demand letter sent on behalf of a Company shareholder. The second letter demanded that the Company take several actions in response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June 2003, the board determined that these proposed actions would not be in the best interests of the Company. In March 2003, the court dismissed this case on the grounds that the plaintiff did not make an adequate demand on the Company before filing suit. Thereafter, the same party sent another demand asserting the same claims, but there has been no further activity. The Company believes that none of the lawsuits described under Other Class Action Lawsuits has merit because, among other reasons, the alleged misstatements and omissions were not material and did not result in any damages to the plaintiffs. Other Legal Matters Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In June 2004, the federal court dismissed the plaintiff's claims and in July 2004, the plaintiff filed a notice of appeal. The Company is vigorously contesting the appeal. The ultimate outcome of this matter cannot be predicted at this time. In February 2005, Utility Choice Electric filed in federal court in Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP and a number of other participants in the ERCOT power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws, intentionally interfered with prospective business relationships and contracts, and committed fraud and negligent misrepresentation. The plaintiff's principal allegations had previously 21

been investigated by the Texas Utility Commission and found to be without merit. The Company intends to vigorously defend the case. The ultimate outcome of this matter cannot be predicted at this time. Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit in state district court in Harris County, Texas for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of the Company's predecessor, Reliant Energy) alleging underpayment of municipal franchise fees. The plaintiffs claimed that they were entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. After a jury trial involving the Three Cities' claims (but not the class of cities), the trial court entered a judgment on the Three Cities' breach of contract claims for $1.7 million, including interest, plus an award of $13.7 million in legal fees. It also decertified the class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. On February 27, 2003, a state court of appeals in Houston rendered an opinion reversing the judgment against the Company and rendering judgment that the Three Cities take nothing by their claims. The court of appeals held that all of the Three Cities' claims were barred by the jury's finding of laches, a defense similar to the statute of limitations, due to the Three Cities' having unreasonably delayed bringing their claims during the more than 30 years since the alleged wrongs began. The court also held that the Three Cities were not entitled to recover any attorneys' fees. The Three Cities filed a petition for review to the Texas Supreme Court, which declined to hear the case. Thus, the Three Cities' claims have been finally resolved in the Company's favor, but the individual claims of the remaining 45 cities remain pending in the same court. The Company does not expect the outcome of the remaining claims to have a material impact on its financial condition, results of operations or cash flows. 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 CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. CERC does not expect the ultimate outcome to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, 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., all of which are subsidiaries of the Company. The plaintiffs alleged that defendants inflated the prices charged 22

to certain consumers of natural gas. In February 2003, a similar suit was filed in state court in Caddo Parish, Louisiana against CERC 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 CERC 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, CERC, 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 County 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, CERC 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 5(d). The Company and CERC 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 CERC. Pipeline Safety Compliance. In 2005, CERC 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. CERC estimates the range of expenditures to locate and replace such components to be $35 to $45 million. CERC will request return on and of the capitalized expenditures in future rate cases. Minnesota Cold Weather Rule. In December 2004, the MPUC opened an investigation to determine whether CERC'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 issued its report alleging CERC has violated the CWR and recommended a $5 million penalty. CERC filed its reply comments in July 2005. In addition, in June 2005, CERC was named in a suit filed on behalf of a purported class of customers who allege that CERC'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. CERC believes that it has not knowingly and intentionally violated the CWR and intends to vigorously contest the lawsuit. CERC 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 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. 23

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 either the Company or CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At June 30, 2005, CERC had accrued $18 million for remediation of certain Minnesota sites. At June 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. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of June 30, 2005, CERC has collected or accrued $13 million from insurance companies and ratepayers 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 CERC or may have been owned by one of its former affiliates. CERC 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 CERC or its divisions. CERC 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 CERC's motion to dismiss on the grounds that CERC 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 CERC. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC 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. Asbestos. A number of facilities owned by the Company contain significant amounts of asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company but currently owned by Texas Genco LLC. The Company anticipates that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between the Company and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco 24

to Texas Genco LLC, the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and 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. 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. (d) Tax Contingencies. As discussed in Note 10 to the CenterPoint Energy Notes, in the 1997 through 2000 audit (which now includes 2001), the Internal Revenue Service (IRS) disallowed all deductions for original issue discount (OID) relating to the Company's 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) and 7% Automatic Common Exchange Securities (ACES). It is the contention of the IRS that (1) those instruments, in combination with the Company's long position in Time Warner common stock (TW Common), constitute a straddle under Section 1092 and 246 of the Internal Revenue Code of 1986, as amended and (2) the indebtedness underlying those instruments was incurred to carry the TW Common. If the IRS prevails on both of these positions, all OID (including interest actually paid) on the ZENS and ACES would not be currently deductible, but would instead be added to the Company's basis in the TW Common it holds. The capitalization of OID to the TW Common basis would have the effect of recharacterizing ordinary interest deductions to capital losses or reduced capital gains. The Company's ability to realize the tax benefit of future capital losses, if any, from the sale of the 21.6 million shares of TW Common currently held will depend on the timing of those sales, the value of TW Common stock when sold, and the extent of any other capital gains and losses. Although the Company is protesting the contention of the IRS, at December 31, 2004, the Company had established a tax reserve for this issue of $79 million, which was increased to $101 million at June 30, 2005. The Company has also reserved for other significant tax items including issues relating to acquisitions, capital cost recovery and certain positions taken with respect to state tax filings. The total amount reserved for the other items is approximately $40 million. (e) Nuclear Decommissioning Trusts. CenterPoint Houston, as collection agent for the nuclear decommissioning charge assessed on its transmission and distribution customers, deposited $2.9 million in 2004 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project, and expects to deposit approximately $2.9 million of collected charges in 2005. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and the Nuclear Regulatory Commission relating to Texas Genco's nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and the Texas Utility Commission's final order, CenterPoint Houston and Texas Genco are presently jointly administering the decommissioning funds through the 25

Nuclear Decommissioning Trust Investment Committee. Texas Genco and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. As administrators of the decommissioning funds, CenterPoint Houston and Texas Genco are jointly responsible for assuring that the funds are prudently invested in a manner consistent with the rules of the Texas Utility Commission. CenterPoint Houston and Texas Genco expect to file a request with the Texas Utility Commission in 2005 to name Texas Genco as the sole fund administrator. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that were not recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be charged to transmission and distribution customers of CenterPoint Houston or its successor. 26

(12) EARNINGS PER SHARE The following table reconciles numerators and denominators of the Company's basic and diluted earnings per share (EPS) calculations: FOR THE THREE MONTHS ENDED FOR THE SIX MONTHS ENDED JUNE 30, JUNE 30, ---------------------------- ---------------------------- 2004 2005 2004 2005 ------------- ------------- ------------- ------------- (IN MILLIONS, EXCEPT SHARE AND PER SHARE AMOUNTS) Basic EPS Calculation: Income (loss) from continuing operations before extraordinary item................................................ $ (3) $ 27 $ 26 $ 94 Discontinued operations, net of tax................................ 60 (3) 105 (3) Extraordinary item, net of tax..................................... -- 30 -- 30 ------------- ------------- ------------- ------------- Net income......................................................... $ 57 $ 54 $ 131 $ 121 ============= ============= ============= ============= Weighted average shares outstanding................................... 307,250,000 309,098,000 306,631,000 308,786,000 ============= ============= ============= ============= Basic EPS: Income (loss) from continuing operations before extraordinary item................................................ $ (0.01) $ 0.09 $ 0.09 $ 0.30 Discontinued operations, net of tax................................ 0.20 (0.01) 0.34 (0.01) Extraordinary item, net of tax..................................... -- 0.10 -- 0.10 ------------- ------------- ------------- ------------- Net income......................................................... $ 0.19 $ 0.18 $ 0.43 $ 0.39 ============= ============= ============= ============= Diluted EPS Calculation: Net income......................................................... $ 57 $ 54 $ 131 $ 121 Plus: Income impact of assumed conversions: Interest on 3 3/4% convertible senior notes...................... -- 4 -- 7 Interest on 6 1/4% convertible trust preferred securities........ -- -- -- -- ------------- ------------- ------------- ------------- Total earnings effect assuming dilution............................ $ 57 $ 58 $ 131 $ 128 ============= ============= ============= ============= Weighted average shares outstanding................................... 307,250,000 309,098,000 306,631,000 308,786,000 Plus: Incremental shares from assumed conversions (1): Stock options.................................................... 1,301,000 1,302,000 1,259,000 1,254,000 Restricted stock................................................. 1,070,000 1,365,000 1,070,000 1,365,000 3 3/4% convertible senior notes.................................. -- 49,655,000 -- 49,655,000 6 1/4% convertible trust preferred securities.................... 17,000 16,000 17,000 16,000 ------------- ------------- ------------- ------------- Weighted average shares assuming dilution.......................... 309,638,000 361,436,000 308,977,000 361,076,000 ============= ============= ============= ============= Diluted EPS: Income (loss) from continuing operations before extraordinary item............................................... $ (0.01) $ 0.09 $ 0.08 $ 0.28 Discontinued operations, net of tax................................ 0.20 (0.01) 0.34 (0.01) Extraordinary item, net of tax..................................... -- 0.08 -- 0.08 ------------- ------------- ------------- ------------- Net income......................................................... $ 0.19 $ 0.16 $ 0.42 $ 0.35 ============= ============= ============= ============= - ----------------- (1) For the three months ended June 30, 2004 and 2005, the computation of diluted EPS excludes options to purchase 10,024,219 and 9,356,759 shares of common stock, respectively, that have exercise prices (ranging from $11.29 to $32.26 per share and $14.01 to $32.26 per share for the second quarter of 2004 and 2005, respectively) greater than the per share average market price for the period and would thus be antidilutive if exercised. For the six months ended June 30, 2004 and 2005, the computation of diluted EPS excludes options to purchase 12,037,219 and 9,356,759 shares of common stock, respectively, that have exercise prices (ranging from $10.92 27

to $32.26 per share and $14.01 to $32.26 per share for the first six months of 2004 and 2005, respectively) greater than the per share average market price for the period and would thus be antidilutive if exercised. The Company's $575 million contingently convertible notes are included in the calculation of diluted earnings per share pursuant to EITF 04-8. The Company's $255 million contingently convertible notes are not included in the calculation of diluted earnings per share because the terms of this debt instrument were modified prior to December 31, 2004 to provide for only cash settlement of the principal amount upon conversion as required by EITF 04-8. Additionally, the $255 million contingently convertible notes were excluded from the calculation of diluted earnings per share because the average market price of the Company's common stock for the three and six months ended June 30, 2005 did not exceed the conversion price of these notes and would thus be antidilutive. Diluted earnings per share for the three months and six months ended June 30, 2004 have not been restated for the adoption of EITF 04-8 effective December 31, 2004 as inclusion of the contingently convertible shares have an antidilutive effect. The impact on the Company's diluted EPS from continuing operations for the three and six months ended June 30, 2005 was a decrease of $-0- and $0.02 per share, respectively. Subsequent to the modification of the $255 million contingently convertible notes to provide for only cash settlement of the principal amount upon conversion, the notes will only be included in the calculation of diluted earnings per share when the average market price of the Company's common stock exceeds the conversion price. Any new notes issued in connection with the exchange offer related to the $575 million contingently convertible notes will be treated similarly. The conversion prices for the $225 million and $575 million contingently convertible notes are $12.81 and $11.58, respectively. (13) REPORTABLE BUSINESS SEGMENTS The Company's determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The Company's Electric Generation business segment is presented as discontinued operations within these Interim Financial Statements. The Company has identified the following reportable business segments: Electric Transmission & Distribution, Natural Gas Distribution, Pipelines and Gathering and Other Operations. The Company's generation operations, which were previously reported in the Electric Generation business segment, are presented as discontinued operations within these Interim Financial Statements. 28

Financial data for the Company's reportable business segments are as follows: FOR THE THREE MONTHS ENDED JUNE 30, 2004 -------------------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING INCOME CUSTOMERS REVENUES (LOSS) -------------- ------------- ---------------- (IN MILLIONS) Electric Transmission & Distribution............................. $ 375(1) $ -- $ 127 Natural Gas Distribution......................................... 1,245(2) -- 23 Pipelines and Gathering.......................................... 79(3) 34 42 Other Operations................................................. 1 2 (6) Eliminations..................................................... -- (36) -- -------------- ------------- ---------------- Consolidated..................................................... $ 1,700 $ -- $ 186 ============== ============= ================ FOR THE THREE MONTHS ENDED JUNE 30, 2005 -------------------------------------------------------- REVENUES FROM NET EXTERNAL INTERSEGMENT OPERATING INCOME CUSTOMERS REVENUES (LOSS) -------------- ------------- ---------------- (IN MILLIONS) Electric Transmission & Distribution............................. $ 414(1) $ -- $ 122 Natural Gas Distribution......................................... 1,429 1 19 Pipelines and Gathering.......................................... 87 38 52 Other Operations................................................. 2 2 (7) Eliminations..................................................... -- (41) -- -------------- ------------- ---------------- Consolidated..................................................... $ 1,932 $ -- $ 186 ============== ============= ================ FOR THE SIX MONTHS ENDED JUNE 30, 2004 ------------------------------------------------ REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING INCOME AS OF CUSTOMERS REVENUES (LOSS) DECEMBER 31, 2004 ------------- ------------ ---------------- ----------------- (IN MILLIONS) Electric Transmission & Distribution ........ $ 705(1) $ -- $ 212 $ 8,783 Natural Gas Distribution..................... 3,375(2) 1 140 4,798 Pipelines and Gathering...................... 145(3) 71 87 2,637 Other Operations............................. 3 3 (13) 2,794 Discontinued Operations...................... -- -- -- 1,565 Eliminations................................. -- (75) -- (2,415) ------------- ------------ ---------------- ----------------- Consolidated................................. $ 4,228 $ -- $ 426 $ 18,162 ============= ============ ================ ================= FOR THE SIX MONTHS ENDED JUNE 30, 2005 ------------------------------------------------ REVENUES FROM NET TOTAL ASSETS EXTERNAL INTERSEGMENT OPERATING INCOME AS OF CUSTOMERS REVENUES (LOSS) JUNE 30, 2005 ------------- ------------ ---------------- ----------------- (IN MILLIONS) Electric Transmission & Distribution ........ $ 759(1) $ -- $ 202 $ 8,311 Natural Gas Distribution..................... 3,757 3 158 4,779 Pipelines and Gathering...................... 171 75 116 2,798 Other Operations............................. 7 4 (14) 2,234 Eliminations................................. -- (82) -- (2,232) ------------- ------------ ---------------- ----------------- Consolidated................................. $ 4,694 $ -- $ 462 $ 15,890 ============= ============ ================ ================= - ------------- (1) Sales to subsidiaries of RRI for the three months ended June 30, 2004 and 2005 represented approximately $202 million and $183 million, respectively, of CenterPoint Houston's transmission and distribution revenues from external customers. Sales to subsidiaries of RRI for the six months ended June 30, 2004 and 29

2005 represented approximately $401 million and $366 million, respectively, of CenterPoint Houston's transmission and distribution revenues from external customers. (2) Sales to Texas Genco for the three and six months ended June 30, 2004 of $10 million and $16 million, respectively, have been reclassified from intersegment revenues to revenues from external customers due to the sale of Texas Genco. (3) Sales to Texas Genco for the three and six months ended June 30, 2004 of $1 million and $2 million, respectively, have been reclassified from intersegment revenues to revenues from external customers due to the sale of Texas Genco. 30

ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES The following discussion and analysis should be read in combination with our Interim Financial Statements contained in this Form 10-Q. EXECUTIVE SUMMARY RECENT EVENTS RECOVERY OF TRUE-UP BALANCE The Texas Electric Choice Plan (Texas electric restructuring law) provides for the Public Utility Commission of Texas (Texas Utility Commission) to conduct a "true-up" proceeding to determine CenterPoint Energy Houston Electric, LLC's (CenterPoint Houston) stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs. In March 2004, CenterPoint Houston filed its stranded cost true-up application with the Texas Utility Commission. CenterPoint Houston had requested recovery of $3.7 billion, excluding interest. In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. Both CenterPoint Houston and other parties filed appeals of the True-Up Order, and those appeals remain pending before a state district court in Travis County, Texas. The court held a hearing on the appeal in early August 2005 with a decision currently expected in the near future. There are two ways for CenterPoint Houston to recover the true-up balance: by issuing transition bonds to securitize the amounts due and/or by implementing a competition transition charge (CTC). In March 2005, the Texas Utility Commission issued a financing order that authorized the issuance of transition bonds. Although several parties originally appealed the financing order, only two have maintained appeals. CenterPoint Houston will not be able to issue transition bonds while an appeal is pending. Prior to the appeal, it had been expected that approximately $1.8 billion in transition bonds could be issued by mid-2005 under the terms of the financing order. On August 4, 2005 the District Court affirmed the financing order. Texas law provides for any further appeals to be filed directly with the Texas Supreme Court within 15 days. On July 14, 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC to collect approximately $570 million over 14 years plus interest at an annual rate of 11.075%. Based on the accrual of interest provided for in the CTC order, CenterPoint Houston expects that this amount will increase to approximately $600 million by the end of the third quarter which is when the CTC is expected to be implemented. The CTC order also allows CenterPoint Houston to collect approximately $24 million of rate case expenses over three years. The CTC order authorizes CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. CenterPoint Houston cannot implement the CTC until the Texas Utility Commission takes final action on the motions for rehearing. CenterPoint Houston is entitled to accrue a return on the true-up balance until it is fully recovered. CITY OF HOUSTON FRANCHISE On June 27, 2005, CenterPoint Houston accepted an ordinance granting CenterPoint Houston a new 30-year franchise to use the public rights-of-way to conduct its business in the City of Houston (New Franchise Ordinance). The New Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Franchise Ordinance clarifies certain operational obligations of CenterPoint Houston and the City of Houston and provides for streamlined payment and audit procedures and a two year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, CenterPoint Houston paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period beginning July 1, 2005, the annual franchise fee (Annual Franchise Fee) under the New Franchise Ordinance will include a base amount of $88.1 million (Base Amount) and an additional payment of $8.5 million (Additional Amount). The Base Amount and the 31

Additional Amount will be adjusted annually based on the annual increase or decrease in kWh delivered by CenterPoint Houston within the City of Houston. The New Franchise Ordinance requires the City of Houston to modify CenterPoint Houston's tariff to allow CenterPoint Houston to recover the Additional Amount from retail electric providers serving end-use retail electric customers within the City of Houston boundaries. CenterPoint Houston filed a request with the City of Houston to implement a tariff rider to collect the Additional Amount, but subsequently asked the City of Houston to abate further consideration of that application pending a review by counsel for the City of Houston and CenterPoint Houston regarding the implementation of the New Franchise Ordinance. CenterPoint Houston began paying the new annual franchise fees on July 1, 2005. Pursuant to the New Franchise Ordinance, CenterPoint Houston retains the right to recover from the City of Houston any portion of the Additional Amount paid (or to refuse to pay any portion not yet paid) for which CenterPoint Houston is denied recovery by any regulatory authority. Additionally, the New Franchise Ordinance provides that the Annual Franchise Fee will be reduced prospectively to reflect any portion of the Annual Franchise Fee that is not included in CenterPoint Houston's base rates in any subsequent rate case. COMPLETION OF SALE OF TEXAS GENCO On April 13, 2005, we completed the sale of our nuclear generation assets, consisting of a 30.8% undivided interest in the South Texas Project Electric Generating Station, to Texas Genco LLC (formerly known as GC Power Acquisition LLC) for $700 million in cash. The sale was effected through the merger of our wholly owned subsidiary, Texas Genco Holdings, Inc. (Texas Genco), with a wholly owned subsidiary of Texas Genco LLC. As a result of the merger, Texas Genco became a wholly owned subsidiary of Texas Genco LLC and we received $700 million in cash. We used the proceeds primarily to repay outstanding indebtedness. The merger was the second and final step of the transaction announced in July 2004 in which Texas Genco LLC agreed to acquire Texas Genco. In the first step of the transaction, involving the sale of Texas Genco's fossil generation assets (coal, lignite and gas-fired plants), we received $2.231 billion in December 2004, which was used primarily to pay down debt. In 2004, we recorded a loss of $214 million related to the sale of Texas Genco and recorded additional losses to offset subsequent earnings of Texas Genco. We continued to record additional losses in 2005 until the April 2005 closing of the final step of the sale transaction to offset Texas Genco's 2005 earnings. DEBT FINANCING TRANSACTIONS In March 2005, we filed a registration statement relating to an offer to exchange our $575 million aggregate principal amount of 3.75% convertible senior notes due 2023 for a new series of 3.75% convertible senior notes due 2023. This registration statement was declared effective by the SEC on July 19, 2005 at which time we commenced the exchange offer. The exchange offer expires on August 17, 2005. We commenced the exchange offer in response to the guidance set forth in Emerging Issues Task Force Issue No. 04-8, "The Effect of Contingently Convertible Instruments on Diluted Earnings Per Share." Under that guidance, because the terms of the new notes provide for settlement of the principal amount on conversion in cash rather than our common stock, exchanging new notes for old notes will allow us to exclude the portion of the conversion value of the new notes attributable to their principal amount from our computation of diluted earnings per share from continuing operations. In June 2005, CERC Corp. 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. REPEAL OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 1935 On July 29, 2005, Congress passed the Energy Policy Act of 2005 (Energy Act), which President Bush is expected to sign in early August. Under that legislation, the Public Utility Holding Company Act of 1935 (1935 Act) is repealed six months after the enactment of the Energy Act. After the effective date of repeal, we and our subsidiaries will no longer be subject to restrictions imposed under the 32

1935 Act. Until the repeal is effective, we and our 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 transfers to the Federal Energy Regulatory Commission (FERC) certain functions performed by the SEC under the 1935 Act, including the requirement that holding companies and their subsidiaries maintain certain books and records and make them available for review by FERC and, through FERC, to state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act. It is presently unknown what, if any, specific obligations under those rules may be imposed on us and our subsidiaries as result of that rulemaking. 2ND QUARTER 2005 HIGHLIGHTS Our operating performance for the second quarter of 2005 compared to the second quarter of 2004 was affected by: - increased operating income of $10 million in our Pipelines and Gathering business segment primarily from increased demand for certain transportation and ancillary services and increased throughput and demand for services related to our core gas gathering operations; - continued customer growth, with the addition of 95,000 metered electric and gas customers; - an increase in other income of $35 million for the second quarter of 2005 related to the return on our true-up balance; and - a decrease in interest expense of $10 million. The above increases in operating performance were partially offset by: - decreased operating income of $5 million in our Electric Transmission & Distribution business segment primarily from increased state and local taxes and higher operation and maintenance expenses including the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in the second quarter of 2004 and higher transmission costs, partially offset by increased usage mainly due to weather, continued customer growth and higher transmission cost recovery; and - decreased operating income of $4 million in our Natural Gas Distribution business segment primarily due to increased depreciation expense. 33

CONSOLIDATED RESULTS OF OPERATIONS All dollar amounts in the tables that follow are in millions, except for per share amounts. THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- -------------------------- 2004 2005 2004 2005 ---------- ---------- ---------- ---------- Revenues............................................ $ 1,700 $ 1,932 $ 4,228 $ 4,694 Expenses............................................ 1,514 1,746 3,802 4,232 ---------- ---------- ---------- ---------- Operating Income.................................... 186 186 426 462 Interest and Other Finance Charges.................. (198) (189) (391) (371) Other Income, net................................... 10 48 14 84 ---------- ---------- ---------- ---------- Income (Loss) From Continuing Operations Before Income Taxes and Extraordinary Item............... (2) 45 49 175 Income Tax Expense.................................. (1) (18) (23) (81) ---------- ---------- ---------- ---------- Income (Loss) From Continuing Operations Before Extraordinary Item................................ (3) 27 26 94 Discontinued Operations, net of tax................. 60 (3) 105 (3) ---------- ---------- ---------- ---------- Income Before Extraordinary Item.................... 57 24 131 91 Extraordinary Item, net of tax...................... -- 30 -- 30 ---------- ---------- ---------- ---------- Net Income.......................................... $ 57 $ 54 $ 131 $ 121 ========== ========== ========== ========== BASIC EARNINGS PER SHARE: Income (Loss) From Continuing Operations Before Extraordinary Item.............................. $ (0.01) $ 0.09 $ 0.09 $ 0.30 Discontinued Operations, net of tax............... 0.20 (0.01) 0.34 (0.01) Extraordinary Item, net of tax.................... -- 0.10 -- 0.10 ---------- ---------- ---------- ---------- Net Income........................................ $ 0.19 $ 0.18 $ 0.43 $ 0.39 ========== ========== ========== ========== DILUTED EARNINGS PER SHARE: Income (Loss) From Continuing Operations Before Extraordinary Item.............................. $ (0.01) $ 0.09 $ 0.08 $ 0.28 Discontinued Operations, net of tax............... 0.20 (0.01) 0.34 (0.01) Extraordinary Item, net of tax.................... -- 0.08 -- 0.08 ---------- ---------- ---------- ---------- Net Income........................................ $ 0.19 $ 0.16 $ 0.42 $ 0.35 ========== ========== ========== ========== THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004 Income from Continuing Operations. We reported income from continuing operations before extraordinary item of $27 million ($0.09 per diluted share) for the three months ended June 30, 2005 as compared to a $3 million loss ($0.01 per diluted share) for the same period in 2004. The increase in income from continuing operations of $30 million was primarily due to increased operating income of $10 million in our Pipelines and Gathering business segment resulting from increased demand for certain transportation and ancillary services as well as increased throughput and demand for services related to our core gas gathering operations, $35 million of other income related to a return on the true-up balance of our Electric Transmission & Distribution business segment as a result of the True-Up Order and a $10 million decrease in interest expense due to lower borrowing levels and lower borrowing costs reflecting the replacement of certain of our credit facilities. These increases were partially offset by decreased operating income of $5 million in our Electric Transmission & Distribution business segment primarily from increased state and local taxes and higher operation and maintenance expenses including the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in the second quarter of 2004, partially offset by increased usage mainly due to weather, continued customer growth and higher transmission cost recovery, as well as decreased operating income of $4 million in our Natural Gas Distribution business segment primarily due to increased depreciation expense and increased income tax expense as discussed below. Income Tax Expense. During the three months ended June 30, 2005, our effective tax rate was 39.3%. The most significant items affecting our effective tax rate in the second quarter of 2005 were an addition to the tax reserve of 34

approximately $12 million relating to the contention of the Internal Revenue Service (IRS) that the current deductions for original issue discount (OID) on our 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) be capitalized, potentially converting what would be ordinary deductions into capital losses at the time the ZENS are settled, partially offset by a favorable tax audit adjustment of $10 million. We expect the reserve to increase by approximately $12 million in each of the remaining two quarters. SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004 Income from Continuing Operations. We reported income from continuing operations before extraordinary item of $94 million ($0.28 per diluted share) for the six months ended June 30, 2005 as compared to $26 million ($0.08 per diluted share) for the same period in 2004. The increase in income from continuing operations of $68 million was primarily due to increased operating income of $29 million in our Pipelines and Gathering business segment resulting from increased demand for certain transportation and ancillary services as well as increased throughput and demand for services related to our core gas gathering operations, increased operating income of $18 million in our Natural Gas Distribution business segment primarily due to rate increases, higher contributions from our competitive natural gas sales business, reduced pension and benefit costs and the absence of severance costs recorded in the first quarter of 2004, partially offset by milder weather, decreased throughput and increased depreciation, $69 million of other income related to a return on the true-up balance of our Electric Transmission & Distribution business segment as a result of the True-Up Order, and a $20 million decrease in interest expense due to lower borrowing levels and lower borrowing costs reflecting the replacement of certain of our credit facilities. The above increases were partially offset by decreased operating income of $10 million in our Electric Transmission & Distribution business segment primarily from increased state and local taxes and higher operation and maintenance expenses including the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in the second quarter of 2004, partially offset by increased usage mainly due to weather, continued customer growth and higher transmission cost recovery, as well as increased income tax expense as discussed below. Income Tax Expense. During the six months ended June 30, 2005, our effective tax rate was 46.2%. The most significant item affecting our effective tax rate in the first six months of 2005 is an addition to the tax reserve of approximately $22 million relating to the ZENS as discussed above. INTEREST EXPENSE AND OTHER FINANCE CHARGES In accordance with Emerging Issues Task Force Issue No. 87-24 "Allocation of Interest to Discontinued Operations," we have reclassified interest to discontinued operations of Texas Genco based on net proceeds received from the sale of Texas Genco of $2.5 billion, and have applied the proceeds to the amount of debt assumed to be paid down in 2004 according to the terms of the respective credit facilities in effect for that period. In periods where only the term loan was assumed to be repaid, the actual interest paid on the term loan was reclassified. In periods where a portion of the revolver was assumed to be repaid, the percentage of that portion of the revolver to the total outstanding balance was calculated, and that percentage was applied to the actual interest paid in those periods to compute the amount of interest reclassified. Total interest expense incurred was $210 million and $415 million for the three and six months ended June 30, 2004. We have reclassified $12 million and $24 million of interest expense for the three and six months ended June 30, 2004 based upon interest expense associated with debt that would have been required to be repaid as a result of our disposition of Texas Genco. EXTRAORDINARY ITEM AND LOSS ON DISPOSAL OF TEXAS GENCO Net income for both the three months and six months ended June 30, 2005 included an after-tax extraordinary gain of $30 million ($0.08 per diluted share) reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 to write-down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission. Net income for the three months ended June 30, 2004 and 2005 included a net after-tax gain (loss) from discontinued operations of Texas Genco of $60 million ($0.20 per diluted share) and ($3) million ($0.01 per diluted 35

share), respectively. Net income for the six months ended June 30, 2004 and 2005 included a net after tax gain (loss) from discontinued operations of Texas Genco of $105 million ($0.34 per diluted share) and ($3) million ($0.01 per diluted share), respectively. RESULTS OF OPERATIONS BY BUSINESS SEGMENT The following table presents operating income for each of our business segments for the three and six months ended June 30, 2004 and 2005. Some amounts from the previous year have been reclassified to conform to the 2005 presentation of the financial statements. These reclassifications do not affect consolidated net income. THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- --------------------------- 2004 2005 2004 2005 ----------- ----------- ----------- ----------- (IN MILLIONS) Electric Transmission & Distribution............... $ 127 $ 122 $ 212 $ 202 Natural Gas Distribution........................... 23 19 140 158 Pipelines and Gathering............................ 42 52 87 116 Other Operations................................... (6) (7) (13) (14) ----------- ----------- ----------- ----------- Total Consolidated Operating Income.......... $ 186 $ 186 $ 426 $ 462 =========== =========== =========== =========== 36

ELECTRIC TRANSMISSION & DISTRIBUTION For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read "Risk Factors -- Risk Factors Affecting Our Electric Transmission & Distribution Business," " -- Risk Factors Associated with Our Consolidated Financial Condition" and " -- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- --------------------------- 2004 2005 2004 2005 ----------- ----------- ----------- ----------- (IN MILLIONS, EXCEPT CUSTOMER DATA) Electric transmission and distribution revenues.............. $ 357 $ 388 $ 672 $ 711 ----------- ----------- ----------- ----------- Electric transmission and distribution expenses: Operation and maintenance.................................. 125 153 258 291 Depreciation and amortization.............................. 63 64 123 128 Taxes other than income taxes.............................. 51 58 98 108 ----------- ----------- ----------- ----------- Total electric transmission and distribution expenses.... 239 275 479 527 ----------- ----------- ----------- ----------- Operating Income - Electric transmission and distribution utility....................................... 118 113 193 184 Operating Income - Transition bond company (1)............... 9 9 19 18 ----------- ----------- ----------- ----------- Total Segment Operating Income............................... $ 127 $ 122 $ 212 $ 202 =========== =========== =========== =========== Actual gigawatt-hours (GWh) delivered: Residential................................................ 5,801 6,594 10,203 10,736 Total...................................................... 18,545 18,956 34,065 34,783 Average number of metered customers: Residential................................................ 1,634,202 1,675,573 1,628,074 1,668,447 Total...................................................... 1,856,846 1,904,090 1,849,762 1,895,556 - ----------- (1) Represents the amount necessary to pay interest on the transition bonds. THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004 Our Electric Transmission & Distribution business segment reported operating income of $122 million for the three months ended June 30, 2005, consisting of $113 million for the regulated electric transmission and distribution utility and $9 million for the transition bond company. For the three months ended June 30, 2004, operating income totaled $127 million, consisting of $118 million for the regulated electric transmission and distribution utility and $9 million for the transition bond company. Operating revenues increased primarily from increased usage mainly due to warmer weather ($14 million), continued customer growth ($8 million) with the addition of 48,000 metered customers since June 2004 and higher transmission cost recovery ($4 million). The increase in operating revenues was more than offset by higher transmission costs ($3 million), higher tree trimming costs for preventive maintenance ($4 million), increased state and local taxes ($7 million) and the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in 2004. SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004 Our Electric Transmission & Distribution business segment reported operating income of $202 million for the six months ended June 30, 2005, consisting of $184 million for the regulated electric transmission and distribution utility and $18 million for the transition bond company. For the six months ended June 30, 2004, operating income totaled $212 million, consisting of $193 million for the regulated electric transmission and distribution utility and $19 million for the transition bond company. Operating revenues increased primarily from increased usage mainly 37

due to warmer weather ($9 million), continued customer growth ($15 million) with the addition of 48,000 metered customers since June 2004 and higher transmission cost recovery ($8 million). The increase in operating revenues was more than offset by higher transmission costs ($8 million), higher tree trimming costs for preventive maintenance ($6 million), the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in 2004, increased state and local taxes ($10 million) and higher depreciation expense ($5 million), partially offset by reduced benefits expense ($7 million). NATURAL GAS DISTRIBUTION For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and " -- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following table provides summary data of our Natural Gas Distribution business segment for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, ------------------------------ ------------------------------ 2004 2005 2004 2005 ------------ ------------ ------------ ------------ (IN MILLIONS, EXCEPT CUSTOMER DATA) Revenues................................... $ 1,245 $ 1,430 $ 3,376 $ 3,760 ------------ ------------ ------------ ------------ Expenses: Natural gas.............................. 1,027 1,213 2,816 3,188 Operation and maintenance................ 133 133 283 273 Depreciation and amortization............ 35 39 70 77 Taxes other than income taxes............ 27 26 67 64 ------------ ------------ ------------ ------------ Total expenses......................... 1,222 1,411 3,236 3,602 ------------ ------------ ------------ ------------ Operating Income........................... $ 23 $ 19 $ 140 $ 158 ============ ============ ============ ============ Throughput (in billion cubic feet (Bcf)): Residential.............................. 21 21 106 98 Commercial and industrial................ 49 43 132 120 Non-rate regulated....................... 167 148 306 331 Elimination (1).......................... (63) (29) (73) (78) ------------ ------------ ------------ ------------ Total Throughput....................... 174 183 471 471 ============ ============ ============ ============ Average number of customers: Residential.............................. 2,793,297 2,833,773 2,802,379 2,842,645 Commercial and industrial................ 242,111 246,032 244,388 247,429 Non-rate regulated....................... 6,265 6,533 6,228 6,522 ------------ ------------ ------------ ------------ Total.................................. 3,041,673 3,086,338 3,052,995 3,096,596 ============ ============ ============ ============ - ---------- (1) Elimination of intrasegment sales. THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004 Our Natural Gas Distribution business segment reported operating income of $19 million for the three months ended June 30, 2005 as compared to $23 million for the same period in 2004. Increases in operating income from rate increases ($5 million) and increased contributions from our competitive natural gas sales business ($1 million) were more than offset by the impact of decreased throughput net of continued customer growth with the addition of approximately 47,000 customers since June 2004 ($5 million) and increased depreciation expense primarily due to higher plant balances ($4 million). Decreases in operation and maintenance expenses primarily from lower employee benefit expenses ($7 million) and the capitalization of previously incurred restructuring expenses as allowed by a recent regulatory order from the Railroad Commission of Texas ($4 million) offset other expense increases ($11 million). 38

SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004 Our Natural Gas Distribution business segment reported operating income of $158 million for the six months ended June 30, 2005 as compared to $140 million for the same period in 2004. Increases in operating income from rate increases ($16 million) and increased contributions from our competitive natural gas sales business ($4 million) were partially offset by the impact of milder weather and decreased throughput net of continued customer growth with the addition of approximately 47,000 customers since June 2004 ($10 million). Operation and maintenance expense decreased $10 million. Excluding an $8 million charge recorded in the first quarter of 2004 for severance costs associated with staff reductions, which has reduced costs in later periods, operation and maintenance expenses decreased by $2 million primarily due to lower employee benefit expenses ($11 million) and the capitalization of previously incurred restructuring expenses as discussed above ($4 million), which more than offset other expense increases ($13 million). These net increases to operating income were partially offset by increased depreciation expense primarily due to higher plant balances ($7 million). PIPELINES AND GATHERING For information regarding factors that may affect the future results of operations of our Pipelines and Gathering business segment, please read "Risk Factors -- Risk Factors Affecting Our Natural Gas Distribution and Pipelines and Gathering Businesses," " -- Risk Factors Associated with Our Consolidated Financial Condition" and " -- Other Risks" in Item 5 of Part II of this report beginning on page 52. The following table provides summary data of our Pipelines and Gathering business segment for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- -------------------------- 2004 2005 2004 2005 ---------- ----------- ---------- ---------- (IN MILLIONS) Revenues.................................. $ 113 $ 125 $ 216 $ 246 ---------- ----------- ---------- ---------- Expenses: Natural gas............................. 18 18 28 25 Operation and maintenance............... 37 40 70 74 Depreciation and amortization........... 11 11 22 22 Taxes other than income taxes........... 5 4 9 9 ---------- ----------- ---------- ---------- Total expenses........................ 71 73 129 130 ---------- ----------- ---------- ---------- Operating Income.......................... $ 42 $ 52 $ 87 $ 116 ========== =========== ========== ========== Throughput (in Bcf): Natural Gas Sales....................... 4 3 7 4 Transportation.......................... 207 230 477 501 Gathering............................... 79 87 154 170 Elimination (1)......................... (3) (2) (5) (3) ---------- ----------- ---------- ---------- Total Throughput..................... 287 318 633 672 ========== =========== ========== ========== - ---------- (1) Elimination of volumes both transported and sold. THREE MONTHS ENDED JUNE 30, 2005 COMPARED TO THREE MONTHS ENDED JUNE 30, 2004 Our Pipelines and Gathering business segment reported operating income of $52 million for the three months ended June 30, 2005 compared to $42 million for the same period in 2004. Operating margins (revenues less natural gas costs) increased by $12 million primarily due to increased demand for certain transportation and ancillary services ($7 million) and increased throughput and demand for services related to our core gas gathering operations ($9 million). SIX MONTHS ENDED JUNE 30, 2005 COMPARED TO SIX MONTHS ENDED JUNE 30, 2004 Our Pipelines and Gathering business segment reported operating income of $116 million for the six months ended June 30, 2005 compared to $87 million for the same period in 2004. Operating margins (revenues less natural 39

gas costs) increased by $33 million primarily due to increased demand for certain transportation and ancillary services ($18 million) and increased throughput and demand for services related to our core gas gathering operations ($14 million). Additionally, operation and maintenance expenses increased by $4 million primarily due to increased pipeline integrity compliance expenses. OTHER OPERATIONS The following table shows the operating loss of our Other Operations business segment for the three and six months ended June 30, 2004 and 2005: THREE MONTHS ENDED JUNE 30, SIX MONTHS ENDED JUNE 30, --------------------------- --------------------------- 2004 2005 2004 2005 ----------- ----------- ----------- ----------- (IN MILLIONS) Revenues........................................... $ 3 $ 4 $ 6 $ 11 Expenses........................................... 9 11 19 25 ----------- ----------- ----------- ----------- Operating Loss..................................... $ (6) $ (7) $ (13) $ (14) =========== =========== =========== =========== DISCONTINUED OPERATIONS In July 2004, we announced our agreement to sell our majority owned subsidiary, Texas Genco, to Texas Genco LLC. On December 15, 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed on April 13, 2005. We recorded after-tax income of $60 million and $105 million for the three and six months ended June 30, 2004, respectively, related to the operations of Texas Genco. We recorded an after-tax loss of $3 million for each of the three and six month periods ended June 30, 2005. General corporate overhead, previously allocated to Texas Genco from CenterPoint Energy, was $5 million and $10 million for the three and six months ended June 30, 2004, respectively, and was less than $1 million for each of the three and six month periods ended June 30, 2005. These amounts will not be eliminated by the sale of Texas Genco and were excluded from income from discontinued operations and reflected as general corporate overhead of CenterPoint Energy in income from continuing operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, "Accounting for the Impairment or Disposal of Long-Lived Assets" (SFAS No. 144). The Interim Financial Statements present these operations as discontinued operations in accordance with SFAS No. 144. Interest expense of $12 million and $24 million for the three and six months ended June 30, 2004, respectively, was reclassified to discontinued operations of Texas Genco related to the applicable amounts of CenterPoint Energy's term loan and revolving credit facility debt that would have been assumed to be paid off with any proceeds from the sale of Texas Genco during those respective periods in accordance with SFAS No. 144. 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 Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Future Earnings" in Item 7 of Part II of the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2004 (CenterPoint Energy Form 10-K), which is incorporated herein by reference, and "Risk Factors" in Item 5 of Part II of this report beginning on page 52. 40

LIQUIDITY AND CAPITAL RESOURCES HISTORICAL CASH FLOWS The following table summarizes the net cash provided by (used in) operating, investing and financing activities from continuing operations for the six months ended June 30, 2004 and 2005: SIX MONTHS ENDED JUNE 30, ----------------------------- 2004 2005 ----------- ----------- (IN MILLIONS) Cash provided by (used in): Operating activities.......................... $ 476 $ 106 Investing activities.......................... (188) 398 Financing activities.......................... (278) (260) CASH PROVIDED BY OPERATING ACTIVITIES Net cash provided by operating activities in the first six months of 2005 decreased $370 million compared to the same period in 2004 primarily due to increased tax payments of $423 million, the majority of which related to the tax payment associated with the sale of Texas Genco, offset by increased operating income, higher net accounts receivable/payable due to higher gas prices in 2005 as compared to 2004 and the termination of excess mitigation credits effective April 29, 2005. CASH PROVIDED BY INVESTING ACTIVITIES Net cash provided by investing activities increased $586 million in the first six months of 2005 as compared to the same period in 2004 primarily due to $700 million in proceeds received from the sale of our remaining interest in Texas Genco, partially offset by increased capital expenditures of $92 million and the absence of a dividend from Texas Genco in 2005. CASH USED IN FINANCING ACTIVITIES In the first six months of 2005, debt payments exceeded net loan proceeds by $186 million. During the first six months of 2004, debt payments exceeded net loan proceeds by $224 million. FUTURE SOURCES AND USES OF CASH Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the last six months of 2005 include the following: - approximately $419 million of capital expenditures; - dividend payments on CenterPoint Energy common stock and debt service payments; and - $1.7 billion of maturing long-term debt, including $31 million of transition bonds and $325 million of CERC's senior notes which were repaid in July 2005. We expect that borrowings under our credit facilities and anticipated cash flows from operations will be sufficient to meet our cash needs for 2005. Cash needs may also be met by issuing securities in the capital markets. CenterPoint Houston's $1.31 billion term loan, maturing in November 2005, requires the proceeds from the issuance of transition bonds to be used to reduce the term loan unless refused by the lenders. CenterPoint Houston's $1.31 billion credit facility may be utilized to refinance the $1.31 billion term loan at maturity. Under this facility, CenterPoint Houston must repay borrowings under the facility with (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston. The 1935 Act regulates our financing ability, as more fully described in " - -- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below. 41

Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. CERC Corp. has a bankruptcy remote subsidiary, which we consolidate, which was formed for the sole purpose of buying receivables created by CERC 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 June 30, 2005, CERC had $181 million of advances under its receivables facility. Credit Facilities. In June 2005, CERC Corp. 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. In March 2005, we replaced our $750 million revolving credit facility with a $1 billion five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 100 basis points based on current credit ratings. An additional utilization fee of 12.5 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. The facility contains covenants, including a debt to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant and an EBITDA to interest covenant. Borrowings under our credit facility are available upon customary terms and conditions for facilities of this type, including a requirement that we represent, except as described below, that no "material adverse change" has occurred at the time of a new borrowing under this facility. A "material adverse change" is defined as the occurrence of a material adverse change in our ability to perform our obligations under the facility but excludes any litigation related to the True-Up Order. The base line for any determination of a relative material adverse change is our most recently audited financial statements. At any time after the first time our credit ratings reach at least BBB by Standard & Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and Baa2 by Moody's Investors Service, Inc. (Moody's), BBB+ by S&P and Baa3 by Moody's, or BBB- by S&P and Baa1 by Moody's, or if the drawing is to retire maturing commercial paper, we are not required to represent as a condition to such drawing that no material adverse change has occurred or that no litigation expected to have a material adverse effect has occurred. Due to restrictions imposed on us under our June 29, 2005 financing order under the 1935 Act, we may not be able to draw the full amount of our credit agreement without further authorization from the SEC because such borrowings would reduce our common equity capitalization ratio below its level as of March 31, 2005. We do not expect this limitation to constrain our borrowings beyond the end of 2005 based on current projections. Additionally, these restrictions will no longer be applicable upon the effective date of the repeal of the 1935 Act. For a discussion of these restrictions, see "-- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" below. Also in March 2005, CenterPoint Houston established a $200 million five-year revolving credit facility. Borrowings may be made under the facility at LIBOR plus 75 basis points based on CenterPoint Houston's current credit rating. An additional utilization fee of 12.5 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. CenterPoint Houston also established a $1.31 billion credit facility in March 2005. This facility is available to be utilized only to refinance CenterPoint Houston's $1.31 billion term loan maturing in November 2005 in the event that proceeds from the issuance of transition bonds are not sufficient to repay such term loan. Due to the pending appeal of the Texas Utility Commission's financing order, it is unlikely that proceeds from the sale of transition bonds would be received prior to November 2005. Drawings may be made under this credit facility until November 2005, at which time any outstanding borrowings are converted to term loans maturing in November 2007. Under this facility, (i) 100% of the net proceeds from the issuance of transition bonds and (ii) the proceeds, in excess of $200 million, from certain other new net indebtedness for borrowed money incurred by CenterPoint Houston must be 42

used to repay borrowings under the facility. Based on CenterPoint Houston's current credit ratings, borrowings under the facility may be made at LIBOR plus 75 basis points. The interest rate under the term loan which this facility would replace is LIBOR plus 975 basis points Changes in credit ratings could lower or raise the increment to LIBOR depending on whether ratings improved or were lowered. Any drawings under this facility must be secured by CenterPoint Houston's general mortgage bonds in the same principal amount and bearing the same interest rate as such drawings. CERC Corp.'s $400 million credit facility contains covenants, including a total debt to capitalization covenant of 65% and an EBITDA to interest covenant. CenterPoint Houston's $200 million and $1.31 billion credit facilities each contain covenants, including a debt (excluding transition bonds) to total capitalization covenant of 68% and an EBITDA to interest covenant. Borrowings under CERC Corp.'s $400 million credit facility and CenterPoint Houston's $200 million credit facility and its $1.31 billion 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 August 1, 2005, we had the following credit facilities (in millions): AMOUNT UTILIZED AT DATE EXECUTED COMPANY SIZE OF FACILITY AUGUST 1, 2005 TERMINATION DATE - ------------- ------------------- ---------------- ------------------ ---------------- March 7, 2005 CenterPoint Energy $ 1,000 $ 152(1) March 7, 2010 March 7, 2005 CenterPoint Houston 200 -- March 7, 2010 March 7, 2005 CenterPoint Houston 1,310 -- (2) June 30, 2005 CERC Corp. 400 -- June 30, 2010 - ---------- (1) Includes $27 million of outstanding letters of credit and $125 million of commercial paper backstopped by the credit facility. (2) Revolver until November 2005 with two-year term-out of borrowed moneys. The $1 billion CenterPoint Energy credit facility backstops a $1 billion commercial paper program under which CenterPoint Energy began issuing commercial paper in June 2005. No commercial paper was outstanding as of June 30, 2005. The commercial paper is rated "Not Prime" by Moody's, "A-3" by S&P and "F3" by Fitch, Inc. (Fitch). We cannot assure you that these ratings, or the credit ratings set forth below in " - - Impact on Liquidity of a Downgrade in Credit Ratings," will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities 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 and the execution of our commercial strategies. Securities Registered with the SEC. At June 30, 2005, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $1 billion and CERC Corp. had a shelf registration statement covering $50 million principal amount of debt securities. Temporary Investments. On June 30, 2005, we had temporary investments of $366 million. CERC Corp.'s temporary external investments were reduced by $325 million in July 2005 when the proceeds from the liquidation of such investments were used to pay maturing debt of CERC Corp. As of August 1, 2005, CERC Corp. had temporary investments in a money market fund of $9 million. Such investments may be utilized to meet the cash flow needs of CERC Corp. Money Pool. We have a "money pool" through which our participating subsidiaries 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 net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy's revolving credit facility. 43

The terms of the money pool are in accordance with requirements applicable to registered public utility holding companies under the 1935 Act and under an order from the SEC relating to our financing activities and those of our subsidiaries on June 29, 2005 (June 2005 Financing Order). This order expires in June 2008. Impact on Liquidity of a Downgrade in Credit Ratings. On July 22, 2005, Moody's upgraded certain of our credit ratings, including our senior unsecured debt to Ba1 from Ba2. Moody's also upgraded the ratings of CERC Corp., including its senior unsecured debt to Baa3 from Bal. These rating actions concluded the review for possible upgrade that was initiated on March 24, 2005. As of August 1, 2005, Moody's, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries: MOODY'S S&P FITCH ------------------- ------------------- ------------------- COMPANY/INSTRUMENT RATING OUTLOOK(1) RATING OUTLOOK(2) RATING OUTLOOK(3) - ------------------ ------ ---------- ------ ---------- ------ ---------- CenterPoint Energy Senior Unsecured Debt........... Ba1 Stable BBB- Negative BBB- Stable CenterPoint Houston Senior Secured Debt (First Mortgage Bonds).................................. Baa2 Stable BBB Negative BBB+ Stable CERC Corp. Senior Debt............................. Baa3 Stable BBB Negative 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. A decline in credit ratings could increase borrowing costs under our $1 billion credit facility, CenterPoint Houston's $200 million credit facility and its $1.31 billion credit facility and CERC's $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. If we were unable to maintain an investment-grade rating from at least one rating agency, as a registered public utility holding company we would be required to obtain further approval from the SEC for any additional capital markets transactions as more fully described in " -- Certain Contractual and Regulatory Limits on Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock" 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 revolving credit facility contains a "material adverse change" clause that could impact our ability to make new borrowings under this facility. CenterPoint Houston's $200 million credit facility, CenterPoint Houston's $1.3 billion facility and CERC Corp.'s $400 million credit facility do not contain material adverse change clauses with respect to borrowings. In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. Each ZENS note is exchangeable at the holder's option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW Common equal to 100% of the reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged and TW Common shares are sold. CenterPoint Energy Services, Inc. (formerly CenterPoint Energy Gas Services, Inc.) (CES), a wholly owned subsidiary of CERC Corp., 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 44

estimate that as of June 30, 2005, unsecured credit limits extended to CES by counterparties could aggregate $105 million; however, utilized credit capacity is significantly lower. In addition, CERC and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC's 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 our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. Pursuant to the indenture governing our senior notes, a payment default by us, CERC Corp. or CenterPoint Houston 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 August 1, 2005, we had issued five 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 subsidiaries' 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: - cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment, particularly given gas price levels and volatility; - acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of suppliers; - increased costs related to the acquisition of gas for storage; - increases in interest expense in connection with debt refinancings and borrowings under credit facilities; - various regulatory actions; - the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI's indemnity obligations to us and our subsidiaries; and - various other risks identified in "Risk Factors" in Item 5 of Part II of this report beginning on page 52. Certain Contractual and Regulatory Limits on Our Ability to Issue Securities, Borrow Money and Pay Dividends on Our Common Stock. The secured term loan and each of the credit facilities of CenterPoint Houston limits CenterPoint Houston's debt, excluding transition bonds, as a percentage of its total capitalization to 68%. CERC Corp.'s bank facility and its receivables facility limit CERC's debt as a percentage of its total capitalization to 65% and 60%, respectively, and contain an EBITDA to interest covenant. Our $1 billion credit facility contains a debt to EBITDA covenant and an EBITDA to interest covenant. CenterPoint Houston's $1.31 billion and $200 million credit facilities also contain an EBITDA to interest covenant. We are a registered public utility holding company under the 1935 Act. The 1935 Act and related rules and regulations impose a number of restrictions on our activities and those of our subsidiaries. The 1935 Act, among other things, limits our ability and the ability of our regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. On July 29, 2005 Congress passed the Energy Act, which President Bush is expected to sign in early August. Under that legislation, the 1935 Act is repealed six months after the enactment of the Energy Act. After the effective date of repeal, we and our subsidiaries will no longer be subject to restrictions imposed under the 1935 Act. Until the repeal is effective, we and our 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 transfers to the FERC certain functions 45

performed by the SEC under the 1935 Act, including the requirement that holding companies and their subsidiaries maintain certain books and records and make them available for review by FERC and, through FERC, to state regulatory authorities. The Energy Act requires FERC to issue regulations to implement its jurisdiction under the Energy Act. It is presently unknown what, if any, specific obligations under those rules may be imposed on us and our subsidiaries as result of that rulemaking. The June 2005 Financing Order is effective until June 30, 2008. This order establishes limits on the amount of external debt and equity securities that can be issued by us and our regulated subsidiaries without additional authorization but generally permits us to refinance our existing obligations and those of our regulated subsidiaries. Each of us and our subsidiaries is in compliance with the authorized limits. Discussed below are the incremental amounts of debt and equity that we are authorized to issue. The order also generally permits utilization of undrawn credit facilities at CenterPoint Energy, CenterPoint Houston and CERC. However, due to the restrictions contained in the order regarding our equity level as described below, we may be unable to draw the full amount of our credit agreement for other than refinancing purposes without further authorization from the SEC. We do not expect this limitation to constrain our borrowings beyond the end of 2005 based on current projections. Unless we obtain a further order from the SEC, as of July 31, 2005: - We are not authorized to issue any additional debt or preferred securities; - CenterPoint Houston is authorized to issue an aggregate $16 million of debt or preferred securities; and - CERC is 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 our common equity ratio falls below its level as of March 31, 2005 (11.4%, net of securitization debt) or if the common equity ratio of either CERC or CenterPoint Houston (net of securitization debt) falls below 30%. Among the other transactions over which the SEC reserved jurisdiction are: (i) issuance of securities by us or any of our subsidiaries 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 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 our common equity is less than 30% of our 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 by each of us, CenterPoint Houston and CERC. 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 revolving credit facilities, are: $4.334 billion for us, $4.280 billion for CenterPoint Houston and $3.256 billion for CERC. 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 the effective date of repeal of the 1935 Act. 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. As discussed above, the SEC has reserved jurisdiction over payment of $300 million of dividends from CenterPoint Energy's unearned surplus or capital. Further authorization would be required to make those payments. As of June 30, 2005, we had a retained deficit on our Consolidated Balance Sheet. On January 26, 2005, our board of directors declared a dividend of $0.10 per share of common stock payable on March 10, 2005 to shareholders of record as of the close of business on February 16, 2005. On March 3, 2005, our board of directors declared a dividend of $0.10 per share of common stock payable on March 31, 2005 to shareholders of record as of the close of business on March 16, 2005. This additional first quarter 46

dividend was declared in lieu of the regular second quarter dividend to address technical restrictions that might have limited our ability to pay a regular dividend during the second quarter of this year. Due to the limitations imposed under the 1935 Act, we may declare and pay dividends only from earnings in the specific quarter in which the dividend is paid, absent specific authorization from the SEC approving payment of the quarterly dividend from capital or unearned surplus. There can be no assurance, however, that the SEC would authorize such payments. As a result of the seasonal nature of our utility businesses, the first quarter is generally the strongest quarter for our gas distribution business. On June 2, 2005, our board of directors declared a dividend of $0.07 per share of common stock payable on June 30, 2005 to shareholders of record as of the close of business on June 15, 2005. Although dividends are subject to consideration and approval of our Board of Directors, subject to the Board's determination, we currently intend to pay a 2005 annual dividend of $0.40 per share in keeping with our historic levels and subject to remaining in compliance with the dividend payment limitations imposed under the 1935 Act. In addition, the SEC generally expects registered holding companies to achieve a ratio of common equity to total capitalization of 30%. At June 30, 2005, our ratio was 13% (excluding transition bonds). Accordingly, we may issue equity and take other actions to achieve a future equity capitalization of 30%. The June 2005 Financing Order also requires that CenterPoint Houston and CERC maintain a ratio of common equity to total capitalization of 30%, although the SEC has permitted the percentage to be below this level for other companies taking into account non-recourse securitization debt as a component of capitalization. At June 30, 2005, their ratios were 43% (excluding transition bonds) and 53%, respectively. Other Factors Affecting the Upstreaming of Cash from Subsidiaries. CenterPoint Houston's term loan, subject to certain exceptions, limits the application of proceeds, in excess of $200 million, from capital markets transactions and certain other borrowing transactions by CenterPoint Houston to repayment of debt existing in November 2002. CenterPoint Houston plans to distribute recovery of the true-up components not used to repay CenterPoint Houston's indebtedness to us through the payment of dividends. CenterPoint Houston requires SEC action to approve any dividends in excess of its current and retained earnings. To maintain CenterPoint Houston's capital structure at the appropriate levels, we may reinvest funds in CenterPoint Houston in the form of equity contributions or intercompany loans. CRITICAL ACCOUNTING POLICIES A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements in the CenterPoint Energy Form 10-K (CenterPoint Energy 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. ACCOUNTING FOR RATE REGULATION SFAS No. 71, "Accounting for the Effects of Certain Types of Regulation" (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the 47

competitive environment makes it probable that such rates can be charged and collected. Application of SFAS No. 71 to the electric generation portion of our business was discontinued as of June 30, 1999. Our Electric Transmission & Distribution business continues to apply SFAS No. 71 which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $2.1 billion of recoverable electric generation-related regulatory assets as of June 30, 2005. These costs are recoverable under the provisions of the Texas electric restructuring law. Based on our analysis of the True-Up Order, we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write-down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in the second quarter of 2005. 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." No impairment of goodwill was indicated based on our analysis as of January 1, 2005. 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. UNBILLED ENERGY REVENUES Revenues related to the sale and/or delivery of electricity or natural gas (energy) are generally recorded when energy is delivered to customers. However, the determination of energy 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 energy delivered to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electricity delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. 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. PENSION AND OTHER RETIREMENT PLANS We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors which attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates to estimate these factors. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Other Significant 48

Matters -- Pension Plan" in Item 7 of the CenterPoint Energy Form 10-K, which is incorporated herein by reference, for further discussion. NEW ACCOUNTING PRONOUNCEMENTS See Note 4 to the Interim Financial Statements for a discussion of new accounting pronouncements that affect us. ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK COMMODITY PRICE RISK We assess the risk of our non-trading derivatives (Energy Derivatives) using a sensitivity analysis method. The sensitivity analysis performed on our Energy Derivatives measures the potential loss based on a hypothetical 10% movement in energy prices. A decrease of 10% in the market prices of energy commodities from their June 30, 2005 levels would have decreased the fair value of our Energy Derivatives from their levels on that date by $42 million. The above analysis of the Energy Derivatives utilized for hedging purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. The Energy Derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of Energy Derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above would be offset by a favorable impact on the underlying hedged physical transactions. INTEREST RATE RISK We have outstanding long-term debt, bank loans, mandatory redeemable preferred securities of subsidiary trusts holding solely our junior subordinated debentures (trust preferred securities), some lease obligations and our obligations under the ZENS that subject us to the risk of loss associated with movements in market interest rates. Our floating-rate obligations aggregated $1.4 billion at June 30, 2005. If the floating rates were to increase by 10% from June 30, 2005 rates, our combined interest expense to third parties would increase by a total of $1 million each month in which such increase continued. At June 30, 2005, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $7.3 billion in principal amount and having a fair value of $8.0 billion. These instruments are fixed-rate and, therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of these instruments would increase by approximately $330 million if interest rates were to decline by 10% from their levels at June 30, 2005. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity. As discussed in Note 6 to the CenterPoint Energy Notes, which note is incorporated herein by reference, upon adoption of SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $108 million at June 30, 2005 is a fixed-rate obligation and, therefore, does not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $17 million if interest rates were to decline by 10% from levels at June 30, 2005. Changes in the fair value of the derivative component will be recorded in our Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from June 30, 2005 levels, the fair value of the derivative component would increase by approximately $5 million, which would be recorded as a loss in our Statements of Consolidated Income. 49

EQUITY MARKET VALUE RISK We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 6 to the CenterPoint Energy Notes for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. A decrease of 10% from the June 30, 2005 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as a loss in our Statements of Consolidated Income. ITEM 4. CONTROLS AND PROCEDURES In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of June 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 June 30, 2005 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting. 50

PART II. OTHER INFORMATION ITEM 1. LEGAL PROCEEDINGS For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 5 and 11 to our Interim Financial Statements, "Business -- Regulation" and " -- Environmental Matters" in Item 1 of the CenterPoint Energy Form 10-K, "Legal Proceedings" in Item 3 of the CenterPoint Energy Form 10-K and Notes 4 and 11 to the CenterPoint Energy Notes, each of which is incorporated herein by reference. ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS At the annual meeting of our shareholders held on June 2, 2005, the matters voted upon and the number of votes cast for, against or withheld, as well as the number of abstentions and broker non-votes as to such matters (including a separate tabulation with respect to each nominee for office), were as stated below: The following nominee for Class II Director was elected to serve a two-year term expiring at the 2007 annual meeting of shareholders (there were no broker non-votes): Nominees For Withheld - ------------------ ----------- --------- Donald R. Campbell 265,325,027 7,792,138 The following nominees for Class III Directors were elected to serve three-year terms expiring at the 2008 annual meeting of shareholders (there were no broker non-votes): Nominees For Withheld - -------------------- ------------ ---------- O.Holcombe Crosswell 264,903,882 8,213,283 Janiece M. Longoria 265,054,353 8,062,812 Thomas F. Madison 261,154,423 11,962,742 Peter S. Wareing 265,285,881 7,831,284 Milton Carroll, John T. Cater, Derrill Cody, David M. McClanahan, Robert T. O'Connell and Michael E. Shannon all continue as directors of CenterPoint Energy. The appointment of Deloitte & Touche LLP as independent accountants and auditors for CenterPoint Energy for 2005 was ratified with 265,528,363 votes for, 5,030,610 votes against, 2,558,192 abstentions and no broker non-votes. The shareholder proposal regarding the future elections of directors annually and not by classes did not receive the required affirmative vote of a majority of the shares of common stock represented at the meeting. The proposal received 75,913,485 votes against, 121,446,825 votes for, 6,448,977 abstentions and 69,307,877 broker non-votes. 51

ITEM 5. OTHER INFORMATION RISK FACTORS We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries: RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN TIMELY RECOVERING THE FULL VALUE OF ITS TRUE-UP COMPONENTS, WHICH COULD HAVE AN ADVERSE IMPACT ON CENTERPOINT HOUSTON'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. On March 31, 2004, CenterPoint Houston filed the final true-up application required by the Texas electric restructuring law with the Texas Utility Commission. CenterPoint Houston's requested true-up balance was $3.7 billion, excluding interest and net of the retail clawback payable to CenterPoint Houston by a former affiliate. In December 2004, the Texas Utility Commission approved a final order in CenterPoint Houston's true-up proceeding authorizing CenterPoint Houston to recover $2.3 billion including interest through August 31, 2004, subject to adjustments to reflect the benefit of certain deferred taxes and the accrual of interest and payment of excess mitigation credits after August 31, 2004. In January 2005, we appealed certain aspects of the final order seeking to increase the true-up balance ultimately recovered by CenterPoint Houston. Other parties have also appealed the order, seeking to reduce the amount authorized for CenterPoint Houston's recovery. No prediction can be made as to the ultimate outcome or timing of such appeals. A failure by CenterPoint Houston to recover the full value of its true-up components may have an adverse impact on CenterPoint Houston's results of operations, financial condition and cash flows. CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL ELECTRIC PROVIDERS, AND ANY DELAY OR DEFAULT IN PAYMENT COULD ADVERSELY AFFECT CENTERPOINT HOUSTON'S CASH FLOWS, FINANCIAL CONDITION AND RESULTS OF OPERATIONS. CenterPoint Houston's receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with approximately 63 retail electric providers. Adverse economic conditions, structural problems in the market served by the Electric Reliability Council of Texas, Inc. (ERCOT) or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston's services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit payments on a timely basis. Any delay or default in payment could adversely affect CenterPoint Houston's cash flows, financial condition and results of operations. RRI, through its subsidiaries, is CenterPoint Houston's largest customer. Approximately 64% of CenterPoint Houston's $154 million in billed receivables from retail electric providers at June 30, 2005 was owed by subsidiaries of RRI. RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY CENTERPOINT HOUSTON'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS. CenterPoint Houston's rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its 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 CenterPoint Houston's costs and enable CenterPoint Houston to earn a reasonable return on its invested capital. DISRUPTIONS AT POWER GENERATION FACILITIES OWNED BY THIRD PARTIES COULD INTERRUPT CENTERPOINT HOUSTON'S SALES OF TRANSMISSION AND DISTRIBUTION SERVICES. CenterPoint Houston depends on power generation facilities owned by third parties to provide retail electric providers with electric power which it transmits and distributes to customers of the retail electric providers. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if 52

power generation capacity is inadequate, CenterPoint Houston's services may be interrupted, and its results of operations, financial condition and cash flows may be adversely affected. CENTERPOINT HOUSTON'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A significant portion of CenterPoint Houston's revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston's revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months. RISK FACTORS AFFECTING OUR NATURAL GAS DISTRIBUTION AND PIPELINES AND GATHERING BUSINESSES RATE REGULATION OF CERC'S BUSINESS MAY DELAY OR DENY CERC'S ABILITY TO EARN A REASONABLE RETURN AND FULLY RECOVER ITS COSTS. CERC's rates for its local distribution companies are regulated by certain municipalities and state commissions based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its 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 CERC's costs and enable CERC to earn a reasonable return on its invested capital. CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, WHICH COULD LEAD TO LESS NATURAL GAS BEING MARKETED, AND ITS 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 OF WHICH COULD HAVE AN ADVERSE IMPACT ON CERC'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS. CERC competes 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 CERC 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 CERC's facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC's results of operations, financial condition and cash flows. CERC's two interstate pipelines and its 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 CERC's competitors could lead to lower prices, which may have an adverse impact on CERC's results of operations, financial condition and cash flows. CERC'S NATURAL GAS DISTRIBUTION BUSINESS IS SUBJECT TO FLUCTUATIONS IN NATURAL GAS PRICING LEVELS, WHICH COULD AFFECT THE ABILITY OF CERC'S SUPPLIERS AND CUSTOMERS TO MEET THEIR OBLIGATIONS. CERC is subject to risk associated with price movements of natural gas. Movements in natural gas prices might affect CERC's ability to collect balances due from its customers and, on the regulated side, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC's 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 CERC operates and increase the risk that CERC's suppliers or customers fail or are unable to meet their obligations. Additionally, increasing gas prices could create the need for CERC to provide collateral in order to purchase gas. IF CERC WERE TO FAIL TO EXTEND A CONTRACT WITH ONE OF ITS SIGNIFICANT PIPELINE CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS. CERC's contract with Laclede Gas Company, one of its 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 53

less than the rates provided in the current contract, there could be an adverse effect on CERC's results of operations, financial condition and cash flows. A DECLINE IN CERC'S CREDIT RATING COULD RESULT IN CERC'S HAVING TO PROVIDE COLLATERAL IN ORDER TO PURCHASE GAS. If CERC's credit rating were to decline, it 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 CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC might be unable to obtain the necessary natural gas to meet its contractual distribution obligations, and its results of operations, financial condition and cash flows would be adversely affected. CERC'S INTERSTATE PIPELINES' AND NATURAL GAS GATHERING AND PROCESSING BUSINESS' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO FLUCTUATIONS IN THE SUPPLY OF GAS. CERC's 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 CERC's results of operations, financial condition and cash flows. CERC'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL. A substantial portion of CERC's revenues is derived from natural gas sales and transportation. Thus, CERC's 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 June 30, 2005, we had $8.8 billion of outstanding indebtedness on a consolidated basis. As of June 30, 2005, approximately $1.8 billion principal amount of this debt must be paid through 2006, excluding principal repayments of approximately $85 million on transition bonds. The success of our future financing efforts may depend, at least in part, on: - the timing and amount of our recovery of the true-up components; - general economic and capital market conditions; - credit availability from financial institutions and other lenders; - investor confidence in us and the market in which we operate; - maintenance of acceptable credit ratings; - market expectations regarding our future earnings and probable cash flows; - market perceptions of our ability to access capital markets on reasonable terms; - our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; - 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. As of June 30, 2005, our CenterPoint Houston subsidiary had $3.3 billion principal amount of general mortgage bonds outstanding and $253 million of first mortgage bonds outstanding. It may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Although approximately $600 million of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of June 30, 2005, CenterPoint Houston has agreed under the $1.3 billion collateralized term loan maturing in November 2005 to not issue, subject to certain exceptions, more than $200 million of any incremental secured or unsecured debt. In addition, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds. CenterPoint Houston's $1.3 54

billion credit facility requires that proceeds from the issuance of transition bonds and certain new net indebtedness for borrowed money issued by CenterPoint Houston in excess of $200 million be used to repay borrowings under such facility. Our capital structure and liquidity will be affected significantly by the securitization of approximately $1.8 billion of costs authorized for recovery in our proceeding regarding the transition to competitive retail markets in Texas. Our current credit ratings are discussed in "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Liquidity and Capital Resources -- Future Sources and Uses of Cash -- 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. AS A HOLDING COMPANY WITH NO OPERATIONS OF OUR OWN, WE WILL DEPEND ON DISTRIBUTIONS FROM OUR SUBSIDIARIES TO MEET OUR PAYMENT OBLIGATIONS, AND PROVISIONS OF APPLICABLE LAW OR CONTRACTUAL RESTRICTIONS COULD LIMIT THE AMOUNT OF THOSE DISTRIBUTIONS. We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends and those under the 1935 Act, limit their ability to make payments or other distributions to us, and they could agree to contractual restrictions on their ability to make distributions. Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary's creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us. AN INCREASE IN SHORT-TERM INTEREST RATES COULD ADVERSELY AFFECT OUR CASH FLOWS AND EARNINGS. As of June 30, 2005, we had $1.4 billion of outstanding floating-rate debt owed to third parties. The interest rate spreads on such debt are substantially above our historical interest rate spreads. In addition, any floating-rate debt issued by us in the future could be at interest rates substantially above our historical borrowing rates. An increase in short-term interest rates could result in higher interest costs and could adversely affect our results of operations, financial condition and cash flows. 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 and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity and financial market risks. We and our subsidiaries 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. 55

OTHER RISKS WE AND CENTERPOINT HOUSTON COULD INCUR LIABILITIES ASSOCIATED WITH BUSINESSES AND ASSETS THAT WE HAVE TRANSFERRED TO OTHERS. Under some circumstances, we and CenterPoint Houston could incur liabilities associated with assets and businesses we and CenterPoint Houston no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated directly or through subsidiaries and include: - those transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and - those transferred to Texas Genco in connection with its organization and capitalization. In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy, Incorporated transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. The indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy, Incorporated has not been released from the liability in connection with the transfer, we or CenterPoint Houston could be responsible for satisfying the liability. RRI's unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI's creditors might be made against us as its former owner. Reliant Energy, Incorporated and RRI are named as defendants in a number of lawsuits arising out of power sales in California and other West Coast markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy, Incorporated have been made on grounds that include the effect of RRI's financial results on Reliant Energy, Incorporated's historical financial statements and liability of Reliant Energy, Incorporated as a controlling shareholder of RRI. We or CenterPoint Houston could incur liability if claims in one or more of these lawsuits were successfully asserted against us or CenterPoint Houston and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims. In connection with the organization and capitalization of Texas Genco, Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy, Incorporated transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were held by CenterPoint Houston and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. In connection with the sale of Texas Genco's fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the separation agreement we entered into with Texas Genco in connection with the organization and capitalization of Texas Genco was amended to provide that all of Texas Genco's rights and obligations under the separation agreement relating to its fossil generation assets, including Texas Genco's obligation to indemnify us with respect to liabilities associated with the fossil generation assets and related business, were assigned to and assumed by Texas Genco LLC. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and CenterPoint Energy has assumed and agreed to indemnify Texas Genco LLC against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy, 56

Incorporated had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability. WE, TOGETHER WITH OUR SUBSIDIARIES, ARE SUBJECT TO REGULATION UNDER THE 1935 ACT. THE 1935 ACT AND RELATED RULES AND REGULATIONS IMPOSE A NUMBER OF RESTRICTIONS ON OUR ACTIVITIES. We and our subsidiaries are subject to regulation by the SEC under the 1935 Act. The 1935 Act, among other things, limits the ability of a holding company and its regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliated service, sales and construction contracts. We received an order from the SEC under the 1935 Act on June 29, 2005 relating to our 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. Under this order, we may not be able to fully utilize our credit facility without prior approval. If our earnings for subsequent quarters are insufficient to pay dividends from current earnings, additional authority would be required from the SEC for payment of the quarterly dividend from capital or unearned surplus, and the SEC may not authorize such payments. The United States Congress has passed legislation, which President Bush is expected to sign in early August, that 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. In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to, its transmission and distribution properties, it may not be able to recover such loss or damage through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows. 57

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 of CenterPoint Energy, Inc. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ------------------------------------- ---------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles CenterPoint Energy's Registration 3-69502 3.1 of Incorporation of CenterPoint Statement on Form S-4 Energy 3.1.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for 1-31447 3.1.1 and Restated Articles of the year ended December 31, 2001 Incorporation of CenterPoint Energy 3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for 1-31447 3.2 CenterPoint Energy the year ended December 31, 2001 3.3 -- Statement of Resolution CenterPoint Energy's Form 10-K for 1-31447 3.3 Establishing Series of Shares the year ended December 31, 2001 designated Series A Preferred Stock of CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock CenterPoint Energy's Registration 3-69502 4.1 Certificate Statement on Form S-4 4.2 -- Rights Agreement dated January CenterPoint Energy's Form 10-K for 1-31447 4.2 1, 2002, between CenterPoint the year ended December 31, 2001 Energy and JPMorgan Chase Bank, as Rights Agent Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-Q certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ------------------------------------- -------------------------------------- ------------ --------- 4.3.1 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 10-K for 1-31447 4(g)(1) dated as of November 12, 2002, the year ended December 31, 2002 among CenterPoint Houston and the banks named therein 4.3.2 -- First Amendment to Exhibit 4.1.1, CenterPoint Energy's Form 10-Q for the 1-31447 10.7 dated as of September 3, 2003 quarter ended September 30, 2003 4.3.3 -- Pledge Agreement, dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2) November 12, 2002 executed in year ended December 31, 2002 connection with Exhibit 4.1.1 4.4 -- $1,000,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.1 dated as of March 7, 2005, among March 7, 2005 CenterPoint Energy and the banks named therein 4.5 -- $400,000,000 Credit Agreement, CenterPoint Energy's Form 8-K dated 1-31447 4.1 dated as of June 30, 2005, among June 29, 2005 CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders 58

SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ------------------------------------- -------------------------------------- ------------ --------- 4.6 -- $200,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.2 dated as of March 7, 2005 among March 7, 2005 CenterPoint Houston and the banks named therein 4.7 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.3 dated as of March 7, 2005 among March 7, 2005 CenterPoint Houston and the banks named therein +10.1 -- City of Houston Franchise Ordinance +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 -- Eleventh Amendment to CenterPoint Energy, Inc. Retirement Plan, effective as of May 1, 2005 +99.2 -- Twelfth Amendment to CenterPoint Energy, Inc. Retirement Plan, effective as of June 1, 2005 +99.3 -- Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1 "Business -- Regulation," " -- Environmental Matters," Item 3 "Legal Proceedings," Item 7 "Management's Discussion and Analysis of Financial Condition and Results of Operations -- Certain Factors Affecting Future Earnings" and " -- Other Significant Matters -- Pension Plan" and Notes 2(d) (Long-Lived Assets and Intangibles), 2(e) (Regulatory Assets and Liabilities), 4 (Regulatory Matters), 5 (Derivative Instruments), 6 (Indexed Debt Securities (ZENS) and Time Warner Securities) and 11 (Commitments and Contingencies) 59

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, INC. By: /s/ James S. Brian ------------------------------- James S. Brian Senior Vice President and Chief Accounting Officer Date: August 8, 2005 60

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 of CenterPoint Energy, Inc. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ------------------------------------- ---------------------------------- ------------ --------- 3.1.1 -- Amended and Restated Articles CenterPoint Energy's Registration 3-69502 3.1 of Incorporation of CenterPoint Statement on Form S-4 Energy 3.1.2 -- Articles of Amendment to Amended CenterPoint Energy's Form 10-K for 1-31447 3.1.1 and Restated Articles of the year ended December 31, 2001 Incorporation of CenterPoint Energy 3.2 -- Amended and Restated Bylaws of CenterPoint Energy's Form 10-K for 1-31447 3.2 CenterPoint Energy the year ended December 31, 2001 3.3 -- Statement of Resolution CenterPoint Energy's Form 10-K for 1-31447 3.3 Establishing Series of Shares the year ended December 31, 2001 designated Series A Preferred Stock of CenterPoint Energy 4.1 -- Form of CenterPoint Energy Stock CenterPoint Energy's Registration 3-69502 4.1 Certificate Statement on Form S-4 4.2 -- Rights Agreement dated January CenterPoint Energy's Form 10-K for 1-31447 4.2 1, 2002, between CenterPoint the year ended December 31, 2001 Energy and JPMorgan Chase Bank, as Rights Agent Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Energy has not filed as exhibits to this Form 10-Q certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of CenterPoint Energy and its subsidiaries on a consolidated basis. CenterPoint Energy hereby agrees to furnish a copy of any such instrument to the SEC upon request. SEC FILE OR EXHIBIT REGISTRATION EXHIBIT NUMBER DESCRIPTION REPORT OR REGISTRATION STATEMENT NUMBER REFERENCE - ------- ------------------------------------- -------------------------------------- ------------ --------- 4.3.1 -- $1,310,000,000 Credit Agreement CenterPoint Energy's Form 10-K for 1-31447 4(g)(1) dated as of November 12, 2002, the year ended December 31, 2002 among CenterPoint Houston and the banks named therein 4.3.2 -- First Amendment to Exhibit 4.1.1, CenterPoint Energy's Form 10-Q for the 1-31447 10.7 dated as of September 3, 2003 quarter ended September 30, 2003 4.3.3 -- Pledge Agreement, dated as of CenterPoint Energy's Form 10-K for the 1-31447 4(g)(2) November 12, 2002 executed in year ended December 31, 2002 connection with Exhibit 4.1.1 4.4 -- $1,000,000,000 Credit Agreement CenterPoint Energy's Form 8-K dated 1-31447 4.1 dated as of March 7, 2005, among March 7, 2005 CenterPoint Energy and the banks named therein 4.5 -- $400,000,000 Credit Agreement, CenterPoint Energy's Form 8-K dated 1-31447 4.1 dated as of June 30, 2005, among June 29, 2005 CERC Corp., as Borrower, and the Initial Lenders named therein, as Initial Lenders

EXHIBIT 10.1 CITY OF HOUSTON, TEXAS, ORDINANCE NO. 2005-692 AN ORDINANCE GRANTING TO CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC THE RIGHT, PRIVILEGE AND FRANCHISE TO USE THE PUBLIC RIGHTS-OF-WAY TO USE, LICENSE, OR EXPLOIT THE COMPANY'S FACILITIES WITHIN THE PUBLIC RIGHTS-OF-WAY TO CONDUCT AN ELECTRIC DELIVERY BUSINESS IN THE CITY AND FOR SUCH OTHER BUSINESS PURPOSES AS THE COMPANY MAY DESIRE FROM TIME TO TIME, SPECIFICALLY INCLUDING, BUT NOT LIMITED TO, THE GRANTING OF ACCESS TO THOSE FACILITIES FOR THE DELIVERY OF BROADBAND THROUGH POWER LINES OR SIMILAR SERVICE WITHIN THE CITY OF HOUSTON, TEXAS. * * * * * * WHEREAS, City of Houston, Texas Ordinance No. 1957-929 (the "1957 Franchise") granted an electrical lighting and power franchise to Houston Lighting & Power Company, for a term expiring August 21, 2007; and WHEREAS, Company is the successor to Reliant Energy, Incorporated.("REI"), which was the successor to Houston Lighting & Power Company, by virtue of a corporate restructuring of REI that occurred in August 2002, in which REI was merged with and into an indirect wholly owned subsidiary of CenterPoint Energy, Inc., which was converted into a limited liability company and was renamed CenterPoint Energy Houston Electric, LLC; and WHEREAS, Company owns and operates a electric delivery business within the corporate limits of the City and Company is willing to continue to provide electric delivery services within the corporate limits of the City; and WHEREAS, Company and the City have reached agreement on the terms and conditions of a renewal franchise; and WHEREAS, it is hereby found and determined by the City Council of the City of Houston that it is in the best interests of the City that a franchise to use the public rights-of-way to conduct an electric delivery business in the city and for such other business purposes as the company may desire from time to time be granted to the Company, subject to the terms and conditions described in this ordinance; NOW, THEREFORE, BE IT ORDAINED BY THE CITY COUNCIL OF THE CITY OF HOUSTON, TEXAS: SECTION 1. That the facts contained in the preamble to the Ordinance are determined to be true and correct and are hereby adopted. SECTION 2. Definitions. Annual Adjustment Factor has the meaning set forth in Section 11 below.

Annual Franchise Fee has the meaning set forth in Section 11 below. Base Amount has the meaning set forth in Section 11 below. Broadband over Power Lines (BPL) or "Access BPL" has the same meaning as that used by the Federal Communications Commission in Section 15.3 of its Rules as reprinted below: Access Broadband over Power Line (Access BPL). A carrier current system installed and operated on an electric utility service as an unintentional radiator that sends radio frequency energy on frequencies between 1.705 MHz and 80 MHz over medium voltage lines or over low voltage lines to provide broadband communications and Is located on the supply side of the utility service's points of interconnection with customer premises. Access BPL does not include power line carrier systems as defined in Section 15.3(t) of this part or In-House BPL as defined in Section 15.3(gg) of this part. City means the City of Houston, Texas, a municipal corporation of the State of Texas. City Council means the governing body of the City, or its designee. Company means CenterPoint Energy Houston Electric, LLC, a Texas limited liability company. Effective Date means the date on which this Franchise becomes effective pursuant to Section 4 below. First Rate Case has the meaning set forth in Section 14 below. Force Majeure means forces or conditions not reasonably within the control of a party, including a strike; war or act of war (whether an actual declaration of war is made or not); insurrection; riot; act of public enemy; accident; fire; flood or other act of God; sabotage; shortages in materials, supplies and equipment; governmental regulations, limitations and restrictions as to the use and availability of materials, supplies and equipment and as to the use of services; unforeseen and unusual demands for service; or other events, where the affected party has exercised all due care in the prevention thereof and such causes or other events are without the fault or negligence of the affected party. Franchise means this Ordinance and the rights and privileges granted by this Ordinance.

Franchise Area means the area within the boundaries of the City as of the Effective Date and as same may change from time to time during the term of the Franchise. Other Services means any service exclusive of the transmission and distribution of electricity provided or allowed to be provided through the use or license of the System for a fee, including but not limited to BPL. Person means any individual, firm, partnership, association, corporation, company or organization of any kind. Public Rights-of-Way means the areas in, under, upon, over, across, and along any and all of the present and future Streets or streams now or hereafter owned or controlled by City. PUC means the Public Utility Commission of Texas or its successor agency with equivalent jurisdiction. Retail Customer means any Person taking delivery of electricity from Company, at a point of delivery within the Franchise Area. Rider HOU Amount has the meaning set forth in Section 11 below. Street means the surface and the space above and below any public street, road, highway, alley, bridge, sidewalk, or other public place or way. System means the Company's facilities erected, constructed, maintained, operated, used, extended, removed, replaced, and repaired, as necessary, by Company pursuant to this Franchise, including without limitation, all poles, pole lines, towers, transmission lines, wires, guys, conduits, cables, and other desirable instrumentalities and appurtenances (including telegraph and telephone poles and wires for use of Company), necessary and proper for the purpose of transmitting and distributing electricity to the City and the inhabitants of said City or other Persons, for any purpose for which electricity may be used. Tracking Rider has the meaning set forth in Section 14 below. SECTION 3. Subject to the terms, conditions and provisions of this Franchise, City hereby grants to Company the right, privilege and franchise to use City's Public Rights-of-Way to construct, maintain, operate and use Company's System to conduct within the City an electric delivery business and the right to use, license, or exploit the System within the Public Rights-of-Way for Other Services. This Franchise does not restrict City's right to impose reasonable fees upon third parties for the use of the Public Rights-of-Way to provide Other Services, including the right to impose fees upon providers of BPL service, so long as such fees are assessed on a non-discriminatory basis with those charged to other companies providing services competitive with the Other Services.

SECTION 4. Upon the filing with City by Company of the acceptance required hereunder, this Franchise shall be in full force and effect for a term and period of thirty (30) years from and after the first day of July, 2005. SECTION 5. All poles erected by Company pursuant to the authority herein granted shall be of sound material and reasonably straight, and shall be so set that they shall not interfere with the flow of water in any gutter or drain, and so that the same shall interfere as little as practicable with the ordinary travel, on the Streets or other Public Rights-of-Way. Within the Streets or other Public Rights-of-Way of City, the location and route of all poles, stubs, guys, anchors, lines, conduits and cables placed and constructed and to be placed and constructed by Company in the construction and maintenance of Company's System in the City, shall be subject to the reasonable and proper regulation, control and direction of City, or of any City official to whom such duties have or may be duly delegated, which regulation and control shall include, but not by way of limitation, the right to require in writing, to the extent provided in Section 10, the relocation of Company's System at Company's cost within the Streets or other Public Rights-of-Way whenever such shall be reasonably necessary to accommodate City Public Works improvement projects within such Streets or Public Rights-of-Way. SECTION 6. In consideration for the compensation set forth in Sections 11 and 15, City agrees that if City sells, convoys, or surrenders possession of any portion of the Public Right-of-Way that is being used by Company pursuant to this Franchise, City, to the maximum extent of its right to do so, shall first grant Company an easement for such use; and the sale, conveyance, or surrender of possession of the Public Right-of-Way shall be subject to the right and continued use of Company. SECTION 7. Company and its contractors shall give City reasonable notice of the dates, location, and nature of the work to be performed on the System within the Public Rights-of-Way. Following completion of work in Public Rights-of-Way, Company shall repair the affected Public Rights-of-Way as soon as possible, but in all cases shall comply with all City ordinances governing time periods and standards relating to excavating in the Public Rights-of-Way. No Street or other Public Right-of-Way shall be encumbered by construction, maintenance or removal work by Company for a longer period than shall be necessary to execute such work. SECTION 8. The service furnished hereunder to City and its inhabitants shall be first-class in all respects, considering all circumstances, and Company shall furnish the grade of service to Retail Customers as provided by its rate schedules and shall maintain its System in reasonable operating condition during the continuance of this Franchise. Company's tariffs shall govern the rates, access to service, terms and quality of electric delivery services provided by Company. An exception to this requirement is automatically in effect when due to Force Majeure. In any Force Majeure event, Company shall do all things reasonably within its power to restore normal service. SECTION 9. Company, on the written request of any person, shall remove or raise or lower its wires temporarily to permit construction work in the vicinity thereof or

to permit the moving of houses or other bulky structures. The expense of such temporary removal, raising or lowering of wires shall be paid by the benefited party or parties, and Company may require such payment in advance, being without obligation to remove, raise, or lower its wires until such payment has been made. Company shall be given not less than forty-eight (48) hours advance notice to arrange for such temporary wire changes. SECTION 10. Company shall construct, operate, and maintain its transmission and distribution facilities in substantial accordance with Company's own Service Standards and the National Electrical Safety Code ("NESC"). Company shall determine the specific location and the method of construction and types of materials used in building, maintaining, and operating Company's transmission and distribution facilities. City shall require its employees and contractors performing work for the benefit of City to comply with all applicable laws, statutes codes and standards (including, without limitation, Section 752 of the Texas Health and Safety Code, as the same may be amended or replaced, and the NESC) when working near Company's System and to report as soon as practicable any damage done to Company's System. Company also agrees to require its employees and contractors performing work for the benefit of City to comply with all applicable laws, statutes codes and standards (including, without limitation, Section 752 of the Texas Health and Safety Code, as the same may be amended or replaced, and the NESC) when working near City's facilities and to report as soon as practicable any damage done to City's facilities. Company shall relocate facilities within Public Rights-of-Way at Company's own expense, exclusive of street lighting and facilities installed for service directly to City, to accommodate City Public Works improvement projects, including but not limited to street widening, change of grade, water, sewer, or drainage upgrades, construction or reconstruction projects and minor relocation of traffic lanes. City shall bear the costs of all relocations of street lighting and facilities installed for service directly to City and of any relocation of other facilities requested by City for reasons other than City Public Works improvement projects. Except in the event of an emergency, City shall give Company at least seventy-two (72) hours notice when requesting the bracing of Company's poles. Company shall pay for the bracing to accommodate City Public Works improvement projects, including but not limited to street widening, change of grade, water, sewer, or drainage upgrades, construction or reconstruction projects and minor relocation of traffic lanes. SECTION 11. In consideration for the rights and privileges herein granted, Company agrees to pay to City during the term of this Franchise an annual franchise fee (referred to herein as "Annual Franchise Fee"), subject to an Annual Adjustment Factor as set forth below. Except as set forth in Section 15, payment of the Annual Franchise Fee shall be the total compensation payable to City in consideration for the right, privilege and franchise herein conferred for Company's use of the Public Rights-of-Way to construct, operate, use and maintain its System for the provision of electricity transmission and distribution service and its right to use, license, or exploit its System for Other Services.

The Annual Franchise Fee shall be calculated as follows: 1. The "Annual Franchise Fee" for the twelve-month period beginning July 1, 2005, shall be (a) the Base Amount plus (b) the Rider HOU Amount (if and only if approved, no longer subject to appeal, and in effect). 2. The "Base Amount* for the Annual Franchise Fee is $88,100,000. 3. City agrees to enact Rider HOU, a rider to Company's tariff, to be effective as of the Effective Date of this Franchise. Rider HOU shall be designed to permit Company to recover fees totaling $8,500,000 (the "Rider HOU Amount") from retail electric providers serving Retail Customers. 4. The Annual Franchise Fee for each succeeding twelve-month period, including the period beginning July 1, 2006, shall be adjusted by multiplying the Base Amount and the Rider HOU Amount by the Annual Adjustment Factor. The "Annual Adjustment Factor" for any given year shall be a fraction, the numerator of which shall be the kWh delivered by Company within the Franchise Area (inclusive of street lighting) in the previous calendar year and the denominator of which shall be the kWh delivered by Company within the Franchise Area (inclusive of street lighting) in 2004, said amount being 28,650,282,466 kWh. (Example: Assuming Rider HOU is still in effect, the Annual Franchise Fee for the twelve-month period beginning July 1, 2008 =($88.1 million + $8.5 million) x 2007 kWh/28,650,282,466 kWh). In no case, however, shall the Annual Franchise Fee be less than the Base Amount plus the Rider HOU Amount set forth in this section; provided, however, that Company shall at all times retain the right to recover from City any amounts paid (or refuse to pay any amounts not yet paid) to City under Rider HOU for which Company is denied recovery by any regulatory authority. In calculating the amount to be paid each year, Company shall offset its Annual Franchise Fee payments with the amount of the Municipal Account Franchise Credits and Municipal Franchise Fee Credits provided in Company's tariffs and applicable to City in the prior calendar year. The Annual Franchise Fee shall be payable in equal monthly installments due the first day of each calendar month. Company shall calculate the new franchise fee to be payable for each twelve-month period beginning July 1st and shall provide the same along with the basis for such calculation to City for its review no later than April 1st of each year. If Company does not receive an objection from City by May 31st, Company shall implement the adjusted annual franchise fee payment on July 1st.

SECTION 12. The parties agree that the franchise payments due under this Franchise are reasonable and necessary and that the parties shall use their best efforts to enable Company to recover these payments through its electric rates. SECTION 13. Except as provided in Section 15, the Annual Franchise Fee payable hereunder shall be the total compensation payable by Company to City for Company's use of the Public Rights-of-Way for the conduct of its business under the Franchise. City shall not charge any additional license, charge, fee, street or alley rental, or other character of charge or levy for the use or occupancy of the Public Rights-of-Way in City, or any pole tax or inspection fee tax. If City does charge Company any additional license, charge, fee, street or alley rental, or other character of charge or levy, then Company may deduct the amount charged from the next succeeding franchise payment or payments until fully reimbursed. The Franchise shall constitute a permit to perform all work on Company's System within the Public Rights-of-Way and to park vehicles in the Streets and other Public Rights-of-Way when necessary for the installation, removal, operation or maintenance of Company's System. Company and contractors performing work for Company shall not be required to obtain any permits in addition to the Franchise or to pay any fee in addition to the Annual Franchise Fee in order to perform work on Company's System or to park within the Streets and other Public Rights-of-Way. Company shall give City reasonable notice of the dates, location and nature of any excavation work and shall cooperate with City to avoid unnecessary disruption, and Company shall comply with all City ordinances governing time periods and standards relating to excavating in the Public Rights-of-Way. SECTION 14. In the first rate case to review Company's base rates following the Effective Date (the "First Rate Case"), City shall support Company's request to (a) include in Company's base rates the entire then-effective Annual Franchise Fee, (b) include in its tariff a new rider that permits Company at all times thereafter to recover through its rates any portion of the Annual Franchise Fee in excess of the amount included in Company's then-effective retail base rate tariff (the "Tracking Rider") and (c) eliminate from Company's tariffs Rider HOU. If, as a result of the First Rate Case, or any subsequent rate case, Company's entire then-effective Annual Franchise Fee is not included in Company's base rates and/or Company is not permitted to implement the Tracking Rider, then Company shall be required to pay only so much in franchise fees as the amount of franchise fees used by the PUC to calculate Company's then-effective rates. SECTION 15. In addition to the considerations set forth in Section 11, Company shall furnish, free of charge, subject to the use of City, such pole and/or duct space as may be required from time to time for the installation of City-owned traffic, police and fire alarm system conductors; provided such conductor space does not exceed the capacity of one crossarm on any one pole or one interior duct and provided such space is then available on existing poles or ducts. Company shall allow for the expanded use of existing energized conductors by City for the purposes of providing traffic signal communication interconnectivity with prior written approval from Company. The specific location for these traffic, police and fire alarm conductors on Company poles or ducts

shall be determined by Company and shall be allotted at the time specific applications for space are received from City. All City traffic, police and fire alarm circuits on Company poles and ducts shall be designed and installed, operated and maintained in compliance with the applicable provisions of the NESC and other laws, statutes, codes and ordinances applicable to private parties and so as to create no interference, corrosion, harm, damage or hazard with, to or from Company's System or Company's business. All plans for such city traffic, police and fire alarm circuits must be submitted for Company's written approval prior to installation. Any modifications to Company's System necessary to accommodate such installation shall be paid by City. If, after installation, City's equipment is found to interfere with Company's System or business, Company and City shall work together to address the problem and, if deemed practical by Company, preserve City's access. Where main underground duct lines are located between manholes, Company shall permit free of charge the installation in one interior duct by City of its traffic, police or fire alarm signal cables; provided space is available in an interior duct not suitable for power circuits without interference with Company's system neutral conductors. All cables installed by City in Company ducts shall be of the non-metallic sheath type to prevent corrosive or electrolytic action between City and Company owned cables. A request for duct assignment shall in each instance be submitted to Company and a sketch showing duct allocation shall be received from Company prior to the installation of City cables in Company-owned duct lines. All City-owned conductors and cables, whether on poles or in duct lines, shall be constructed, maintained and operated in such manner as to not interfere with or create a hazard in the operation of Company's System or Company's business. If after installation, City's equipment is found to interfere with Company's System or business, Company and City shall work together to address the problem and, if deemed practical by Company, preserve City's access. In addition to the consideration set forth in Section 11, Company shall permit City to use, free of charge, extra space on its street light poles to install City-owned traffic control signs and decorative banners, with prior written approval from Company and provided that such use is consistent with the NESC and other applicable engineering and operational codes and standards. NOTWITHSTANDING ANY OTHER PROVISION IN THIS AGREEMENT, IT IS FURTHER AGREED THAT COMPANY SHALL NOT BE RESPONSIBLE TO ANY PARTY OR PARTIES WHATSOEVER FOR ANY CLAIMS, DEMANDS, LOSSES, SUITS, JUDGMENTS FOR DAMAGES OR INJURIES TO PERSONS OR PROPERTY BY REASON OF THE CONSTRUCTION, MAINTENANCE, INSPECTION OR USE OF THE TRAFFIC SIGNAL LIGHT SYSTEMS, POLICE AND FIRE ALARM SYSTEMS, TRAFFIC CONTROL SIGNS, OR DECORATIVE BANNERS BELONGING TO CITY AND CONSTRUCTED UPON COMPANY'S POLES OR STREET LIGHT POLES OR IN ITS DUCTS, AND CITY SHALL INDEMNIFY AND HOLD COMPANY HARMLESS AGAINST ALL SUCH CLAIMS, LOSSES, DEMANDS, SUITS AND JUDGMENTS, TO THE EXTENT PERMITTED BY THE TEXAS TORT CLAIMS ACT, BUT CITY DOES NOT, BY THIS AGREEMENT, ADMIT PRIMARY LIABILITY TO ANY THIRD PARTY BY REASON OF CITY'S OPERATION AND USE OF SUCH TRAFFIC SIGNAL LIGHT

SYSTEMS, POLICE AND FIRE ALARM SYSTEMS, TRAFFIC CONTROL SIGNS, OR DECORATIVE BANNERS, SUCH BEING A FUNCTION OF GOVERNMENT. SECTION 16. City may conduct an audit or other inquiry, or may pursue a cause of action in relation to the payment of the Annual Franchise Fee only if such audit, inquiry, or pursuit of a cause of action concerns a payment made less than two (2) years before commencement of such audit, inquiry, or pursuit of a cause of action. City shall bear the costs of any such audit or inquiry. All books and records related to Company's operations under this Franchise shall be available to City. Upon receipt of a written request from City, such documents shall be made available for inspection and copying no later than thirty (30) days from the receipt of such request. Amounts due to City for past underpayments or amounts due Company for past overpayments shall include interest calculated using the annual interest rates for overcharges as set by the Texas Public Utility Commission. Said interest shall be payable on such sum from the date the initial payment was due until it is paid. SECTION 17. The parties agree to waive any and all claims, asserted or unasserted, arising out of prior franchise agreements including, without limitation, the ordinance passed by the Mayor of the City of Houston on the 21st day of August, 1957, granting a franchise to Houston Lighting & Power Company except those claims relating to Company's obligations as determined in the audit underway at the time of the execution of this Franchise and any claims associated with Company's fulfillment of its obligations during the period of September 2004 through June 2005. SECTION 18. Nothing contained in this Franchise shall ever be construed as conferring upon Company any exclusive rights or privileges of any nature whatsoever. SECTION 19. It shall be Company's obligation as provided in Section 8 hereof to furnish efficient electrical service to the public at reasonable rates and to maintain its property in good repair and working order except when prevented from so doing by forces and conditions not reasonably within the control of Company. Should Company fail or refuse to maintain its System in good order and furnish efficient service at all times throughout the life of this grant, except only when prevented from so doing by Force Majeure, or should Company fail or refuse to furnish efficient service at reasonable rates, lawfully determined by City, throughout the life of this grant, excepting only during such periods as Company shall in good faith and diligently contest the reasonableness of the rates in question, then it shall forfeit and pay to City the sum of Twenty Five Dollars ($25) for each day it shall so fail or refuse after reasonable notice thereof and a hearing thereon by City. Any suit to recover such penalty shall be filed within one year from the date the penalty accrues. SECTION 20. This Franchise is granted subject to the lawful provisions of Section 17, Article II, of the Charter of City of Houston, which provisions are incorporated herein. If for the purposes of such Section it shall ever become necessary to ascertain the mode of determining fair valuation, such fair valuation shall mean current fair market value. If City should elect to exercise its rights under such Section, payment of a fair valuation shall be required, the mode of ascertaining which, if not agreed upon by the

parties, shall be determined in an appropriate proceeding filed in any Court having jurisdiction. SECTION 21. If any term or other provision of the Franchise is determined by a nonappealable decision by a court, administrative agency, or arbitrator to be invalid, illegal, or incapable of being enforced by any rule of law or public policy, all other conditions and provisions of the Franchise shall nevertheless remain in full force and effect so long as the economic or legal substance is not affected in any manner materially adverse to either party. Upon such determination that any term or other provision is invalid, illegal, or incapable of being enforced, the parties shall negotiate in good faith to modify the Franchise so as to effect the original intent of the parties as closely as possible. SECTION 22. SUBJECT TO SECTION 15, COMPANY, ITS SUCCESSORS AND ASSIGNS, SHALL PROTECT AND HOLD CITY HARMLESS AGAINST ALL CLAIMS FOR DAMAGES OR DEMANDS FOR DAMAGES TO ANY PERSON OR PROPERTY BY REASON OF THE CONSTRUCTION AND MAINTENANCE OF ITS ELECTRICITY TRANSMISSION AND DISTRIBUTION SYSTEM, OR IN ANY WAY GROWING OUT OF THE GRANTING OF THIS FRANCHISE, EITHER DIRECTLY OR INDIRECTLY, OR BY REASON OF ANY ACT, NEGLIGENCE, OR NONFEASANCE OF THE CONTRACTORS, AGENTS OR EMPLOYEES OF COMPANY, ITS SUCCESSORS OR ASSIGNS, AND SHALL REFUND TO CITY ALL SUMS WHICH IT MAY BE ADJUDGED TO PAY ON ANY SUCH CLAIM, OR WHICH MAY ARISE OR GROW OUT OF THE EXERCISE OF THE RIGHTS AND PRIVILEGES HEREBY GRANTED, OR BY THE ABUSE THEREOF, ANY COMPANY, ITS SUCCESSORS AND ASSIGNS, SHALL INDEMNIFY AND HOLD CITY HARMLESS FROM AND ON ACCOUNT OF ALL DAMAGES, COSTS, EXPENSES, ACTIONS, AND CAUSES OF ACTION, TO THE EXTENT PERMITTED BY THE TEXAS TORT CLAIMS ACT, THAT MAY ACCRUE TO OR BE BROUGHT BY ANY PERSON, PERSONS, COMPANY OR COMPANIES AT ANY TIME HEREAFTER BY REASON OF THE EXERCISE OF THE RIGHTS AND PRIVILEGES HEREBY GRANTED, OR OF THE ABUSE THEREOF. SECTION 23. In granting this Franchise, it is understood that the lawful power vested by law in City to regulate all public utilities within City, and to regulate the local rates of public utilities within City within the limits of the Constitution and laws, and to require all persons or corporations to discharge the duties and undertakings, for the performance of which this Franchise was made, is reserved; and this grant is made subject to all lawful rights, powers and authorities, either of regulation or otherwise, reserved to City by its Charter or by the general laws of this State. SECTION 24. This Franchise replaces all former franchise agreements with Company, or its predecessors, which are hereby repealed. There is specifically and particularly repealed that certain City of Houston, Texas Ordinance No. 1957-929 passed by the Mayor of City of Houston on the 21st day of August, 1957, granting a franchise to Houston Lighting & Power Company.

SECTION 25. City by the granting of this Franchise does not surrender or to any extent lose, waive, impair or lessen the lawful powers and rights, now or hereafter vested in City under the Constitution and statutes of the State of Texas and under the Charter of City to regulate the rates and services of Company; and Company by its acceptance of this Franchise agrees that all such lawful regulatory powers and rights as the same may be from time to time vested in City shall be in full force and effect and subject to the exercise thereof by City at any time and from time to time. SECTION 26. Within 30 days following the final passage and approval of this ordinance, the Company shall file with the City Secretary, accompanied by appropriate authorized corporate resolutions in a form acceptable to the City Attorney, a written statement in the following form signed in its name and behalf: "To the Honorable Mayor and the City Council of the City of Houston, Texas: For itself, its successors and assigns, Grantee, CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC, hereby accepts the attached ordinance and agrees to be bound by all of its terms, conditions and provisions." CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC By: ----------------------------------- Name: ---------------------------------- Title: -------------------------------- "Dated this the _____ day of ______________________, 2005." SECTION 27. This Franchise, having been published as required by Article II, Section 17 of the City Charter shall take effect and be in force from and after 30 days following its final passage and approval, and receipt by the City of Company's acceptance filed pursuant to Section 26. In compliance with the provisions of Article II, Sections 17 and 18, of the City Charter, the Company shall pay the cost of those publications and any costs associated with any elections held regarding this Franchise required by such Charter provisions. SECTION 28. Every notice, order, petition, document, or other direction or communication to be served upon the City or the Company shall be deemed sufficiently given if sent by registered or certified mail, return receipt requested. Every such communication to the Company shall be sent to: VICE PRESIDENT, REGULATORY RELATIONS CENTERPOINT ENERGY, INC. 1111 LOUISIANA STREET HOUSTON, TEXAS 77002

Every such communication to the City or the City Council shall be sent to the DIRECTOR, FINANCE & ADMINISTRATION DEPARTMENT 611 WALKER, 10TH FLOOR HOUSTON, TEXAS 77002 and, as applicable, to the CITY ATTORNEY, CITY SECRETARY CITY HALL ANNEX CITY HALL ANNEX 900 BAGBY, 4TH FLOOR 900 BAGBY, PUBLIC LEVEL HOUSTON, TEXAS 77002 HOUSTON, TEXAS 77002 The mailing of such notice, direction, or order shall be equivalent to direct personal notice and shall be deemed to have been given the earlier of receipt or two business days after it was mailed. SECTION 29. The rights and remedies provided herein are cumulative and not exclusive of any remedies provided by law, and nothing contained in this Franchise shall impair any of the rights of the City or the Company under applicable law, subject in each case to the terms and conditions of this Franchise. PASSED first reading the 1st day of June, 2005. PASSED second reading the 8th day of June, 2005. PASSED third and final reading the 15th day of June, 2005. APPROVED the 15th day of June, 2005. ATTEST/SEAL: /s/ Anna Russell - ------------------------------- City Secretary /s/ Bill White ---------------------------- Mayor of the City of Houston /s/ Judy Gray Johnson - ------------------------------- Director, Finance and Administration Dept. Prepared by Legal Dept. /s/ Arturo G. Michel ------------------------------- Arturo G. Michel, City Attorney LD# ---------------

EXHIBIT 31.1 CERTIFICATIONS I, David M. McClanahan, certify that: 1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.; 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)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) 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 (d) 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: August 8, 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, Inc.; 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)) and internal control over financial reporting (as defined in Exchange Act Rules 13(a)-15(f) and 15d-15(f)) 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) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; (c) 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 (d) 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: August 8, 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, Inc. (the "Company") on Form 10-Q for the period ended June 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 August 8, 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, Inc. (the "Company") on Form 10-Q for the period ended June 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 August 8, 2005

EXHIBIT 99.1 CENTERPOINT ENERGY, INC. RETIREMENT PLAN (As Amended and Restated Effective January 1, 1999) Eleventh Amendment CenterPoint Energy, Inc., a Texas corporation, having reserved the right under Section 15.1 of the CenterPoint Energy, Inc. Retirement Plan, as amended and restated effective as of January 1, 1999, and as thereafter amended (the "Plan"), to amend the Plan, does hereby amend the second sentence in the first paragraph of Article II of the Plan, effective as of May 1, 2005, to read as follows: "Each other Employee who is not (i) a 'leased employee' (as defined in Section 414(n)(2) of the Code, subject to Code Section 414(n)(5)), (ii) designated, compensated, or otherwise classified or treated as an independent contractor or a leased employee by an Employer or an Affiliate, (iii) a non-resident alien who receives no United States source earned income from the Employer, or (iv) designated or otherwise classified by the Company or an Affiliate as an offshore production operations employee, shall participate in the Plan on the later of January 1, 1999, or the date on which the Employee completes one hour of service in accordance with Section 3.2." IN WITNESS WHEREOF, CenterPoint Energy, Inc. has caused these presents to be executed by its duly authorized officer in a number of copies, all of which shall constitute one and the same instrument, which may be sufficiently evidenced by any executed copy hereof, on this 28th day of April 2005, but effective as of May 1, 2005. CENTERPOINT ENERGY, INC. By /s/ David M. McClanahan --------------------------------------- David M. McClanahan President and Chief Executive Officer ATTEST: /s/ Richard Dauphin - ------------------- Richard Dauphin Assistant Secretary

EXHIBIT 99.2 CENTERPOINT ENERGY, INC. RETIREMENT PLAN (As Amended and Restated Effective January 1, 1999) Twelfth Amendment CenterPoint Energy, Inc., a Texas corporation, having reserved the right under Section 15.1 of the CenterPoint Energy, Inc. Retirement Plan, as amended and restated effective as of January 1, 1999, and as thereafter amended (the "Plan"), to amend the Plan, does hereby amend the second sentence in the first paragraph of Article II of the Plan, effective as of June 1, 2005, to read as follows: "Each other Employee who is not (i) a 'leased employee' (as defined in Section 414(n)(2) of the Code, subject to Code Section 414(n)(5)), (ii) designated, compensated, or otherwise classified or treated as an independent contractor or a leased employee by an Employer or an Affiliate, (iii) a non-resident alien who receives no United States source earned income from the Employer, (iv) designated or otherwise classified by the Company or an Affiliate as an offshore production operations employee, or (v) designated or otherwise classified as an Employee of the TCT Division of CenterPoint Energy Field Services, Inc., shall participate in the Plan on the later of January 1, 1999, or the date on which the Employee completes one hour of service in accordance with Section 3.2." IN WITNESS WHEREOF, CenterPoint Energy, Inc. has caused these presents to be executed by its duly authorized officer in a number of copies, all of which shall constitute one and the same instrument, which may be sufficiently evidenced by any executed copy hereof, on this 27th day of May 2005, but effective as of June 1, 2005. CENTERPOINT ENERGY, INC. By /s/ David M. McClanahan --------------------------------------- David M. McClanahan President and Chief Executive Officer ATTEST: /s/ Richard Dauphin - ------------------- Richard Dauphin Assistant Secretary

Exhibit 99.3 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 registered public utility holding company, we and our subsidiaries are subject to a comprehensive regulatory scheme imposed by the SEC in order to protect customers, investors and the public interest. Although the SEC does not regulate rates and charges under the 1935 Act, it does regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies. In order to obtain financing, acquire additional public utility assets or stock, or engage in other significant transactions, we are generally required to obtain approval from the SEC under the 1935 Act. We received an order from the SEC under the 1935 Act on June 30, 2003 and supplemental orders thereafter relating to our financing activities and those of our regulated subsidiaries, as well as other matters. The orders are effective until June 30, 2005. As of December 31, 2004, the orders generally permitted us and our subsidiaries to issue securities to refinance indebtedness outstanding at June 30, 2003, and authorized us and our subsidiaries 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 our securities, interest rates, maturities, issuance expenses and use of proceeds. The orders generally require that CenterPoint Houston and CERC 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. Pursuant to requirements of the orders, we formed a service company, CenterPoint Energy Service Company, LLC (Service Company), that began operation as of January 1, 2004, to provide certain corporate and shared services to our subsidiaries. Those services are provided pursuant to service arrangements that are in a form prescribed by the SEC. Services are provided by the Service Company at cost and are subject to oversight and periodic audit from the SEC. 1

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. 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. CenterPoint Houston is not a "public utility" under the Federal Power Act and therefore is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. STATE AND LOCAL REGULATION Electric Transmission & Distribution. CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. In addition, CenterPoint Houston holds non-exclusive franchises, typically having a term of 50 years, from the incorporated municipalities in its service territory. These franchises give CenterPoint Houston the right to construct, operate and maintain its transmission and distribution system within the streets and public ways of these municipalities for the purpose of delivering electric service to the municipality, its residents and businesses in exchange for payment of a fee. The franchise for the City of Houston is scheduled to expire in 2007. All retail electric providers in CenterPoint Houston's service area pay the same rates and other charges for transmission and distribution services. CenterPoint Houston's distribution rates charged to retail electric providers for residential customers are based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are based on peak demand. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under "postage stamp" rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. The transmission and distribution rates for CenterPoint Houston have been in effect since January 1, 2002, when electric competition began. This regulated delivery charge includes the transmission and distribution rate (which includes costs for nuclear decommissioning and municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a transition charge associated 2

with securitization of regulatory assets and an excess mitigation credit imposed by the Texas Utility Commission. Natural Gas Distribution. In almost all communities in which CERC provides natural gas distribution services, it operates 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 CERC's material franchises expire in the near term. CERC expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive. Substantially all of CERC's retail natural gas sales by its 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 CERC serves. 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. 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 Depart- 3

ment 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, gas gathering and processing systems, and electric transmission and distribution 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. 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 4

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. 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 5

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. 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. We believe the ultimate cost associated with resolving this matter will not have a material impact on our financial condition or results of operations or that of CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At December 31, 2004, CERC 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. CERC 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, CERC has 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 were owned or operated by CERC or may have been owned or operated by one of its former affiliates. CERC has not been named by these agencies as a PRP for any of those sites. CERC has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. We are investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of those sites under CERCLA and applicable state statutes, and is vigorously contesting those suits. 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 6

spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by us at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows. Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not believe, based on our experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on our financial condition, results of operations or cash flows. Asbestos. A number of facilities that we own contain significant amounts of asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by us but currently owned by Texas Genco LLC. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the separation agreement between us and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of our agreement to sell Texas Genco to Texas Genco LLC, we have agreed to continue to defend such claims to the extent they are covered by insurance we maintain, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and 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. REGULATORY AND ENVIRONMENTAL MATTERS RELATING TO DISCONTINUED OPERATIONS Nuclear Regulatory Commission. Texas Genco is subject to regulation by the NRC with respect to the operation of the South Texas Project nuclear facility. This regulation involves testing, evaluation and modification of all aspects of plant operation in light of NRC safety and environmental requirements. Continuous demonstrations to the NRC that plant operations meet applicable requirements are also required. The NRC has the ultimate authority to determine whether any nuclear-powered generating unit may operate. Texas Genco and the other owners of the South Texas Project are required by NRC regulations to estimate from time to time the amounts required to decommission that nuclear generating facility and are required to maintain funds to satisfy that obligation when the plant ultimately is decommissioned. CenterPoint Houston currently collects through its electric rates amounts calculated to provide sufficient funds at the time of decommissioning to discharge these obligations. Funds collected are deposited into nuclear decommissioning trusts. The beneficial ownership of the nuclear decommissioning trusts is held by Texas Genco, as a licensee of the facility. While current funding levels exceed NRC minimum requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and waste burial. In the event that funds from the trust are inadequate to decommission the facilities, CenterPoint Houston will be required by the transaction agreement with Texas Genco LLC to collect through rates or other authorized charges all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the South Texas Project. Nuclear Waste. Under the U.S. Nuclear Waste Policy Act of 1982, the federal government was to create a federal repository for spent nuclear fuel produced by nuclear plants like the South Texas Project. Also 7

pursuant to that legislation a special assessment has been imposed on those nuclear plants to pay for the facility. Consistent with the Act, owners of nuclear facilities, including Texas Genco and the other owners of the South Texas Project, entered into contracts setting out the obligations of the owners and U.S. Department of Energy (DOE). Since 1998, DOE has been in default on its obligations to begin moving spent nuclear fuel from reactors to the federal repository (which still is not completed). In January 2004, Texas Genco and the other owners of the South Texas Project, along with owners of other nuclear plants, filed a breach of contract suit against DOE in order to protect against the running of a statute of limitations. In conjunction with Texas Genco's 30.8% ownership interest in the South Texas Project, Texas Genco bears a proportionate share of responsibility associated with the proper handling and disposal of high-level radioactive waste (spent nuclear fuel) as well as low-level radioactive waste. The South Texas Project has on-site storage facilities with the capability to store the spent nuclear fuel, and currently does store such waste on-site, per the requirements established by the NRC. There is adequate on-site storage at the South Texas Project for high-level radioactive waste over the licensed life of the two generating units. The 1980 Federal Low-Level Radioactive Waste Policy Act directed states to assume responsibility for the disposal of low-level radioactive waste generated within their borders. Texas does not currently have any waste disposal locations available for low-level radioactive waste. Private waste management companies are seeking to develop sites in Texas but Texas Genco cannot predict when such a site may be available. South Carolina and New Mexico operate low-level radioactive waste disposal sites that accept low-level radioactive waste from Texas. The South Texas Project disposes of its low-level radioactive waste in both South Carolina and New Mexico under short-term annual agreements. In the event that both South Carolina and New Mexico stop accepting waste in the future, and until a Texas site is functional, the South Texas Project has storage for at least five years of low-level radioactive waste generated by the project. 8

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 4 and 11(c) to our consolidated financial statements, which information is incorporated herein by reference. 9

ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND 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: - the timing and amount of our recovery of the true-up components; - the timing and results of the monetization of our remaining interest in Texas Genco; - state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, constraints placed on our activities or business by the 1935 Act, changes in or application of laws or regulations applicable to other aspects of our business and actions with respect to: - allowed rates of return; - rate structures; - recovery of investments; and - operation and construction of facilities; - 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 cost 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 for our services due to financial distress of our customers, including RRI; - the outcome of the pending securities lawsuits against us, Reliant Energy and RRI; - the ability of RRI to satisfy its obligations to us, including indemnity obligations; - our ability to control costs; - the investment performance of our 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." 10

OTHER SIGNIFICANT MATTERS Pension Plan. As discussed in Note 9(b) to our consolidated financial statements, we maintain a non-contributory pension plan covering substantially all employees. Employer contributions are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes. At December 31, 2004, the projected benefit obligation exceeded the market value of plan assets by $53 million; however, the market value of the plan assets exceeded the accumulated benefit obligation by $22 million. Changes in interest rates and the market values of the securities held by the plan during 2005 could materially, positively or negatively, change our funded status and affect the level of pension expense and required contributions in 2006 and beyond. In connection with the sale of our 81% interest in Texas Genco, a separate pension plan was established for Texas Genco on September 1, 2004 and we transferred a net pension liability of approximately $68 million to Texas Genco. In October 2004, Texas Genco received an allocation of assets from our pension plan pursuant to rules and regulations under ERISA. During 2003 and 2004, we have not been required to make contributions to our pension plan. We have made voluntary contributions of $23 million and $476 million in 2003 and 2004, respectively. Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA and the Internal Revenue Code. In accordance with SFAS No. 87, "Employers' Accounting for Pensions," changes in pension obligations and assets may not be immediately recognized as pension costs in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension costs recorded in any period may not reflect the actual level of benefit payments provided to plan participants. Pension costs were $35 million, $90 million and $80 million for 2002, 2003 and 2004, respectively. For 2002, a pension benefit of $4 million was recorded related to RRI's participants. Pension benefit for RRI's participants is reflected in the Statement of Consolidated Operations as discontinued operations. In addition, included in the costs for 2002, 2003 and 2004 are $15 million, $17 million and $11 million, respectively, of expense related to Texas Genco participants. Pension expense for Texas Genco participants is reflected in the Statement of Consolidated Operations as discontinued operations. Additionally, we maintain a non-qualified benefit restoration plan which allows participants to retain the benefits to which they would have been entitled under our non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with this non-qualified plan was $9 million, $8 million and $6 million in 2002, 2003 and 2004, respectively. Included in the cost for 2002 is $3 million of expense related to RRI's participants, which is reflected in discontinued operations in the Statements of Consolidated Operations. 11

The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate. As of December 31, 2004, the expected long-term rate of return on plan assets was 8.5%, a reduction from the 9.0% rate assumed as of December 31, 2003. We believe that our actual asset allocation, on average, will approximate the targeted allocation and the estimated return on net assets. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate. As of December 31, 2004, the projected benefit obligation was calculated assuming a discount rate of 5.75%, which is a 0.5% decline from the 6.25% discount rate assumed in 2003. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan. Pension expense for 2005, including the benefit restoration plan, is estimated to be $37 million based on an expected return on plan assets of 8.5% and a discount rate of 5.75% as of December 31, 2004. If the expected return assumption were lowered by 0.5% (from 8.5% to 8.0%), 2005 pension expense would increase by approximately $8 million. Due to significant funding that occurred during 2004, pension plan assets (excluding the unfunded benefit restoration plan) exceed the accumulated benefit obligation, which enabled us to reverse a charge to comprehensive income of $350 million, net of tax. However, if the discount rate were lowered by 0.5% (from 5.75% to 5.25%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2005 pension expense by approximately $106 million, $100 million and $7 million, respectively. In addition, the assumption change would have significant impacts on our Consolidated Balance Sheet by changing the pension asset recorded as of December 31, 2004 of $610 million to a pension liability of $78 million, offset by a charge to comprehensive income in 2004 of $447 million, net of tax. For the benefit restoration plan, if the discount rate were lowered by 0.5% (from 5.75% to 5.25%), the assumption change would increase our projected benefit obligation, accumulated benefit obligation and 2005 pension expense by approximately $4 million, $3 million, and less than $1 million, respectively. In addition, the assumption change would result in a charge to comprehensive income of approximately $2 million. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be. In October 2004, the American Jobs Creation Act (AJCA) was signed into law. The AJCA made significant changes in the taxation of nonqualified deferred compensation with new Code Section 409A. Non-compliance with Section 409A can result in increased federal income taxes on nonqualified deferred compensation for employees. We are currently analyzing the impact of Section 409A and related guidance issued by the Treasury Department and the Internal Revenue Service, on our non-qualified plans and agreements that provide for deferred compensation. Such plans or agreements may require amendment or modification to comply with the new law. 12

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (2) Summary of Significant Accounting Policies (d) LONG-LIVED ASSETS AND INTANGIBLES The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:

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

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 December 31, 2004 other than goodwill discussed below. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 40 to 75 years for land rights and 4 to 25 years for other intangibles. 13

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Amortization expense for other intangibles for 2002, 2003 and 2004 was $2 million in each year. Estimated amortization expense for the five succeeding fiscal years is as follows (in millions):

2005........................................................ $ 2 2006........................................................ 2 2007........................................................ 3 2008........................................................ 3 2009........................................................ 3 --- Total..................................................... $13 ===

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

The Company completed its annual evaluation of goodwill for impairment as of January 1, 2004 and no impairment was indicated. The Company periodically evaluates long-lived assets, including property, plant and equipment, goodwill and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets. As a result of the Company's decision to sell its interest in Texas Genco in July 2004, the Company recorded an after-tax loss of approximately $253 million in the third quarter of 2004. In the fourth quarter of 2004, the Company reduced the expected loss on the sale of its interest in Texas Genco by $39 million to $214 million. For further discussion, see Note 3. (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 Electric Transmission & Distribution business segment and the utility operations of the Natural Gas Distribution business segment and to some of the accounts of the Pipelines and Gathering business segment. 14

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2003 and 2004:

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. During 2004, the Company wrote-off net regulatory assets of $1.5 billion in response to the Texas Utility Commission's order on CenterPoint Houston's final true-up application. For further discussion of regulatory assets, see Note 4. 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 $647 million and $677 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. 15

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (4) REGULATORY MATTERS (a) 2004 TRUE-UP PROCEEDING In March 2004, CenterPoint Houston filed the final true-up application required by the Texas electric restructuring law with the Public Utility Commission of Texas (Texas Utility Commission) (2004 True-Up Proceeding). CenterPoint Houston's requested true-up balance was $3.7 billion, excluding interest and net of the retail clawback from RRI described below. In June, July and September 2004, the Texas Utility Commission conducted hearings on, and held public meetings addressing, CenterPoint Houston's true-up application. In December 2004, the Texas Utility Commission approved a final order in CenterPoint Houston's true-up proceeding (2004 Final Order) authorizing CenterPoint Houston to recover $2.3 billion including interest through August 31, 2004, subject to adjustments to reflect the benefit of certain deferred taxes and the accrual of interest and payment of excess mitigation credits after August 31, 2004. As a result of the 2004 Final Order, the Company wrote-off net regulatory assets of $1.5 billion and recorded a related income tax benefit of $526 million, resulting in an after-tax charge of $977 million, which is reflected as an extraordinary loss in the Company's Statements of Consolidated Operations. The Company recorded an expected loss of $894 million in the third quarter of 2004 and increased this amount by $83 million in the fourth quarter of 2004 based on the Company's assessment of the amounts ultimately recoverable. In January 2005, CenterPoint Houston appealed certain aspects of the final order seeking to increase the true-up balance ultimately recovered by CenterPoint Houston. Other parties have also appealed the order, seeking to reduce the amount authorized for CenterPoint Houston's recovery. Although CenterPoint Houston believes it has 16

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) meritorious arguments and that the other parties' appeals are without merit, no prediction can be made as to the ultimate outcome or timing of such appeals. The Company has recorded as a regulatory asset a return of $374 million on the true-up balance for the period from January 1, 2002 through December 31, 2004 as allowed by the Texas Utility Commission's 2004 Final Order. The Company, under the 2004 Final Order, will continue to accrue a return until the true-up balance is recovered by the Company, either from rate payers or through a securitization offering as discussed below. The rate of return is based on CenterPoint Houston's cost of capital, established in the Texas Utility Commission's final order issued in October 2001 (2001 Final Order), which is derived from CenterPoint Houston's cost to finance assets and an allowance for earnings on shareholders' investment. Accordingly, in accordance with SFAS No. 92, "Regulated Enterprises -- Accounting for Phase-in Plans." the rate of return has been bifurcated into components representing a return of costs to finance assets and an allowance for earnings on shareholders' investment. The component representing a return of costs to finance assets of $226 million has been recognized in the fourth quarter of 2004 and is included in other income in the Company's Statements of Consolidated Operations. The component representing a return of costs to finance assets will continue to be recognized as earned going forward. The component representing an allowance for earnings on shareholders' investment of $148 million has been deferred and will be recognized as it is collected through rates in the future. In November 2004, RRI paid $177 million to the Company, representing the "retail clawback" determined by the Texas Utility Commission in the 2004 True-Up Proceeding. The Texas electric restructuring law requires the Texas Utility Commission to determine the retail clawback if the formerly integrated utility's affiliated retail electric provider retained more than 40 percent of its residential price-to-beat customers within the utility's service area as of January 1, 2004 (offset by new customers added outside the service territory). That retail clawback is a credit against the stranded costs the utility is entitled to recover and was reflected in the $2.3 billion recovery authorized. Under the terms of a master separation agreement between RRI and the Company, RRI agreed to pay the Company the amount of the retail clawback determined by the Texas Utility Commission. The payment was used by the Company to reduce outstanding indebtedness. The Texas electric restructuring law provides for the use of special purpose entities to issue transition bonds for the economic value of generation-related regulatory assets and stranded costs. These transition bonds will be amortized over a period not to exceed 15 years through non-bypassable transition charges. In October 2001, a special purpose subsidiary of CenterPoint Houston issued $749 million of transition bonds to securitize certain generation-related regulatory assets. These transition bonds have a final maturity date of September 15, 2015 and are non-recourse to the Company and its subsidiaries other than to the special purpose issuer. Payments on the transition bonds are made solely out of funds from non-bypassable transition charges. In December 2004, CenterPoint Houston filed for approval of a financing order to issue transition bonds to securitize its true-up balance. On March 9, 2005, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize approximately $1.8 billion and requiring that the benefit of certain deferred taxes be reflected as a reduction in the competition transition charge. The Company anticipates that a new special purpose subsidiary of CenterPoint Houston will issue bonds in one or more series through an underwritten offering. Depending on market conditions and the impact of possible appeals of the financing order, among other factors, the Company anticipates completing such an offering in 2005. In January 2005, CenterPoint Houston filed an application for a competition transition charge to recover its true-up balance. CenterPoint Houston will adjust the amount sought through that charge to the extent that it is able to securitize any of such amount. Under the Texas Utility Commission's rules, the unrecovered true-up balance to be recovered through the competition transition charge earns a return until fully recovered. 17

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) In the 2001 Final Order, the Texas Utility Commission established the transmission and distribution rates that became effective in January 2002. Based on its 2001 revision of the 1998 stranded cost estimates, the Texas Utility Commission determined that CenterPoint Houston had over-mitigated its stranded costs by redirecting transmission and distribution depreciation and by accelerating depreciation of generation assets as provided under its 1998 transition plan and the Texas electric restructuring law. In the 2001 Final Order, CenterPoint Houston was required to reverse the amount of redirected depreciation and accelerated depreciation taken for regulatory purposes as allowed under the 1998 transition plan and the Texas electric restructuring law. In accordance with the 2001 Final Order, CenterPoint Houston recorded a regulatory liability to reflect the prospective refund of the accelerated depreciation, and in January 2002 CenterPoint Houston began paying excess mitigation credits, which were to be paid over a seven-year period with interest at 7 1/2% per annum. The annual payment of excess mitigation credits is approximately $264 million. In its December 2004 final order in the 2004 True-Up Proceeding, the Texas Utility Commission found that CenterPoint Houston did, in fact, have stranded costs (as originally estimated in 1998). Despite this ruling, the Texas Utility Commission denied CenterPoint Houston recovery of approximately $180 million of the interest portion of the excess mitigation credits already paid by CenterPoint Houston and refused to terminate future excess mitigation credits. In January 2005, CenterPoint Houston filed a writ of mandamus petition with the Texas Supreme Court asking that court to order the Texas Utility Commission to terminate immediately the payment of all excess mitigation credits and to ensure full recovery of all excess mitigation credits. Although CenterPoint Houston believes it has meritorious arguments, a writ of mandamus is an extraordinary remedy and no prediction can be made as to the ultimate outcome or timing of the mandamus petition. If the Supreme Court denies CenterPoint Houston's mandamus petition, it will continue to pursue this issue through regular appellate mechanisms. On March 1, 2005, a non-unanimous settlement was filed in Docket No. 30774, which involves the adjustment of RRI's Price-to-Beat. Under the terms of that settlement, the excess mitigation credits being paid by CenterPoint Houston would be terminated as of April 29, 2005. The Texas Utility Commission approved the settlement on March 9, 2005. (b) FINAL FUEL RECONCILIATION On March 4, 2004, an Administrative Law Judge (ALJ) issued a Proposal for Decision (PFD) relating to CenterPoint Houston's final fuel reconciliation. CenterPoint Houston reserved $117 million, including $30 million of interest, in the fourth quarter of 2003 reflecting the ALJ's recommendation. On April 15, 2004, the Texas Utility Commission affirmed the PFD's finding in part, reversed in part, and remanded one issue back to the ALJ. On May 28, 2004, the Texas Utility Commission approved a settlement of the remanded issue and issued a final order which reduced the disallowance. As a result of the final order, the Company reversed $23 million, including $8 million of interest, of the $117 million reserve recorded in the fourth quarter of 2003. The results of the Texas Utility Commission's final decision are a component of the 2004 True-Up Proceeding. The Company has appealed certain portions of the Texas Utility Commission's final order involving a disallowance of approximately $67 million relating to the final fuel reconciliation plus interest of $10 million. Briefs on this issue were filed on January 5, 2005, and a hearing on this issue is scheduled for April 22, 2005. (c) 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. 18

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 by approximately $3 million annually. (d) 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. (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 19

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 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 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. 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. Interest Rate Swaps. As of December 31, 2003, the Company had an outstanding interest rate swap with a notional amount of $250 million to fix the interest rate applicable to floating-rate short-term debt. This swap, which expired in January 2004, did not qualify as a cash flow hedge under SFAS No. 133, "Accounting for Derivative Instruments and Hedging Activities" (SFAS No. 133), and was marked to market in the Company's Consolidated Balance Sheets with changes in market value reflected in interest expense in the Statements of Consolidated Operations. During 2002, the Company settled forward-starting interest rate swaps having an aggregate notional amount of $1.5 billion at a cost of $156 million, which was recorded in other comprehensive income and is being amortized into interest expense over the life of the designated fixed-rate debt. Amortization of amounts deferred in accumulated other comprehensive income for 2003 and 2004 was $12 million and $25 million, respectively. As of December 31, 2004, the Company expects $31 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months. Embedded Derivative. The Company's $575 million of convertible senior notes, issued May 19, 2003, and $255 million of convertible senior notes, issued December 17, 2003 (see Note 8), contain contingent interest provisions. The contingent interest component is an embedded derivative as defined by SFAS No. 133, and accordingly, must be split from the host instrument and recorded at fair value on the 20

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) balance sheet. The value of the contingent interest components was not material at issuance or at December 31, 2004. (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):

- --------------- (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), an affiliate until the date of the RRI Distribution. As of December 31, 2004, Reliant Energy Services did not have an investment grade rating. (c) GENERAL POLICY The Company 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 the Company'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 Company'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. (6) INDEXED DEBT SECURITIES (ZENS) AND TIME WARNER SECURITIES (a) ORIGINAL INVESTMENT IN TIME WARNER SECURITIES In 1995, the Company sold a cable television subsidiary to Time Warner Inc. (TW) and received TW convertible preferred stock (TW Preferred) as partial consideration. On July 6, 1999, the Company converted its 11 million shares of TW Preferred into 45.8 million shares of Time Warner common stock (TW Common). The Company currently owns 21.6 million shares of TW Common. Unrealized gains and losses resulting from changes in the market value of the TW Common are recorded in the Company's Statements of Consolidated Operations. 21

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) ZENS In September 1999, the Company issued its 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion. ZENS are exchangeable for cash equal to the market value of a specified number of shares of TW common. The Company pays interest on the ZENS at an annual rate of 2% plus the amount of any quarterly cash dividends paid in respect of the shares of TW Common attributable to the ZENS. The principal amount of ZENS is subject to being increased to the extent that the annual yield from interest and cash dividends on the reference shares of TW Common is less than 2.309%. At December 31, 2004, ZENS having an original principal amount of $840 million and a contingent principal amount of $851 million were outstanding and were exchangeable, at the option of the holders, for cash equal to 95% of the market value of 21.6 million shares of TW Common deemed to be attributable to the ZENS. At December 31, 2004, the market value of such shares was approximately $421 million, which would provide an exchange amount of $476 for each $1,000 original principal amount of ZENS. At maturity, the holders of the ZENS will receive in cash the higher of the original principal amount of the ZENS (subject to adjustment as discussed above) or an amount based on the then-current market value of TW Common, or other securities distributed with respect to TW Common. In 2002, holders of approximately 16% of the 17.2 million ZENS originally issued exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million. Exchanges of ZENS subsequent to 2002 aggregate less than one percent of ZENS originally issued. A subsidiary of the Company owns shares of TW Common and elected to liquidate a portion of such holdings to facilitate the Company's making the cash payments for the ZENS exchanged in 2002 through 2004. In connection with the exchanges, the Company received net proceeds of approximately $43 million from the liquidation of approximately 4.1 million shares of TW Common at an average price of $10.56 per share. The Company now holds 21.6 million shares of TW Common which are classified as trading securities under SFAS No. 115 and are expected to be held to facilitate the Company's ability to meet its obligation under the ZENS. Upon adoption of SFAS No. 133 effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component (the holder's option to receive the appreciated value of TW Common at maturity). The derivative component was valued at fair value and determined the initial carrying value assigned to the debt component ($121 million) as the difference between the original principal amount of the ZENS ($1 billion) and the fair value of the derivative component at issuance ($879 million). Effective January 1, 2001 the debt component was recorded at its accreted amount of $122 million and the derivative component was recorded at its fair value of $788 million, as a current liability. Subsequently, the debt component accretes through interest charges at 17.5% annually up to the minimum amount payable upon maturity of the ZENS in 2029 (approximately $915 million) which reflects exchanges and adjustments to maintain a 2.309% annual yield, as discussed above. Changes in the fair value of the derivative component are recorded in the Company's Statements of Consolidated Operations. During 2002, 2003 and 2004, the Company recorded a loss of $500 million, a gain of $106 million and a gain of $31 million, respectively, on the Company's investment in TW Common. During 2002, 2003 and 2004, the Company recorded a gain of $480 million, a loss of $96 million and a loss of $20 million, respectively, associated with the fair value of the derivative component of the ZENS obligation. Changes in the fair value of the TW Common held by the Company are expected to substantially offset changes in the fair value of the derivative component of the ZENS. 22

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ZENS obligation (in millions).

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (11) COMMITMENTS AND CONTINGENCIES (a) FUEL COMMITMENTS Fuel commitments, excluding Texas Genco, include 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 derivatives 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. 24

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) (b) LEASE COMMITMENTS The following table sets forth information concerning the Company's obligations, excluding Texas Genco, under non-cancelable long-term operating leases at December 31, 2004, which primarily consist of rental agreements for building space, data processing equipment and vehicles (in millions):

2005........................................................ $ 25 2006........................................................ 21 2007........................................................ 18 2008........................................................ 14 2009........................................................ 6 2010 and beyond............................................. 26 ---- Total..................................................... $110 ====

Total lease expense for all operating leases was $36 million, $35 million and $32 million during 2002, 2003 and 2004, respectively. (c) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS Legal Matters RRI Indemnified Litigation The Company, CenterPoint Houston or their predecessor, Reliant Energy, and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and RRI, the Company and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys' fees and other costs, arising out of the lawsuits described below under Electricity and Gas Market Manipulation Cases and Other Class Action Lawsuits. Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. The ultimate outcome of these matters cannot be predicted at this time. Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in both federal and state courts in California and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other western states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit, attorneys' fees and divestiture of assets. To date, some of these complaints have been dismissed by the trial court and are on appeal, several of which dismissals have been affirmed by the appellate courts, but most of the lawsuits remain in early procedural stages. The Company's former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally. RRI, some of its subsidiaries and, in some cases, corporate officers of some of those companies have been named as defendants in these suits. The Company or its predecessor, Reliant Energy, have been named in approximately 30 of these lawsuits, which were instituted between 2001 and 2004 and are pending in California state courts in Alameda County, Los Angeles County, San Francisco County, San Mateo County and San Diego County, in Nevada state court 25

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) in Clark County, in federal district courts in San Francisco, San Diego, Los Angeles, Fresno, Sacramento and Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases. On July 6, 2004 and on October 12, 2004, the Ninth Circuit affirmed the Company's removal to federal district court of two electric cases brought by the California Attorney General and affirmed the federal court's dismissal of these cases based upon the filed rate doctrine and federal preemption. Other Class Action Lawsuits. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of RRI and/or Reliant Energy have been consolidated in federal district court in Houston. RRI and certain of its former and current executive officers are named as defendants. The consolidated complaint also names RRI , Reliant Energy, the underwriters of the initial public offering of RRI's common stock in May 2001 (RRI Offering), and RRI's and Reliant Energy's independent auditors as defendants. The consolidated amended complaint seeks monetary relief purportedly on behalf of purchasers of common stock of Reliant Energy or RRI during certain time periods ranging from February 2000 to May 2002, and purchasers of common stock that can be traced to the RRI Offering. The plaintiffs allege, among other things, that the defendants misrepresented their revenues and trading volumes by engaging in round-trip trades and improperly accounted for certain structured transactions as cash-flow hedges, which resulted in earnings from these transactions being accounted for as future earnings rather than being accounted for as earnings in fiscal year 2001. In January 2004 the trial judge dismissed the plaintiffs' allegations that the defendants had engaged in fraud, but claims based on alleged misrepresentations in the registration statement issued in the RRI Offering remain. In June 2004, the plaintiffs filed a motion for class certification, which the court granted in February 2005. The defendants have appealed the court's order certifying the class. In February 2003, a lawsuit was filed by three individuals in federal district court in Chicago against CenterPoint Energy and certain former officers of RRI for alleged violations of federal securities laws. The plaintiffs in this lawsuit allege that the defendants violated federal securities laws by issuing false and misleading statements to the public, and that the defendants made false and misleading statements as part of an alleged scheme to artificially inflate trading volumes and revenues. In addition, the plaintiffs assert claims of fraudulent and negligent misrepresentation and violations of Illinois consumer law. In January 2004 the trial judge ordered dismissal of plaintiffs' claims on the ground that they did not set forth a claim. The plaintiffs filed an amended complaint in March 2004, which the defendants asked the court to dismiss. On August 18, 2004, the court granted the defendants' motion to dismiss with prejudice. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by Reliant Energy. Two of the lawsuits have been dismissed without prejudice. Reliant Energy and certain current and former members of its benefits committee are the remaining defendants in the third lawsuit. That lawsuit alleges that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by Reliant Energy, in violation of the Employee Retirement Income Security Act of 1974. The plaintiffs allege that the defendants permitted the plans to purchase or hold securities issued by Reliant Energy when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint seeks monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held Reliant Energy or RRI securities, as well as restitution. In July 2004, another class action suit was filed in federal court on behalf of the Reliant Energy Savings Plan and a class consisting of participants in that plan against Reliant Energy and the Reliant Energy Benefits Committee. The allegations and the relief sought in the new suit are substantially similar to those in the previously pending suit; however, the new suit also alleges that Reliant Energy and its Benefits Committee breached their fiduciary duties to the Savings Plan and its participants by investing plan funds in 26

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Reliant Energy stock when Reliant Energy or its subsidiaries were allegedly manipulating the California energy market. On October 14, 2004, the plaintiff voluntarily dismissed the newly filed lawsuit. In October 2002, a derivative action was filed in the federal district court in Houston against the directors and officers of the Company. The complaint set forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleged that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleged breach of fiduciary duty in connection with the spin-off of RRI and the RRI Offering. The complaint sought monetary damages on behalf of the Company as well as equitable relief in the form of a constructive trust on the compensation paid to the defendants. The Company's board of directors investigated that demand and similar allegations made in a June 28, 2002 demand letter sent on behalf of a Company shareholder. The second letter demanded that the Company take several actions in response to alleged round-trip trades occurring in 1999, 2000, and 2001. In June 2003, the board determined that these proposed actions would not be in the best interests of the Company. In March 2003, the court dismissed this case on the grounds that the plaintiff did not make an adequate demand on the Company before filing suit. Thereafter, the plaintiff sent another demand asserting the same claims. The Company believes that none of the lawsuits described under Other Class Action Lawsuits has merit because, among other reasons, the alleged misstatements and omissions were not material and did not result in any damages to the plaintiffs. Other Legal Matters Texas Antitrust Actions. In July 2003, Texas Commercial Energy filed in federal court in Corpus Christi, Texas a lawsuit against Reliant Energy, the Company and CenterPoint Houston, as successors to Reliant Energy, Genco LP, RRI, Reliant Energy Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws and committed fraud and negligent misrepresentation. The lawsuit sought damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. In June 2004, the federal court dismissed the plaintiff's claims and in July 2004, the plaintiff filed a notice of appeal. The Company is vigorously contesting the appeal. The ultimate outcome of this matter cannot be predicted at this time. In February 2005, Utility Choice Electric filed in federal court in Houston, Texas a lawsuit against the Company, CenterPoint Houston, CenterPoint Energy Gas Services, Inc., CenterPoint Energy Alternative Fuels, Inc., Genco LP and a number of other participants in the ERCOT power market. The plaintiff, a retail electricity provider with the ERCOT market, alleged that the defendants conspired to illegally fix and artificially increase the price of electricity in violation of state and federal antitrust laws, intentionally interfered with prospective business relationships and contracts, and committed fraud and negligent misrepresentation. The plaintiff's principal allegations had previously been investigated by the Texas Utility Commission and found to be without merit. The Company intends to vigorously defend the case. The ultimate outcome of this matter cannot be predicted at this time. Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit in state district court in Harris County, Texas for themselves and a proposed class of all similarly situated cities in Reliant Energy's electric service area, against Reliant Energy and Houston Industries Finance, Inc. (formerly a wholly owned subsidiary of the Company's predecessor, Reliant Energy) alleging underpayment of municipal franchise fees. The plaintiffs claimed that they were entitled to 4% of all receipts of any kind for business conducted within these cities over the previous four decades. After a jury trial 27

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) involving the Three Cities' claims (but not the class of cities), the trial court entered a judgment on the Three Cities' breach of contract claims for $1.7 million, including interest, plus an award of $13.7 million in legal fees. It also decertified the class. Following this ruling, 45 cities filed individual suits against Reliant Energy in the District Court of Harris County. On February 27, 2003, a state court of appeals in Houston rendered an opinion reversing the judgment against the Company and rendering judgment that the Three Cities take nothing by their claims. The court of appeals held that all of the Three Cities' claims were barred by the jury's finding of laches, a defense similar to the statute of limitations, due to the Three Cities' having unreasonably delayed bringing their claims during the more than 30 years since the alleged wrongs began. The court also held that the Three Cities were not entitled to recover any attorneys' fees. The Three Cities filed a petition for review to the Texas Supreme Court, which declined to hear the case. Thus, the Three Cities' claims have been finally resolved in the Company's favor, but the individual claims of the 45 cities remain pending in the same court. 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 CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC and its subsidiaries believe that there has been no systematic mismeasurement of gas and that the suits are without merit. CERC does not expect that the ultimate outcome will have a material impact on the financial condition or results of operations of either the Company or CERC. Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, 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 CERC 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 28

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) state court in Calcasieu Parish, Louisiana against CERC 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 LPSC. In October 2004, a similar case was filed in district court in Miller County, Arkansas against the Company, CERC, 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 County 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, CERC 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 CERC 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 CERC. Texas Genco Shareholder Litigation. On July 23, 2004, two plaintiffs, both Texas Genco shareholders, filed virtually identical lawsuits in Harris County, Texas district court. These suits, purportedly brought on behalf of holders of Texas Genco common stock, name Texas Genco and each of that company's directors as defendants. Both plaintiffs allege, among other things, self-dealing and breach of fiduciary duty by the defendants in entering into the July 2004 agreement to sell Texas Genco. As part of their allegations of self-dealing, both plaintiffs claim that the board of directors of Texas Genco is controlled by CenterPoint Energy, that the defendants improperly concealed results of Texas Genco's results of operations for the second quarter of 2004 until after the transaction agreement was announced and that, in order to aid CenterPoint Energy, the Texas Genco board only searched for acquirers who would offer all-cash consideration. Plaintiffs seek to enjoin the transaction or, alternatively, rescind the transaction and/or recover damages in the event that the transaction is consummated. In August 2004, the cases were consolidated in state district court in Harris County, Texas. Although the defendants continue to deny liability, in February 2005, all parties entered into a Memorandum of Understanding to settle the lawsuit based upon supplemental disclosures made by Texas Genco and the extension of the deadline for the exercise of shareholder dissenters' rights. The settlement is subject to the parties' preparation of a stipulation of settlement and court approval of the settlement. 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. 29

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) 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 either the Company or CERC. Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory. CERC believes that it has no liability with respect to two of these sites. At December 31, 2004, CERC 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. CERC 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, CERC has collected or accrued $13 million from insurance companies and ratepayers 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 CERC or may have been owned by one of its former affiliates. CERC has not been named by these agencies as a PRP for any of those sites. CERC has been named as a defendant in lawsuits under which contribution is sought for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. The Company is investigating details regarding these sites and the range of environmental expenditures for potential remediation. However, CERC 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. 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. Asbestos. A number of facilities owned by the Company contain significant amounts of asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company but currently owned by Texas Genco LLC. The Company anticipates that additional claims like those received may be 30

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) asserted in the future. Under the terms of the separation agreement between the Company and Texas Genco, ultimate financial responsibility for uninsured losses relating to these claims has been assumed by Texas Genco, but under the terms of its agreement to sell Texas Genco to Texas Genco LLC, the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from Texas Genco LLC. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and 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 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 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. TEXAS GENCO MATTERS Nuclear Insurance. Texas Genco and the other owners of the South Texas Project maintain nuclear property and nuclear liability insurance coverage as required by law and periodically review available limits and coverage for additional protection. The owners of the South Texas Project currently maintain $2.75 billion in property damage insurance coverage, which is above the legally required minimum, but is less than the total amount of insurance currently available for such losses. Under the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $10.8 billion as of December 31, 2004. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan under which the owners of the South Texas Project are subject to maximum retrospective assessments in the aggregate per incident of up to $100.6 million per reactor. The owners are jointly and severally liable at a rate not to exceed $10 million per reactor per year per incident. There can be no assurance that all potential losses or liabilities associated with the South Texas Project will be insurable, or that the amount of insurance will be sufficient to cover them. Any substantial losses not covered by insurance would have a material effect on Texas Genco's financial condition, results of operations and cash flows. Nuclear Decommissioning. CenterPoint Houston, as collection agent for the nuclear decommissioning charge assessed on its transmission and distribution customers, contributed $2.9 million in 2004 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project, and expects to contribute $2.9 million in 2005. There are various investment restrictions imposed upon Texas 31

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES NOTES TO CONSOLIDATED FINANCIAL STATEMENTS -- (CONTINUED) Genco by the Texas Utility Commission and the NRC relating to Texas Genco's nuclear decommissioning trusts. Texas Genco and CenterPoint Houston have each appointed two members to the Nuclear Decommissioning Trust Investment Committee which establishes the investment policy of the trusts and oversees the investment of the trusts' assets. The securities held by the trusts for decommissioning costs had an estimated fair value of $216 million as of December 31, 2004, of which approximately 36% were fixed-rate debt securities and the remaining 64% were equity securities. In May 2004, an outside consultant estimated Texas Genco's portion of decommissioning costs to be approximately $456 million. While the funding levels currently exceed minimum NRC requirements, no assurance can be given that the amounts held in trust will be adequate to cover the actual decommissioning costs of the South Texas Project. Such costs may vary because of changes in the assumed date of decommissioning and changes in regulatory requirements, technology and costs of labor, materials and equipment. Pursuant to the Texas electric restructuring law, costs associated with nuclear decommissioning that were not recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be charged to transmission and distribution customers of CenterPoint Houston or its successor. 32