CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-Q, Received: 05/10/2004 06:04:46)    
 
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 MARCH 31, 2004

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, including
  executive offices)                                  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 May 1, 2004, CenterPoint Energy, Inc. had 307,193,878 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 MARCH 31, 2004
TABLE OF CONTENTS

PART I.     FINANCIAL INFORMATION
            Item 1. Financial Statements.............................................................   1
                  Statements of Consolidated Income
                     Three Months Ended March 31, 2003 and 2004 (unaudited)..........................   1
                  Consolidated Balance Sheets
                     December 31, 2003 and March 31, 2004 (unaudited)................................   2
                  Statements of Consolidated Cash Flows
                     Three Months Ended March 31, 2003 and 2004 (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 and Subsidiaries.....................................  22
            Item 3. Quantitative and Qualitative Disclosures about Market Risk.......................  37
            Item 4. Controls and Procedures..........................................................  39

PART II.    OTHER INFORMATION
            Item 1. Legal Proceedings................................................................  40
            Item 2. Changes in Securities, Use of Proceeds and Issuer Repurchases of Equity
               Securities............................................................................  40
            Item 6. Exhibits and Reports on Form 8-K.................................................  41

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 outcome of the regulatory process related to the 1999 Texas Electric Choice Law leading to the determination and recovery of the true-up components and the securitization of these amounts;

- the timing and results of the monetization of our interest in Texas Genco Holdings, Inc.;

- state and federal legislative and regulatory actions or developments, including deregulation, re-regulation and restructuring of the electric utility industry, constraints placed on our activities or business by the Public Utility Holding Company Act of 1935, as amended (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 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 counterparts 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 and obligations to pay the "price to beat" clawback; and

- other factors we discuss in "Risk Factors" beginning on page 26 of the CenterPoint Energy, Inc. Annual Report on Form 10-K for the year ended December 31, 2003.

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
                                                                                          MARCH 31,
                                                                                 ---------------------------
                                                                                     2003           2004
                                                                                 ------------   ------------
REVENUES...................................................................      $  2,900,168   $  2,959,187
                                                                                 ------------   ------------
EXPENSES:
  Fuel and cost of gas sold................................................         1,859,145      1,942,258
  Purchased power..........................................................            11,994          8,270
  Operation and maintenance................................................           412,876        410,612
  Depreciation and amortization............................................           152,282        156,587
  Taxes other than income taxes............................................           102,844        106,245
                                                                                 ------------   ------------
      Total................................................................         2,539,141      2,623,972
                                                                                 ------------   ------------
OPERATING INCOME...........................................................           361,027        335,215
                                                                                 ------------   ------------
OTHER INCOME (EXPENSE):
  Loss on  Time Warner investment..........................................           (48,474)       (24,453)
  Gain on indexed debt securities..........................................            42,703         27,014
  Interest and other finance charges.......................................          (228,044)      (194,752)
  Interest on transition bonds.............................................            (9,848)        (9,674)
  Other, net...............................................................             3,159          1,824
                                                                                 ------------   ------------
      Total................................................................          (240,504)      (200,041)
                                                                                 ------------   ------------
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAXES,  MINORITY INTEREST,
  AND CUMULATIVE EFFECT OF ACCOUNTING CHANGE ..............................           120,523        135,174
  Income Tax Expense.......................................................           (41,109)       (49,997)
  Minority Interest........................................................             2,066        (11,590)
                                                                                 ------------   ------------
INCOME FROM CONTINUING OPERATIONS BEFORE CUMULATIVE EFFECT OF ACCOUNTING
  CHANGE ..................................................................            81,480         73,587
DISCONTINUED OPERATIONS:
    Loss from Other Operations, net of tax.................................              (462)             -
    Gain on Disposal of  Other Operations, net of tax......................             7,342              -
CUMULATIVE EFFECT OF ACCOUNTING CHANGE, NET OF  TAX........................            80,072              -
                                                                                 ------------   ------------
NET INCOME ................................................................      $    168,432   $     73,587
                                                                                 ============   ============
BASIC EARNINGS PER SHARE:
  Income from Continuing Operations Before Cumulative Effect of Accounting
    Change.................................................................      $       0.27   $       0.24
  Discontinued Operations:
    Loss from Other Operations, net of tax.................................                 -              -
    Gain on Disposal of  Other Operations, net of tax......................              0.02              -
  Cumulative Effect of Accounting Change, net of tax.......................              0.27              -
                                                                                 ------------   ------------
  Net Income...............................................................      $       0.56   $       0.24
                                                                                 ============   ============
DILUTED EARNINGS PER SHARE:
  Income from Continuing Operations Before Cumulative Effect of Accounting
    Change.................................................................      $       0.27   $       0.24
  Discontinued Operations:
    Loss from Other Operations, net of tax.................................                 -              -
    Gain on Disposal of  Other Operations, net of tax......................              0.02              -
  Cumulative Effect of Accounting Change, net of tax.......................              0.27              -
                                                                                 ------------   ------------
  Net Income...............................................................      $       0.56   $       0.24
                                                                                 ============   ============

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,        MARCH 31,
                                                                                     2003               2004
                                                                                --------------     --------------
CURRENT ASSETS:
   Cash and cash equivalents................................................    $      131,480     $      206,467
   Investment in Time Warner common stock...................................           389,302            364,849
   Accounts receivable, net.................................................           636,646            566,440
   Accrued unbilled revenues................................................           395,351            242,584
   Fuel stock...............................................................           237,650            148,867
   Materials and supplies...................................................           175,276            169,501
   Non-trading derivative assets............................................            45,897             48,993
   Taxes receivable.........................................................           159,646            123,455
   Prepaid expenses and other current assets................................           101,457             79,176
                                                                                --------------     --------------
     Total current assets...................................................         2,272,705          1,950,332
                                                                                --------------     --------------
PROPERTY, PLANT AND EQUIPMENT:
   Property, plant and equipment............................................        20,005,437         20,097,386
   Less accumulated depreciation and amortization...........................        (8,193,901)        (8,307,335)
                                                                                --------------     --------------
     Property, plant and equipment, net.....................................        11,811,536         11,790,051
                                                                                --------------     --------------
OTHER ASSETS:
   Goodwill, net............................................................         1,740,510          1,740,510
   Other intangibles, net...................................................            79,936             79,111
   Regulatory assets........................................................         4,930,793          4,945,277
   Non-trading derivative assets............................................            11,273             11,391
   Other....................................................................           529,911            542,872
                                                                                --------------     --------------
     Total other assets.....................................................         7,292,423          7,319,161
                                                                                --------------     --------------
       TOTAL ASSETS.........................................................    $   21,376,664     $   21,059,544
                                                                                ==============     ==============

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,         MARCH 31,
                                                                                    2003                2004
                                                                                --------------     --------------
CURRENT LIABILITIES:
   Short-term borrowings...................................................     $       63,000     $           --
   Current portion of transition bond long-term debt.......................             41,189             43,099
   Current portion of other long-term debt.................................            121,234            122,108
   Indexed debt securities derivative......................................            321,352            294,335
   Accounts payable........................................................            694,558            624,782
   Taxes accrued...........................................................            193,273            115,320
   Interest accrued........................................................            164,669            155,957
   Non-trading derivative liabilities......................................              8,036              9,626
   Regulatory liabilities..................................................            186,239            187,218
   Accumulated deferred income taxes, net..................................            345,870            334,480
   Deferred revenues.......................................................             88,740             88,781
   Other...................................................................            290,176            228,906
                                                                                --------------     --------------
     Total current liabilities.............................................          2,518,336          2,204,612
                                                                                --------------     --------------
OTHER LIABILITIES:
   Accumulated deferred income taxes, net..................................          3,010,577          3,043,093
   Unamortized investment tax credits......................................            211,731            206,969
   Non-trading derivative liabilities......................................              3,330              1,676
   Benefit obligations.....................................................            836,459            851,622
   Regulatory liabilities..................................................          1,358,030          1,331,355
   Other...................................................................            715,670            697,633
                                                                                --------------     --------------
     Total other liabilities...............................................          6,135,797          6,132,348
                                                                                --------------     --------------
LONG-TERM DEBT:
   Transition bonds........................................................            675,665            659,762
   Other...................................................................         10,107,399         10,046,251
                                                                                --------------     --------------
     Total long-term debt..................................................         10,783,064         10,706,013
                                                                                --------------     --------------
COMMITMENTS AND CONTINGENCIES (NOTES 1 AND 11)

MINORITY INTEREST IN CONSOLIDATED SUBSIDIARIES.............................            178,910            186,691
                                                                                --------------     --------------
SHAREHOLDERS' EQUITY:
   Common stock (305,385,434  shares and 307,072,860 shares outstanding
     at December 31, 2003 and March 31, 2004, respectively)................              3,063              3,071
   Additional paid-in capital..............................................          2,868,416          2,882,417
   Unearned ESOP stock.....................................................             (2,842)                --
   Retained deficit........................................................           (700,033)          (657,012)
   Accumulated other comprehensive loss....................................           (408,047)          (398,596)
                                                                                --------------     --------------
     Total shareholders' equity............................................          1,760,557          1,829,880
                                                                                --------------     --------------

       TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY..........................     $   21,376,664     $   21,059,544
                                                                                ==============     ==============

See Notes to the Company's Interim Financial Statements

3


 
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
STATEMENTS OF CONSOLIDATED CASH FLOWS
(THOUSANDS OF DOLLARS)

(UNAUDITED)

                                                                                   THREE MONTHS ENDED MARCH 31,
                                                                               -----------------------------------
                                                                                    2003                2004
                                                                               --------------       --------------
CASH FLOWS FROM OPERATING ACTIVITIES:
  Net income..............................................................     $      168,432       $       73,587
  Discontinued operations.................................................             (6,880)                   -
  Cumulative effect of accounting change..................................            (80,072)                   -
                                                                               --------------       --------------
  Income from continuing operations before cumulative effect of
    accounting change.....................................................             81,480               73,587
  Adjustments to reconcile income from continuing operations before
    cumulative effect of accounting change to net cash provided by
    operating activities:
    Depreciation and amortization.........................................            152,282              156,587
    Fuel-related amortization.............................................              6,535                6,916
    Amortization of deferred financing costs..............................             38,839               22,846
    Deferred income taxes.................................................            101,945               17,061
    Investment tax credit.................................................             (4,342)              (4,761)
    Unrealized loss on Time Warner investment.............................             48,474               24,453
    Unrealized gain on indexed debt securities............................            (42,703)             (27,014)
    Minority interest.....................................................             (2,066)              11,590
    Changes in other assets and liabilities:
      Accounts receivable and unbilled revenues, net......................           (292,422)             223,241
      Inventory...........................................................             59,473               94,558
      Taxes receivable....................................................            (21,045)              36,191
      Accounts payable....................................................            216,341              (69,776)
      Fuel cost over (under) recovery/surcharge...........................             10,702               31,280
      Non-trading derivatives, net........................................             (3,826)               4,987
      Interest and taxes accrued..........................................           (109,862)             (86,665)
      Net regulatory assets and liabilities...............................           (198,022)             (54,965)
      Other current assets................................................              7,854               22,281
      Other current liabilities...........................................            (79,136)             (92,513)
      Other assets........................................................             (4,323)             (14,427)
      Other liabilities...................................................             39,816               (3,773)
    Other, net............................................................               (296)              21,136
                                                                               --------------       --------------
        Net cash provided by operating activities.........................              5,698              392,820
                                                                               --------------       --------------
CASH FLOWS FROM INVESTING ACTIVITIES:
  Capital expenditures....................................................           (143,373)            (122,853)
  Other, net..............................................................             (2,924)              (4,745)
                                                                               --------------       --------------
        Net cash used in investing activities.............................           (146,297)            (127,598)
                                                                               --------------       --------------
CASH FLOWS FROM FINANCING ACTIVITIES:
  Decrease in short-term borrowing, net...................................           (347,000)             (63,000)
  Long-term revolving credit facility, net................................            (53,000)             195,500
  Proceeds from long-term debt............................................          1,408,830              231,550
  Payments of long-term debt..............................................           (729,138)            (510,356)
  Debt issuance costs.....................................................           (124,893)             (13,126)
  Payment of common stock dividends.......................................            (30,507)             (30,657)
  Payment of common stock dividends by subsidiary.........................             (3,809)              (3,808)
  Proceeds from issuance of common stock, net.............................                814                3,658
  Other, net..............................................................                168                    4
                                                                               --------------       --------------
      Net cash provided by (used in) financing activities.................            121,465             (190,235)
                                                                               --------------       --------------
NET CASH PROVIDED BY DISCONTINUED OPERATIONS..............................             19,322                    -
                                                                               --------------       --------------
NET INCREASE IN CASH AND CASH EQUIVALENTS.................................                188               74,987
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD..........................            304,281              131,480
                                                                               --------------       --------------
CASH AND CASH EQUIVALENTS AT END OF PERIOD................................     $      304,469       $      206,467
                                                                               ==============       ==============
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash Payments:
  Interest................................................................     $      234,871       $      202,587
  Income taxes (refunds)..................................................            (39,260)               1,997

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., together with its subsidiaries (collectively, CenterPoint Energy or the Company), are CenterPoint Energy's consolidated interim financial statements and notes (Interim Financial Statements) including its wholly owned and majority owned subsidiaries. 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, 2003 (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 1999 Texas Electric Choice Law (Texas electric restructuring law).

The Company's operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, natural gas pipelines and electric generating plants. 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 regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliate transactions.

Texas Genco, LP, the wholly owned subsidiary of Texas Genco Holdings, Inc. (Texas Genco) that owns and operates its electric generating plants, is an exempt wholesale generator pursuant to an order of the Federal Energy Regulatory Commission. As a result, Texas Genco, LP is exempt from all provisions of the 1935 Act so long as it remains an exempt wholesale generator, and Texas Genco is no longer a public utility holding company under the 1935 Act.

As of March 31, 2004, 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. Through wholly owned subsidiaries, CERC owns two interstate natural gas pipelines and gas gathering systems and provides various ancillary services.

CenterPoint Energy also has an approximately 81% ownership interest in Texas Genco, which owns and operates a portfolio of generating assets located in Texas. CenterPoint Energy distributed approximately 19% of the 80 million outstanding shares of common stock of Texas Genco to its shareholders on January 6, 2003 (Texas Genco Distribution). As a result of the Texas Genco Distribution, CenterPoint Energy recorded an impairment charge of $399 million, which is reflected as a regulatory asset representing stranded costs in the Consolidated Balance Sheets. This impairment charge represents the excess of the carrying value of CenterPoint Energy's net investment in Texas Genco over the market value of the Texas Genco common stock that was distributed. The financial impact of this impairment was offset by recording a $399 million regulatory asset reflecting CenterPoint Energy's expectation of stranded cost recovery of such impairment. Additionally, in connection with the Texas Genco Distribution, CenterPoint Energy recorded minority interest ownership in Texas Genco of $146 million in its Consolidated Balance Sheets in the first quarter of 2003. CenterPoint Energy is actively pursuing a sale of its 81% ownership interest in Texas Genco.

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 7 (Indexed Debt Securities (ZENS) and Time Warner Securities) and Note 12 (Commitments and Contingencies) to the consolidated annual financial statements in the CenterPoint Energy Form 10-K 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) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS

(a) Stock-Based Incentive Compensation Plans.

In accordance with SFAS No. 123, "Accounting for Stock-Based Compensation" (SFAS No. 123), and SFAS No. 148, "Accounting for Stock-Based Compensation, Transition and Disclosure -- an Amendment of SFAS No. 123," the Company applies the guidance contained in Accounting Principles Board Opinion No. 25 and discloses the required pro-forma effect on net income of the fair value based method of accounting for stock compensation.

Pro-forma information for the three months ended March 31, 2003 and 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, the Company's net income and earnings per share would have been as follows:

 

                                                                       THREE MONTHS ENDED
                                                                           MARCH 31,
                                                                ------------------------------
                                                                     2003              2004
                                                                -----------        -----------
                                                                (IN MILLIONS, EXCEPT PER SHARE
                                                                            AMOUNTS)
Net Income:
  As reported..............................................     $       168        $        74
  Total stock-based employee compensation determined under
    the fair value based method............................              (3)                (2)
                                                                -----------        -----------
  Pro forma................................................     $       165        $        72
                                                                ===========        ===========
Basic Earnings Per Share:
  As reported..............................................     $      0.56        $      0.24
  Pro forma................................................     $      0.55        $      0.24

Diluted Earnings Per Share:
  As reported..............................................     $      0.56        $      0.24
  Pro forma................................................     $      0.54        $      0.23

6


(b) Employee Benefit Plans.

The Company's net periodic cost includes the following components relating to pension and postretirement benefits:

 

                                                   THREE MONTHS ENDED MARCH 31,
                                     --------------------------------------------------------
                                                2003                          2004
                                     --------------------------    --------------------------
                                     PENSION     POSTRETIREMENT    PENSION     POSTRETIREMENT
                                     BENEFITS       BENEFITS       BENEFITS       BENEFITS
                                     --------    --------------    --------    --------------
                                                          (IN MILLIONS)
Service cost......................   $      9       $      1       $     10       $       1
Interest cost.....................         26              8             26               8
Expected return on plan assets....        (23)            (3)           (26)             (3)
Net amortization..................         11              3              9               3
Other.............................         -               -              -               2
                                     --------    -----------       --------    ------------
Net periodic cost.................   $     23       $      9       $     19       $      11
                                     ========    ===========       ========    ============

The Company previously disclosed in its financial statements for the year ended December 31, 2003, that it expected to contribute $38 million to its postretirement benefits plan in 2004. As of March 31, 2004, $8 million of contributions have been made. Contributions to the pension plan are not required or expected in 2004.

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 March 31, 2003 and 2004 was $2 million and $1 million, respectively.

(3) DISCONTINUED OPERATIONS

Latin America. In February 2003, the Company sold its interest in Argener, a cogeneration facility in Argentina, for $23 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. The Company recorded an after-tax gain of $7 million from the sale of Argener in the first quarter of 2003. The Interim Financial Statements present these Latin America operations as discontinued 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). Accordingly, the Interim Financial Statements include the necessary reclassifications to reflect these operations as discontinued operations for the three months ended March 31, 2003.

Revenues related to the Company's Latin America operations included in discontinued operations for the three months ended March 31, 2003 were $2 million. Income from these discontinued operations for the three months ended March 31, 2003 is reported net of income tax expense of $-0-.

CenterPoint Energy Management Services, Inc. In November 2003, the Company completed the sale of a component of its Other Operations business segment, CenterPoint Energy Management Services, Inc. (CEMS), that provides district cooling services in the Houston central business district and related complementary energy services to district cooling customers and others. The Interim Financial Statements present these CEMS operations as discontinued operations in accordance with SFAS No. 144. Accordingly, the Interim Financial Statements include the necessary reclassifications to reflect these operations as discontinued operations for the three months ended March 31, 2003.

Revenues related to CEMS included in discontinued operations for the three months ended March 31, 2003, were $2 million. The loss from these discontinued operations for the three months ended March 31, 2003 is reported net of income tax benefit of $1 million.

(4) NEW ACCOUNTING PRONOUNCEMENTS

In January 2003, the Financial Accounting Standards Board (FASB) issued FASB Interpretation No. (FIN) 46 "Consolidation of Variable Interest Entities, an Interpretation of Accounting Research Bulletin No. 51" (FIN 46). FIN 46 requires certain variable interest entities to be consolidated by the primary beneficiary of the entity if the equity investors in the entity do not have the characteristics of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support from

7


other parties. On December 24, 2003, the FASB issued a revision to FIN 46 (FIN 46-R). For special-purpose entities (SPE's) created before February 1, 2003, the Company applied the provisions of FIN 46 or FIN 46-R as of December 31, 2003. The revised FIN 46-R is effective for all other entities for financial periods ending after March 15, 2004. The Company has subsidiary trusts that have Mandatorily Redeemable Preferred Securities outstanding. The trusts were determined to be variable interest entities under FIN 46-R and the Company also determined that it is not the primary beneficiary of the trusts. As of December 31, 2003, the Company deconsolidated the trusts and instead reports its junior subordinated debentures due to the trusts as long-term debt. The Company also evaluated two purchase power contracts with qualifying facilities as defined in the Public Utility Regulatory Policies Act of 1978 related to its Electric Generation business segment. The Company concluded it was not required to consolidate the entities that own the qualifying facilities.

On December 23, 2003, the FASB issued SFAS No. 132 (Revised 2003), "Employer's Disclosures about Pensions and Other Postretirement Benefits" (SFAS No. 132(R)) which increases the existing disclosure requirements by requiring more details about pension plan assets, benefit obligations, cash flows, benefit costs and related information. Companies are required to segregate plan assets by category, such as debt, equity and real estate, and to provide certain expected rates of return and other informational disclosures. SFAS No. 132(R) also requires companies to disclose various elements of pension and postretirement benefit costs in interim-period financial statements for quarters beginning after December 15, 2003. The Company has adopted the disclosure requirements of SFAS No. 132(R) in Note 2 to these Interim Financial Statements.

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

(5) REGULATORY MATTERS

(a) 2004 True-Up Proceeding.

On March 31, 2004, CenterPoint Houston, Texas Genco LP and Reliant Energy Retail Services LLC, a former affiliate and current subsidiary of Reliant Energy, Inc. (formerly named Reliant Resources, Inc.) (RRI), filed the final true-up application required by the Texas electric restructuring law with the Public Utility Commission of Texas (Texas Utility Commission). The Texas electric restructuring law authorizes public utilities to recover in 2004 a true-up balance composed of stranded power plant costs, the cost of environmental controls and certain other costs associated with transition from a regulated to a competitive environment (2004 True-Up Proceeding). The Company's true-up balance is $3.8 billion. An additional $631 million in interest could be added if approved in a proceeding pending before the Texas Supreme Court.

The Texas electric restructuring law requires a final order to be issued by the Texas Utility Commission not more than 150 days after a proper filing is made by the regulated utility, although under its rules the Texas Utility Commission can extend the 150-day deadline for good cause. The Texas Utility Commission has scheduled hearings beginning June 21, 2004. The true-up proceeding will result in either additional charges being assessed or credits being issued through the utility's non-bypassable delivery charges. The Texas electric restructuring law permits transmission and distribution utilities to recover the true-up balance through transition charges on their non-bypassable delivery charge, to the extent that such components are established in certain regulatory proceedings. Non-bypassable delivery charges are those that must be paid by essentially all customers and cannot, except in limited circumstances, be avoided by switching to self-generation. The law also authorizes the Texas Utility Commission to permit utilities to issue transition bonds based on the securitization of revenues associated with the transition charges. Any delay in the final order date will result in a delay in the securitization of the true-up

8


components and the implementation of the non-bypassable charges described above, and could delay the recovery of carrying costs on the true-up components determined by the Texas Utility Commission.

CenterPoint Houston will be required to establish and support the $3.8 billion it seeks to recover in the 2004 True-Up Proceeding. Third parties will have the opportunity and are expected to challenge CenterPoint Houston's calculation of these amounts. To the extent recovery of a portion of these amounts is denied or if CenterPoint Houston agrees to forego recovery of a portion of the request under a settlement agreement, CenterPoint Houston would be unable to recover those amounts in the future.

Following adoption of the true-up rule by the Texas Utility Commission in 2001, CenterPoint Houston appealed the provisions of the rule that permitted interest to be recovered on stranded costs only from the date of the Texas Utility Commission's final order in the 2004 True-Up Proceeding, instead of from January 1, 2002 as CenterPoint Houston contends is required by law. On January 30, 2004, the Texas Supreme Court granted CenterPoint Houston's petition for review of the true-up rule. Oral arguments were heard on February 18, 2004. The decision by the Court is pending. The Company has not accrued interest income on stranded costs in its consolidated financial statements.

As of March 31, 2004, CenterPoint Houston has recorded net regulatory assets totaling $3.3 billion, which are expected to be recovered in the 2004 True-Up Proceeding. If events were to occur during the 2004 True-Up Proceeding that made the recovery of these regulatory assets no longer probable, the Company would write off the unrecoverable balance of such assets as a charge against earnings.

(b) Generation Asset Impairment Contingency.

The Company evaluates the recoverability of its long-lived assets in accordance with SFAS No. 144. As of March 31, 2004, no impairment of its Texas generation assets had been indicated. The Company anticipates that future events, such as changes in the market value of Texas Genco common stock, a change in the estimated holding period of the Texas generation assets, or a change in market demand for electricity, will require the Company to re-evaluate these assets for impairment. Changes in any of these assumptions could result in a material impairment charge.

(c) Rate Cases.

On January 6, 2004, new rates went into effect in the City of Houston in accordance with a rate settlement between CenterPoint Energy Entex (Entex) and the City. These settlement rates were subsequently filed with the 28 remaining cities in the Houston Division and with the Railroad Commission of Texas (Texas Railroad Commission). The settlement rates went into effect in 12 of the 28 cities on February 1, 2004 and went into effect for ten additional cities on May 1, 2004. The Texas Railroad Commission is expected to render a decision associated with the unincorporated environs in the near future. Once all remaining regulatory approvals are received, the annualized effect of this multi-jurisdictional rate increase will be approximately $14 million.

(d) Other Regulatory Proceedings.

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 interest, in the fourth quarter of 2003 reflecting the ALJ's recommendation. On April 15, 2004, the Texas Utility Commission reviewed the PFD in CenterPoint Houston's final fuel reconciliation case, affirmed the PFD's finding in part, reversed in part, and remanded one issue back to the ALJ. The Texas Utility Commission's decision is pending the outcome of the remanded issue. The results of the Texas Utility Commission's final decision will be a component of the 2004 True-Up Proceeding.

City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Entex had overcharged residential and small commercial customers in that city for excessive gas costs under supply agreements in effect since 1992. That dispute has been referred to the Texas Railroad Commission by agreement of the parties for a determination of whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending

9


October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs.

(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.

During the three months ended March 31, 2004, no hedge ineffectiveness was recognized in earnings 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. As of March 31, 2004, the Company expects $54 million in accumulated other comprehensive income to be reclassified into net income during the next twelve months.

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 Income.

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. No amortization of this amount was recognized in the first three months of 2003. Amortization of amounts deferred in accumulated other comprehensive income for the three months ended March 31, 2004, was $6 million.

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 March 31, 2004.

(7) GOODWILL AND INTANGIBLES

Goodwill as of December 31, 2003 and March 31, 2004 by reportable business segment is as follows (in millions):

 

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

The Company completed its annual evaluation of goodwill for impairment as of January 1, 2004 and no impairment was indicated.

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

 

                                                           DECEMBER 31, 2003                 MARCH 31, 2004
                                                       ---------------------------     ---------------------------
                                                        CARRYING       ACCUMULATED       CARRYING     ACCUMULATED
                                                         AMOUNT       AMORTIZATION       AMOUNT       AMORTIZATION
                                                       -----------    ------------     -----------    ------------
                                                                             (IN MILLIONS)
Land use rights....................................    $        61    $        (14)    $        61    $        (14)
Other..............................................             38              (5)             38              (6)
                                                       -----------    ------------     -----------    ------------
    Total..........................................    $        99    $        (19)    $        99    $        (20)
                                                       ===========    ============     ===========    ============

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

10


March 31, 2004. 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 March 31, 2003 and 2004 was $1 million. Estimated amortization expense for the remainder of 2004 and the five succeeding fiscal years is as follows (in millions):

 

2004........................................     $     3
2005........................................           3
2006........................................           2
2007........................................           2
2008........................................           2
2009........................................           2
                                                 -------
  Total.....................................     $    14
                                                 =======

(8) COMPREHENSIVE INCOME

The following table summarizes the components of total comprehensive income:

 

                                                                                       FOR THE THREE MONTHS ENDED
                                                                                               MARCH 31,
                                                                                       ---------------------------
                                                                                          2003            2004
                                                                                       -----------     -----------
                                                                                             (IN MILLIONS)
Net income.........................................................................    $       168     $        74
                                                                                       -----------     -----------
Other comprehensive income:
  Net deferred gain (loss) from cash flow hedges...................................             (1)              8
  Reclassification of deferred loss from cash flow hedges realized in net income...              1               1
  Other comprehensive income from discontinued operations..........................              1               -
                                                                                       -----------     -----------
Other comprehensive income.........................................................              1               9
                                                                                       -----------     -----------
Comprehensive income ..............................................................    $       169     $        83
                                                                                       ===========     ===========

(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, 2003, 306,297,147 shares of CenterPoint Energy common stock were issued and 305,385,434 shares of CenterPoint Energy common stock were outstanding. At March 31, 2004, 307,073,026 shares of CenterPoint Energy common stock were issued and 307,072,860 shares of CenterPoint Energy common stock were outstanding. Outstanding common shares exclude (a) shares pledged to secure a loan to CenterPoint Energy's Employee Stock Ownership Plan (911,547 and -0- at December 31, 2003 and March 31, 2004, respectively) and (b) treasury shares (166 at both December 31, 2003 and March 31, 2004). CenterPoint Energy declared a dividend of $0.10 per share in the first quarter of both 2003 and 2004.

Both the 2004 True-Up Proceeding and the monetization of CenterPoint Energy's remaining interest in Texas Genco could result in charges against our earnings. If those charges are of sufficient magnitude, they could reduce our earnings below the level required for us to continue paying our current quarterly dividends out of current earnings as required under our SEC financing order. We have filed an application with the SEC under the 1935 Act requesting an order authorizing us to pay dividends in the second and third quarters of 2004 out of capital or unearned surplus in the event we take such a charge against earnings.

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

(a) Short-term Borrowings.

As of March 31, 2004, Texas Genco had a revolving credit facility that provided for an aggregate of $75 million of committed credit. The revolving credit facility terminates on December 21, 2004. As of March 31, 2004, such credit facility was not utilized.

(b) Long-term Debt.

As of March 31, 2004, CERC Corp. had a revolving credit facility that provided for an aggregate of $250 million in committed credit. The revolving credit facility terminates on March 23, 2007. Fully-drawn rates for borrowings under this facility, including the facility fee, are the London interbank offered rate (LIBOR) plus 150 basis points based on current credit ratings and the applicable pricing grid. As of March 31, 2004, such credit facility was not utilized.

In February 2004, $56 million aggregate principal amount of collateralized
5.6% pollution control bonds due 2027 and $44 million aggregate principal amount of 4.25% collateralized insurance-backed pollution control bonds due 2017 were issued on behalf of CenterPoint Houston. The pollution control bonds are collateralized by general mortgage bonds of CenterPoint Houston with principal amounts, interest rates and maturities that match the pollution control bonds. The proceeds were used to extinguish two series of 6.7% collateralized pollution control bonds with an aggregate principal amount of $100 million issued on behalf of CenterPoint Energy. CenterPoint Houston's 6.7% first mortgage bonds which collateralized CenterPoint Energy's payment obligations under the refunded pollution control bonds were retired in connection with the extinguishment of the refunded pollution control bonds. CenterPoint Houston's 6.7% notes payable to CenterPoint Energy were also cancelled upon the extinguishment of the refunded pollution control bonds.

In March 2004, $45 million aggregate principal amount of 3.625% collateralized insurance-backed pollution control bonds due 2012 and $84 million aggregate principal amount of 4.25% collateralized insurance-backed pollution control bonds due 2017 were issued on behalf of CenterPoint Houston. The pollution control bonds are collateralized by general mortgage bonds of CenterPoint Houston with principal amounts, interest rates and maturities that match the pollution control bonds. The proceeds were used to extinguish two series of 6.375% collateralized pollution control bonds with an aggregate principal amount of $45 million and one series of 5.6% collateralized pollution control bonds with an aggregate principal amount of $84 million issued on behalf of CenterPoint Energy. CenterPoint Houston's 6.375% and 5.6% first mortgage bonds which collateralized CenterPoint Energy's payment obligations under the refunded pollution control bonds were retired in connection with the extinguishment of the refunded pollution control bonds. CenterPoint Houston's
6.375% and 5.6% notes payable to CenterPoint Energy were also cancelled upon the extinguishment of the refunded pollution control bonds.

Junior Subordinated Debentures (Trust Preferred Securities). In February 1997, two Delaware statutory business trusts created by CenterPoint Energy (HL&P Capital Trust I and HL&P Capital Trust II) issued to the public (a) $250 million aggregate amount of preferred securities and (b) $100 million aggregate amount of capital securities, respectively. In February 1999, a Delaware statutory business trust created by CenterPoint Energy (REI Trust I) issued $375 million aggregate amount of preferred securities to the public. Each of the trusts used the proceeds of the offerings to purchase junior subordinated debentures issued by CenterPoint Energy having interest rates and maturity dates that correspond to the distribution rates and the mandatory redemption dates for each series of preferred securities or capital securities. As discussed in Note 4, upon the Company's adoption of FIN 46, the junior subordinated debentures discussed above are included in long-term debt as of December 31, 2003 and March 31, 2004.

The junior subordinated debentures are the trusts' 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 each series of preferred securities or capital securities, taken together, to constitute a full and unconditional guarantee by CenterPoint Energy of each trust's obligations related to the respective series of preferred securities or capital securities.

12


The preferred securities and 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 March 31, 2004, no interest payments on the junior subordinated debentures had been deferred.

The outstanding aggregate liquidation amount, distribution rate and mandatory redemption date of each series of the preferred securities or capital securities of the trusts described above and the identity and similar terms of each related series of junior subordinated debentures are as follows:

 

                                    AGGREGATE LIQUIDATION
                                       AMOUNTS AS OF
                                   ------------------------
                                                               DISTRIBUTION       MANDATORY
                                                                   RATE/         REDEMPTION
                                   DECEMBER 31,   MARCH 31,      INTEREST           DATE/
            TRUST                      2003          2004          RATE         MATURITY DATE    JUNIOR SUBORDINATED DEBENTURES
---------------------------------  ------------   ---------    -------------    -------------   --------------------------------
                                     (IN MILLIONS)

REI Trust I......................  $        375   $     375             7.20%     March 2048    7.20% Junior Subordinated
                                                                                                Debentures

HL&P Capital Trust I(1)..........  $        250   $       -            8.125%     March 2046    8.125% Junior Subordinated
                                                                                                 Deferrable Interest Debentures
                                                                                                Series A

HL&P Capital Trust II............  $        100   $     100            8.257%   February 2037   8.257% Junior Subordinated
                                                                                                Deferrable Interest Debentures
                                                                                                Series B


(1) The preferred securities issued by HL&P Capital Trust I having an aggregate liquidation amount of $250 million were redeemed at 100% of their aggregate liquidation amount in January 2004.

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. As discussed in Note 4, upon the Company's adoption of FIN 46, the junior subordinated debentures discussed above are included in long-term debt as of December 31, 2003 and March 31, 2004.

The convertible preferred securities are mandatorily redeemable upon the repayment of the convertible junior subordinated debentures at their stated maturity or earlier redemption. Effective January 7, 2003, the convertible preferred securities are convertible at the option of the holder into $33.62 of cash and 2.34 shares of CenterPoint Energy common stock for each $50 of liquidation value. As of December 31, 2003 and March 31, 2004, $0.4 million liquidation amount of convertible preferred securities were outstanding. The securities, and their underlying convertible junior subordinated debentures, bear interest at 6.25% and mature in June 2026. Subject to some limitations, CERC Corp. has the option of deferring payments of interest on the convertible junior subordinated debentures. During any deferral or event of default, CERC Corp. may not pay dividends on its common stock to CenterPoint Energy. As of March 31, 2004, no interest payments on the convertible junior subordinated debentures had been deferred.

(c) Receivables Facility.

On January 21, 2004, CERC replaced its $100 million receivables facility with a $250 million receivables facility. The $250 million receivables facility terminates on January 19, 2005. As of March 31, 2004, CERC had fully utilized its receivables facility.

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(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 Reliant Energy 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, but most of the lawsuits remain in early procedural stages. Our 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, CenterPoint Houston or their predecessor, Reliant Energy, were named in approximately 25 of these lawsuits, which were instituted between 2001 and 2004 and are pending in state court in Los Angeles County, in federal district courts in San Francisco, San Diego, Los Angeles and Nevada and before the Ninth Circuit Court of Appeals. However, neither the Company nor Reliant Energy was a participant 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.

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 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 February 2003, a lawsuit was filed by three individuals in federal district court in Chicago against CenterPoint Energy and certain former and current 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

14


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 are asking the court to dismiss.

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 equitable relief in the form of restitution.

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 sets forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleges that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleges breach of fiduciary duty in connection with the spin-off of RRI and the RRI Offering. The complaint seeks 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. 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'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 latter 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.

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 Action. In July 2003, Texas Commercial Energy filed a lawsuit against Reliant Energy, RRI, Reliant Electric Solutions, LLC, several other RRI subsidiaries and a number of other participants in the Electric Reliability Council of Texas (ERCOT) power market in federal court in Corpus Christi, Texas. The plaintiff, a retail electricity provider in the Texas market served by ERCOT, alleges 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 seeks damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. In February 2004, this complaint was amended to add the Company and CenterPoint Houston, as successors to Reliant Energy, and Texas Genco, LP as defendants. The plaintiff's principal allegations have previously been investigated by the Texas Utility Commission and found to be without merit. The Company also believes the plaintiff's allegations are without merit and will seek their dismissal.

Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit, 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 decertified the class and entered a judgment for $1.7 million, including interest, plus an award of $13.7 million in legal fees. Despite other jury findings for the plaintiffs, the trial court's judgment was based on the jury's finding in

15


favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. 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 found that the jury's finding of laches barred all of the Three Cities' claims and that the Three Cities were not entitled to recovery of any attorneys' fees. The Three Cities filed a petition for review at the Texas Supreme Court, which declined to hear the case. The Three Cities filed a motion for rehearing, which was denied by the Supreme Court in April 2004. Now that the Three Cities case has been favorably resolved, the Company intends to seek dismissal of the claims of the other cities.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. 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 their ultimate outcome would 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 others alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed against CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by CERC. In February 2004, another suit was filed against CERC in Calcasieu Parish, Louisiana, seeking to recover alleged overcharges for gas or gas services allegedly provided by Entex without advance approval by the Louisiana Public Service Commission. The plaintiffs in these cases seek injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages and civil penalties. In these cases, the Company, CERC and Entex Gas Marketing Company deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities. 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.

16


(b) Environmental Matters.

Clean Air Standards. The Texas electric restructuring law and regulations adopted by the Texas Commission on Environmental Quality (TCEQ) in 2001 require substantial reductions in emission of oxides of nitrogen (NOx) from electric generating units. The Company is currently installing cost-effective controls at its generating plants to comply with these requirements. Through March 31, 2004, the Company has invested $679 million for NOx emission control, and plans to make additional expenditures of up to approximately $116 million during the remainder of 2004 through 2007. Further revisions to these NOx requirements may result from the EPA's ongoing review of these TCEQ rules and from the TCEQ's future rules, expected by 2007, implementing more stringent federal eight-hour ozone standards. The Texas electric restructuring law provides for stranded cost recovery for expenditures incurred before May 1, 2003 to achieve the NOx reduction requirements. Incurred costs include costs for which contractual obligations have been made. The Texas Utility Commission has determined that the Company's emission control plan is the most cost-effective option for achieving compliance with applicable air quality standards for the Company's generating facilities and the final amount for recovery will be determined in the 2004 True-Up Proceeding. The Company is limited to a maximum recovery of $699 million excluding allowance for funds used during construction and capitalized interest, as previously determined by the Texas Utility Commission.

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. The Company is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters.

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory, two of which CERC believes were neither owned nor operated by CERC, and for which CERC believes it has no liability.

At March 31, 2004, CERC had accrued $19 million for remediation of certain Minnesota sites. At March 31, 2004, the estimated range of possible remediation costs for these sites was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. CERC has collected or accrued $12 million as of March 31, 2004 to be used for environmental remediation.

CERC has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for other 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

17


expenditures for potential remediation. Based on current information, the Company has not been able to quantify a range of potential environmental expenditures for such sites.

Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows.

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims that it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows.

(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 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.

(d) 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 March 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 of the South Texas Project 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 incident per year.

There can be no assurance that all potential losses or liabilities 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 the Company's financial condition, results of operations and cash flows.

18


(e) Nuclear Decommissioning.

CenterPoint Houston contributed $2.9 million in 2003 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 2004. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and the United States Nuclear Regulatory Commission (NRC) relating to Texas Genco's nuclear decommissioning trusts. Texas Genco and CenterPoint Energy 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 $201 million as of March 31, 2004, of which approximately 36% were fixed-rate debt securities and the remaining 64% were equity securities. In July 1999, an outside consultant estimated Texas Genco's portion of decommissioning costs to be approximately $363 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 have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a charge to transmission and distribution customers of CenterPoint Houston or its successor.

19


(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
                                                                                             MARCH 31,
                                                                                 ---------------------------------
                                                                                     2003                2004
                                                                                 --------------     --------------
                                                                                  (IN MILLIONS, EXCEPT SHARE AND
                                                                                        PER SHARE AMOUNTS)
Basic EPS Calculation:
  Income from continuing operations before cumulative effect of accounting
    change...................................................................    $           81     $           74
  Discontinued operations, net of tax........................................                 7                  -
  Cumulative effect of accounting change, net of tax.........................                80                  -
                                                                                 --------------     --------------
  Net income ................................................................    $          168     $           74
                                                                                 ==============     ==============
Weighted average shares outstanding..........................................       301,664,000        306,012,000
                                                                                 ==============     ==============
Basic EPS:
  Income from continuing operations before cumulative effect of accounting
    change...................................................................    $         0.27     $         0.24
  Discontinued operations, net of tax........................................              0.02                  -
  Cumulative effect of accounting change, net of tax.........................              0.27                  -
                                                                                 --------------     --------------
  Net income.................................................................    $         0.56     $         0.24
                                                                                 ==============     ==============
Diluted EPS Calculation:
  Net income.................................................................    $          168     $           74
  Plus: Income impact of assumed conversions:
    Interest on 6 1/4% convertible trust preferred securities................                 -                  -
                                                                                 --------------     --------------
  Total earnings effect assuming dilution....................................    $          168     $           74
                                                                                 ==============     ==============
Weighted average shares outstanding..........................................       301,664,000        306,012,000
  Plus: Incremental shares from assumed conversions (1):
    Stock options............................................................           258,000          1,261,000
    Restricted stock.........................................................         1,338,000            861,000
    6 1/4% convertible trust preferred securities............................            18,000             17,000
                                                                                 --------------     --------------
  Weighted average shares assuming dilution..................................       303,278,000        308,151,000
                                                                                 ==============     ==============
Diluted EPS:
Income from continuing operations before cumulative effect of
  accounting change..........................................................    $         0.27     $         0.24
Discontinued operations, net of tax..........................................              0.02                  -
Cumulative effect of accounting change, net of tax...........................              0.27                  -
                                                                                 --------------     --------------
  Net income.................................................................    $         0.56     $         0.24
                                                                                 ==============     ==============


(1) For the three months ended March 31, 2003 and 2004, the computation of diluted EPS excludes 10,249,849 and 12,051,118 purchase options, respectively, for shares of common stock that have exercise prices (ranging from $7.86 to $34.17 per share and $10.92 to $32.26 per share for the first quarter of 2003 and 2004, respectively) greater than the per share average market price for the period and would thus be anti-dilutive if exercised. The Company's contingently convertible debt is not considered for purposes of diluted earnings per share because the required conversion criteria had not been met as of the end of the reporting period.

20


(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 Latin America operations and its energy management services business, which were previously reported in the Other Operations business segment, are presented as discontinued operations within these Interim Financial Statements.

The Company has identified the following reportable business segments:
Electric Transmission & Distribution, Electric Generation, Natural Gas Distribution, Pipelines and Gathering and Other Operations. Reportable business segments for all prior periods have been restated to conform to the 2004 presentation.

Financial data for the Company's reportable business segments are as follows:

 

                                                                                                           AS OF
                                                     FOR THE THREE MONTHS ENDED MARCH 31, 2003       DECEMBER 31, 2003
                                                  ----------------------------------------------     -----------------
                                                                          NET
                                                  REVENUES FROM       INTERSEGMENT     OPERATING
                                                  NON-AFFILIATES        REVENUES         INCOME        TOTAL ASSETS
                                                  --------------      ------------     ---------     -----------------
                                                                           (IN MILLIONS)
Electric Transmission & Distribution............  $          448 (1)  $          -     $     206     $          10,326
Electric Generation.............................             359 (2)             -           (17)                4,640
Natural Gas Distribution........................           2,028                17           129                 4,661
Pipelines and Gathering.........................              61                48            43                 2,519
Other Operations................................               4                 5             -                 1,347
Eliminations....................................               -               (70)            -                (2,116)
                                                  --------------      ------------     ---------     -----------------
Consolidated....................................  $        2,900      $          -     $     361     $          21,377
                                                  ==============      ============     =========     =================

 

                                                                                                       AS OF
                                                   FOR THE THREE MONTHS ENDED MARCH 31, 2004       MARCH 31, 2004
                                                  ---------------------------------------------    --------------
                                                                          NET
                                                  REVENUES FROM       INTERSEGMENT    OPERATING
                                                  NON-AFFILIATES        REVENUES        INCOME      TOTAL ASSETS
                                                  --------------      ------------    ---------    --------------
                                                                           (IN MILLIONS)
Electric Transmission & Distribution ...........  $          329 (1)  $          -    $      85    $       10,234
Electric Generation.............................             439 (2)             -           90             4,619
Natural Gas Distribution........................           2,124                 7          117             4,691
Pipelines and Gathering.........................              65                37           45             2,481
Other Operations................................               2                 1           (2)            1,423
Eliminations....................................               -               (45)           -            (2,388)
                                                  --------------      ------------    ---------    --------------
Consolidated....................................  $        2,959      $          -    $     335    $       21,060
                                                  ==============      ============    =========    ==============


(1) Sales to subsidiaries of RRI for the three months ended March 31, 2003 and 2004 represented approximately $212 million and $199 million, respectively, of CenterPoint Houston's transmission and distribution revenues.

(2) Sales to subsidiaries of RRI for the three months ended March 31, 2003 and 2004 represented approximately 68% and 58%, respectively, of Texas Genco's total revenues. Sales to another major customer for the three months ended March 31, 2003 and 2004 represented approximately 10% and 19%, respectively, of Texas Genco's total revenues.

21


 
ITEM 2. MANAGEMENT'S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY 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

1ST QUARTER 2004 HIGHLIGHTS

Our operating performance and cash flow for the first quarter of 2004 compared to the first quarter of 2003 were affected by:

- improved operating income from Texas Genco Holdings, Inc. (Texas Genco) of $107 million;

- continued customer growth, with the addition of nearly 87,000 metered electric and gas customers;

- a decrease in interest expense of $33 million;

- a reduction of $21 million in capital expenditures;

- the termination of revenues related to Excess Cost Over Market (ECOM) as of January 1, 2004 compared to ECOM revenues of $132 million recorded in the first quarter of 2003;

- milder weather in 2004, impacting the quarter by $16 million; and

- a charge of $8 million related to staff reductions in the Natural Gas Distribution business segment.

SIGNIFICANT EVENTS IN 2004

The 1999 Texas Electric Choice Law (Texas electric restructuring law) contains provisions that allow our transmission and distribution utility, CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), to recover the amount by which the market value of our generating assets, as determined by the Public Utility Commission of Texas (Texas Utility Commission) under a formula prescribed in the law, is below the regulatory net book value of those assets as of the end of 2001. It also allows CenterPoint Houston to recover certain other transition costs, such as a final fuel reconciliation balance, regulatory assets and the difference between the Texas Utility Commission's projected market prices for generation during 2002 and 2003 and actual market prices for generation as determined in the state-mandated capacity auctions during that period (called the ECOM true-up). Those amounts, and certain other adjustments (the true-up balance), are to be determined by the Texas Utility Commission in a proceeding that began on March 31, 2004 (2004 True-Up Proceeding). Our true-up balance is $3.8 billion, excluding interest. The law requires a final order to be issued by the Texas Utility Commission not more than 150 days after a proper filing is made by the regulated utility, although, under its rules the Texas Utility Commission can extend the 150-day deadline for good cause. The Texas Utility Commission has scheduled hearings beginning June 21, 2004. Various parties have intervened in our true-up proceeding, and we expect intervenors to vigorously oppose recovery of the amounts we are seeking. After the Texas Utility Commission determines the amount of the true-up balance that the utility may recover, the utility will recover those amounts through a transition charge added to its non-bypassable delivery charge. An ultimate determination or a settlement at an amount less than that recorded in our financial statements could lead to a charge that would materially adversely affect our results of operations, financial condition and cash flows. Assuming receipt of a timely final order from the Texas Utility Commission, we expect to begin earning a rate of return on the true-up balance in the third quarter of 2004. We intend to seek authority from the Texas Utility Commission to securitize all or a portion of the true-up balance as early as the fourth quarter of 2004 through the issuance of transition bonds and to be in a position to issue those bonds by early 2005. Transition bonds would be issued through a special purpose entity that would be a subsidiary of CenterPoint Houston, but they would be non-recourse to CenterPoint Houston. Any portion of the true-up balance not securitized by transition bonds will be recovered through a non-bypassable competition transition charge. CenterPoint Houston will distribute recovery of the true-up components not used to repay indebtedness to us through either the payment of dividends or the

22

settlement of intercompany payables. We can then move funds back to CenterPoint Houston, either through equity or intercompany debt, in order to maintain CenterPoint Houston's capital structure at the appropriate levels.

In January 2004, Reliant Energy, Inc. (formerly named Reliant Resources, Inc.) (RRI) did not exercise its option to purchase our 81% interest in Texas Genco. We have engaged a financial advisor to assist us in the sale of our interest in Texas Genco. We are currently providing interested parties information about Texas Genco and its operations. There can be no assurance that we will receive any definitive bids for our interest in Texas Genco or that any bids we do receive will be acceptable to us. Any proceeds from the monetization of Texas Genco are expected to be used to repay indebtedness. We expect to have determined our best course of action regarding the possible disposition of our interest in Texas Genco in 2004.

The alternatives for monetization of our remaining interest in Texas Genco may not be completed in 2004 and may result in receipt of proceeds in an amount different from the market valuation placed on Texas Genco in the 2004 True-Up Proceeding. To the extent that the Texas Utility Commission uses a market value higher than the amount ultimately realized from the sale of Texas Genco, a loss would be recognized. The completion of the 2004 True-Up Proceeding and recovery of stranded costs is not dependent on the sale of Texas Genco.

Resolution of the 2004 True-Up Proceeding and the monetization of our remaining interest in Texas Genco are the two most significant events facing the company in 2004. These events are expected to result in aggregate proceeds of over $5 billion based on the Texas Utility Commission rules and our estimate of the ultimate sales price of our interest in Texas Genco. We expect to use these proceeds to repay our indebtedness. Either or both events could, however, lead to charges against earnings. If those charges are of sufficient magnitude, they could reduce our earnings below the level required for us to continue paying our current quarterly dividends out of current earnings as required under our Securities and Exchange Commission (SEC) financing order. We have filed an application with the SEC under the 1935 Act requesting an order authorizing us to pay dividends in the second and third quarters of 2004 out of capital or unearned surplus in the event we are required to take such a charge against earnings.

Following adoption of the true-up rule by the Texas Utility Commission in 2001, CenterPoint Houston appealed the provisions of the rule that permitted interest to be recovered on stranded costs only from the date of the Texas Utility Commission's final order in the 2004 True-Up Proceeding, instead of from January 1, 2002 as CenterPoint Houston contends is required by law. On January 30, 2004, the Texas Supreme Court granted our petition for review of the true-up rule. Oral arguments were heard on February 18, 2004. The decision by the Court is pending. We have not accrued interest income on stranded costs of approximately $631 million in our consolidated financial statements.

RECENT DEVELOPMENTS

In March 2004, AEP Central Texas Company (AEP), one of Texas Genco's co-owners in the South Texas Project Electric Generating Station (South Texas Project), notified Texas Genco that it has received an offer by a third party to purchase its entire 25.2 percent ownership interest in the South Texas Project for $332.6 million, subject to certain adjustments at closing. Under the terms of the agreements among the owners of the South Texas Project, Texas Genco and each of the other two co-owners have the right to purchase AEP's interest for the cash price offered by the third party. To exercise the right of first refusal, Texas Genco must give notice to AEP within three months of their notice to Texas Genco. If more than one owner elects to purchase all or a portion of the interest being sold, the interest will be prorated among the owners seeking to purchase AEP's interest in proportion to their ownership interests in the South Texas Project. Texas Genco is currently evaluating the offer received, but has not made a decision whether to exercise its rights.

23

 
CONSOLIDATED RESULTS OF OPERATIONS

                                                                                         THREE MONTHS ENDED MARCH 31,
                                                                                    ------------------------------------
                                                                                            2003            2004
                                                                                          --------        --------
                                                                                    (IN MILLIONS, EXCEPT PER SHARE DATA)

Revenues .........................................................................          $ 2,900         $ 2,959
Expenses .........................................................................           (2,539)         (2,624)
                                                                                            -------         -------
Operating Income .................................................................              361             335
Interest and Other Finance Charges ...............................................             (238)           (205)
Other Income, net ................................................................               (3)              5
                                                                                            -------         -------
Income From Continuing Operations Before Income Taxes, Minority Interest and
  Cumulative Effect of Accounting Change .........................................              120             135
Income Tax Expense ...............................................................              (41)            (50)
Minority Interest ................................................................                2             (11)
                                                                                            -------         -------
Income From Continuing Operations Before Cumulative Effect of Accounting Change ..               81              74
Discontinued Operations, net of tax ..............................................                7              --
Cumulative Effect of Accounting Change, net of tax ...............................               80              --
                                                                                            -------         -------
Net Income .......................................................................          $   168         $    74
                                                                                            =======         =======
BASIC EARNINGS PER SHARE:
  Income From Continuing Operations Before Cumulative Effect of Accounting
    Change .......................................................................          $  0.27         $  0.24
  Discontinued Operations, net of tax ............................................             0.02              --
  Cumulative Effect of Accounting Change, net of tax .............................             0.27              --
                                                                                            -------         -------
  Net Income .....................................................................          $  0.56         $  0.24
                                                                                            =======         =======

DILUTED EARNINGS PER SHARE:
  Income From Continuing Operations Before Cumulative Effect of Accounting
    Change .......................................................................          $  0.27         $  0.24
  Discontinued Operations, net of tax ............................................             0.02              --
  Cumulative Effect of Accounting Change, net of tax .............................             0.27              --
                                                                                            -------         -------
  Net Income .....................................................................          $  0.56         $  0.24
                                                                                            =======         =======

THREE MONTHS ENDED MARCH 31, 2004 COMPARED TO THREE MONTHS ENDED MARCH 31, 2003

Income from Continuing Operations. We reported income from continuing operations of $74 million ($0.24 per diluted share) for the three months ended March 31, 2004 as compared to $81 million ($0.27 per diluted share) for the same period in 2003 before cumulative effect of accounting change. The decrease in income from continuing operations of $7 million was primarily due to the termination of revenues in our Electric Transmission & Distribution business segment related to ECOM as of January 1, 2004 compared to ECOM revenues of $132 million recorded in the first quarter of 2003, a reduction of $16 million in revenues from our Electric Transmission & Distribution and Natural Gas Distribution business segments due to milder weather in the first quarter of 2004 and an $8 million charge for severance cost associated with staff reductions in our Natural Gas Distribution business segment. These decreases were substantially offset by a $107 million increase in operating income from our Electric Generation business segment and a $33 million decrease in interest expense due to lower borrowing costs.

Cumulative Effect of Accounting Change. In connection with the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, "Accounting for Asset Retirement Obligations" (SFAS No. 143), effective January 1, 2003, we completed an assessment of the applicability and implications of SFAS No. 143. As a result of the assessment, we identified retirement obligations for nuclear decommissioning at the South Texas Project and for lignite mine operations at the Jewett mine supplying the Limestone electric generation facility. The net difference between the amounts determined under SFAS No. 143 and the previous method of accounting for estimated mine reclamation costs was $37 million and has been recorded as a cumulative effect of accounting change. Upon adoption of SFAS No. 143, we reversed $115 million of previously recognized removal costs with respect to our non-rate regulated businesses as a cumulative effect of accounting change. The total cumulative effect of accounting

24

change from adoption of SFAS No. 143 was $80 million after-tax ($152 million pre-tax). Excluded from the $80 million after-tax cumulative effect of accounting change recorded for the three months ended March 31, 2003, is minority interest of $19 million related to the Texas Genco stock not owned by CenterPoint Energy.

 

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income for each of our business segments for the three months ended March 31, 2003 and 2004. Some amounts from the previous year have been reclassified to conform to the 2004 presentation of the financial statements. These reclassifications do not affect consolidated net income.

                                                THREE MONTHS ENDED MARCH 31,
                                                ----------------------------
                                                      2003       2004
                                                      ----       ----
                                                       (IN MILLIONS)
Electric Transmission & Distribution .........       $ 206       $  85
Electric Generation ..........................         (17)         90
Natural Gas Distribution .....................         129         117
Pipelines and Gathering ......................          43          45
Other Operations .............................          --          (2)
                                                     -----       -----
      Total Consolidated Operating Income.....       $ 361       $ 335
                                                     =====       =====

ELECTRIC TRANSMISSION & DISTRIBUTION

For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read "Business -- Risk Factors -- Principal Risk Factors Associated with Our Businesses -- Risk Factors Affecting Our Electric Transmission & Distribution Business," " -- Risk Factors Associated with Our Consolidated Financial Condition" and " -- Other Risks" in Item 1 of the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2003 (CenterPoint Energy Form 10-K), each of which is incorporated herein by reference.

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three months ended March 31, 2003 and 2004:

 

                                                         THREE MONTHS ENDED MARCH 31,
                                                         ----------------------------
                                                              2003         2004
                                                             -------     -------
                                                                 (IN MILLIONS)
Revenues:
  Electric transmission and distribution revenues.....       $   303     $   314
  ECOM revenues ......................................           132          --
  Transition bond revenues ...........................            13          15
                                                             -------     -------
    Total revenues ...................................           448         329
                                                             -------     -------
Expenses:
  Operation and maintenance ..........................           133         132
  Depreciation and amortization ......................            62          60
  Taxes other than income taxes ......................            44          47
  Transition bond expenses ...........................             3           5
                                                             -------     -------
    Total expenses ...................................           242         244
                                                             -------     -------
Operating Income .....................................       $   206     $    85
                                                             =======     =======

Actual gigawatt-hours (GWh) delivered:
  Residential ........................................         4,558       4,402
  Total (1) ..........................................        14,788      15,520



(1) Usage volumes for commercial and industrial customers are included in total GWh delivered; however, the majority of these customers are billed on a peak demand (KW) basis and, as a result, revenues do not vary based on consumption.

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Our Electric Transmission & Distribution business segment reported operating income of $85 million for the three months ended March 31, 2004, consisting of $75 million for the regulated electric transmission and distribution utility and $10 million for the transition bond company. For the three months ended March 31, 2003, operating income totaled $206 million, consisting of $64 million for the regulated electric transmission and distribution utility, $10 million for the transition bond company and $132 million of non-cash income associated with ECOM. ECOM is recoverable under the Texas electric restructuring law and is included in our recently filed true-up application. Beginning in 2004, there is no ECOM contribution to earnings. The transition bond company's operating income represents the amount necessary to pay interest on the transition bonds. The regulated electric transmission and distribution utility continues to benefit from solid customer growth. Revenues increased $9 million for the three months ended March 31, 2004 as compared to the same period in 2003 from the addition of 48,000 metered customers since March 2003. This increase was partially offset by milder weather which negatively impacted the quarter by $6 million.

ELECTRIC GENERATION

For information regarding factors that may affect the future results of operations of our Electric Generation business segment, please read "Business -- Risk Factors -- Principal Risk Factors Associated with Our Businesses -- Risk Factors Affecting Our Electric Generation Business," " -- Risk Factors Associated with Our Consolidated Financial Condition" and " -- Other Risks" in  
Item 1 of the CenterPoint Energy Form 10-K, each of which is incorporated herein by reference.

The following tables provide summary data of our Electric Generation business segment for the three months ended March 31, 2003 and 2004:

                                                   THREE MONTHS ENDED MARCH 31,
                                                   ----------------------------
                                                         2003         2004
                                                       --------     -------
                                                           (IN MILLIONS)
Revenues .........................................     $   359      $   439
                                                       -------      -------
Expenses:
  Fuel ...........................................         208          187
  Purchased power ................................          12            8
  Operation and maintenance ......................         106          102
  Depreciation and amortization ..................          39           40
  Taxes other than income taxes ..................          11           12
                                                       -------      -------
    Total expenses ...............................         376          349
                                                       -------      -------
Operating Income (Loss) ..........................     $   (17)     $    90
                                                       =======      =======

Sales (in GWh) ...................................       9,276       10,721
Generation (in GWh) ..............................       8,995       10,149

Our Electric Generation business segment's operating income for the three months ended March 31, 2004 was $90 million compared to a loss of $17 million for the same period in 2003. Revenues increased $80 million in the first quarter of 2004 as compared to the same period in 2003 due to higher capacity revenue for base-load products driven by continued high natural gas prices. Most of these base-load products were sold in capacity auctions held when natural gas prices were higher than when we sold our capacity for 2003. Additionally, the sale of surplus air emission allowances contributed $4 million to the increase in revenues. Fuel and purchased power costs declined $25 million in the first quarter of 2004 as compared to the same period in 2003 reflecting the increase in availability of our lower-cost base-load units in 2004, lower gas prices in 2004 and lower demand for gas-fired generation products. Operation and maintenance expenses decreased $4 million primarily due to a reduction in planned and unplanned outages in the first quarter of 2004 as compared to the same period in 2003.

NATURAL GAS DISTRIBUTION

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read "Business -- Risk Factors -- Principal Risk Factors Associated with Our Businesses -- 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 1 of the CenterPoint Energy Form 10-K, each of which is incorporated herein by reference.

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The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2003 and 2004:

 

                                                             THREE MONTHS ENDED MARCH 31,
                                                             ----------------------------
                                                                   2003         2004
                                                                 --------     --------
                                                                     (IN MILLIONS)
Revenues ...................................................     $ 2,045      $ 2,131
                                                                 -------      -------
Expenses:
  Natural gas ..............................................       1,694        1,790
  Operation and maintenance ................................         148          149
  Depreciation and amortization ............................          33           35
  Taxes other than income taxes ............................          41           40
                                                                 -------      -------
    Total expenses .........................................       1,916        2,014
                                                                 -------      -------
Operating Income ...........................................     $   129      $   117
                                                                 =======      =======

Throughput (in billion cubic feet (Bcf)):
  Residential ..............................................          94           85
  Commercial and industrial ................................          89           83
  Non-rate regulated commercial and industrial .............         129          139
  Elimination ..............................................         (15)         (10)
                                                                 -------      -------
    Total Throughput .......................................         297          297
                                                                 =======      =======

Our Natural Gas Distribution business segment reported operating income of $117 million for the three months ended March 31, 2004 as compared to $129 million for the same period in 2003. Continued customer growth, with the addition of over 38,000 customers since March 2003, and higher revenues of $3 million from rate increases were more than offset by the impact of milder weather of $10 million and reduced contributions from our competitive commercial and industrial sales business. Operations and maintenance expense increased $1 million for the three months ended March 31, 2004 as compared to the same period in 2003. The increase was primarily due to an $8 million charge for severance cost associated with staff reductions, which will reduce costs in future periods. Excluding this charge, operation and maintenance expenses decreased by $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 "Business -- Risk Factors -- Principal Risk Factors Associated with Our Businesses -- 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 1 of the CenterPoint Energy Form 10-K, each of which is incorporated herein by reference.

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The following table provides summary data of our Pipelines and Gathering business segment for the three months ended March 31, 2003 and 2004:

 

                                               THREE MONTHS ENDED MARCH 31,
                                               ----------------------------
                                                     2003         2004
                                                   --------     --------
                                                       (IN MILLIONS)
Revenues ...................................       $ 109      $ 102
                                                   -----      -----
Expenses:
  Natural gas ..............................          21          9
  Operation and maintenance ................          30         33
  Depreciation and amortization ............          11         11
  Taxes other than income taxes ............           4          4
                                                   -----      -----
    Total expenses .........................          66         57
                                                   -----      -----
Operating Income ...........................       $  43      $  45
                                                   =====      =====

Throughput (in Bcf):
  Natural Gas Sales ........................           4          2
  Transportation ...........................         268        270
  Gathering ................................          72         75
  Elimination (1) ..........................          (2)        (2)
                                                   -----      -----
    Total Throughput .......................         342        345
                                                   =====      =====



(1) Elimination of volumes both transported and sold.

Our Pipelines and Gathering business segment reported operating income of $45 million for the three months ended March 31, 2004 compared to $43 million for the same period in 2003. The improvement was primarily due to higher utilization of storage services, higher interruptible transportation margins, increased throughput and enhanced services related to our gas gathering operations and lower natural gas prices. Operation and maintenance expenses increased $3 million for the three months ended March 31, 2004 compared to the same period in 2003 primarily due to spending related to pipeline integrity and higher employee-related costs.

 
OTHER OPERATIONS

The following table shows operating income of our Other Operations business segment for the three months ended March 31, 2003 and 2004:

                                 THREE MONTHS ENDED MARCH 31,
                                 ----------------------------
                                       2003       2004
                                       -----     ------
                                         (IN MILLIONS)
Revenues.......................        $   9     $   3
Expenses.......................            9         5
                                       -----     -----
Operating Income (Loss)........        $  --     $  (2)
                                       =====     =====

DISCONTINUED OPERATIONS

In February 2003, we sold our interest in Argener, a cogeneration facility in Argentina, for $23 million. The carrying value of this investment was approximately $11 million as of December 31, 2002. We recorded an after-tax gain of $7 million from the sale of Argener in the first quarter of 2003. We have completed our strategy of exiting all of our international investments. The Interim Financial Statements present these operations as discontinued operations in accordance with SFAS No. 144 for the three months ended March 31, 2003.

In November 2003, we sold a component of our Other Operations business segment, CenterPoint Energy Management Services, Inc. (CEMS), that provides district cooling services in the Houston central business district and related complementary energy services to district cooling customers and others. The Interim Financial Statements present these operations as discontinued operations in accordance with SFAS No. 144 for the three months ended March 31, 2003.

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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 CenterPoint Energy Form 10-K and "Risk Factors" in Item 1 of Part I of the CenterPoint Energy Form 10-K, each of which is incorporated herein by reference. In addition to these factors, the discontinuation of non-cash operating income associated with ECOM is expected to negatively impact our earnings in 2004.

 

LIQUIDITY AND CAPITAL RESOURCES

HISTORICAL CASH FLOWS

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the three months ended March 31, 2003 and 2004:

                                           THREE MONTHS ENDED MARCH 31,
                                           ----------------------------
                                                 2003       2004
                                                ------     ------
                                                  (IN MILLIONS)
Cash provided by (used in):
   Operating activities .................       $   6      $ 393
   Investing activities .................        (146)      (128)
   Financing activities .................         121       (190)

CASH PROVIDED BY OPERATING ACTIVITIES

Cash provided by operating activities increased $387 million for the three months ended March 31, 2004 as compared to the same period in 2003 primarily due to increased cash flow from Texas Genco substantially due to higher capacity revenues driven by continued high natural gas prices ($88 million), and decreased accounts receivable attributable to a higher level of accounts receivable being sold under CERC Corp.'s factoring agreement ($100 million). Additionally, other changes in working capital items, primarily decreased net accounts receivable and accounts payable due to the impact of lower natural gas prices and milder weather in the first quarter of 2004 as compared to the same period in 2003 ($130 million), contributed to the overall increase in cash provided by operating activities.

CASH USED IN INVESTING ACTIVITIES

Net cash used in investing activities decreased $18 million for the three months ended March 31, 2004 as compared to the same period in 2003 due primarily to decreased environmental-related capital expenditures in our Electric Generation business segment and decreased capital expenditures in our Electric Transmission & Distribution business segment primarily resulting from delayed spending due to inclement weather.

CASH PROVIDED BY (USED IN) FINANCING ACTIVITIES

During the first three months of 2004, debt payments exceeded net loan proceeds by $159 million. During the first three months of 2003, net loan proceeds exceeded debt payments by $155 million.

FUTURE SOURCES AND USES OF CASH

Our liquidity and capital requirements will be affected by:

- capital expenditures;

- debt service requirements;

- various regulatory actions; and

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- working capital requirements.

The 1935 Act regulates our financing ability, as more fully described in " -- Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay Dividends on Our Common Stock" below.

Off-Balance Sheet Arrangements. Other than operating leases, we have no off-balance sheet arrangements. However, we do participate in a receivables factoring arrangement. On January 21, 2004, CERC Corp. replaced its $100 million receivables facility with a $250 million receivables facility. The $250 million receivables facility terminates on January 19, 2005. As of March 31, 2004, CERC Corp. had fully utilized its receivables facility.

Long-term and Short-term Debt. Our long-term debt consists of our obligations and the obligations of our subsidiaries, including transition bonds issued by an indirect wholly owned subsidiary (transition bonds).

As of March 31, 2004, we had the following revolving credit facilities (in millions):

 

                                               SIZE OF           AMOUNT
                                             FACILITY AT     OUTSTANDING AT
                                              MARCH 31,        MARCH 31,
  DATE EXECUTED            COMPANY              2004             2004             TERMINATION DATE
  -------------            -------              ----             ----             ----------------
  March 23, 2004         CERC Corp.           $    250         $   --              March 23, 2007
 October 7, 2003     CenterPoint Energy          1,425            735             October 7, 2006
December 23, 2003      Texas Genco, LP              75             --            December 21, 2004

On March 23, 2004, CERC Corp. replaced its $200 million revolving credit facility with a $250 million revolving credit facility that terminates on March 23, 2007. Fully-drawn rates for borrowings under this facility, including the facility fee, are LIBOR plus 150 basis points based on current credit ratings and the applicable pricing grid.

In February 2004, $56 million aggregate principal amount of collateralized
5.60% pollution control bonds due 2027 and $44 million aggregate principal amount of 4.25% collateralized insurance-backed pollution control bonds due 2017 were issued on behalf of CenterPoint Houston. The pollution control bonds are collateralized by general mortgage bonds of CenterPoint Houston with principal amounts, interest rates and maturities that match the pollution control bonds. The proceeds were used to extinguish two series of 6.7% collateralized pollution control bonds with an aggregate principal amount of $100 million issued on our behalf. CenterPoint Houston's 6.7% first mortgage bonds, which collateralized our payment obligations under the refunded pollution control bonds, were retired in connection with the extinguishment of the refunded pollution control bonds. CenterPoint Houston's 6.7% notes payable to us were cancelled upon the extinguishment of the refunded pollution control bonds.

In March 2004, $45 million aggregate principal amount of 3.625% collateralized insurance-backed pollution control bonds due 2012 and $84 million aggregate principal amount of 4.25% collateralized insurance-backed pollution control bonds due 2017 were issued on behalf of CenterPoint Houston. The pollution control bonds are collateralized by general mortgage bonds of CenterPoint Houston with principal amounts, interest rates and maturities that match the pollution control bonds. The proceeds were used to extinguish two series of 6.375% collateralized pollution control bonds with an aggregate principal amount of $45 million and one series of 5.6% collateralized pollution control bonds with an aggregate principal amount of $84 million issued on our behalf. CenterPoint Houston's 6.375% and 5.6% first mortgage bonds which collateralized our payment obligations under the refunded pollution control bonds were retired in connection with the extinguishment of the refunded pollution control bonds. CenterPoint Houston's 6.375% and 5.6% notes payable to us were cancelled upon the extinguishment of the refunded pollution control bonds.

On March 31, 2004, we had temporary external investments of $160 million.

At March 31, 2004, CenterPoint Energy had a shelf registration statement covering 15 million shares of common stock and CERC Corp. had a shelf registration statement covering $50 million principal amount of debt securities.

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Cash Requirements in 2004. Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, and working capital needs. Our principal cash requirements during the remainder of 2004, assuming we continue to own our interest in Texas Genco for the full year, include the following:

- approximately $571 million of capital expenditures;

- an estimated $183 million in refunds by CenterPoint Houston of excess mitigation credits through December 31, 2004;

- dividend payments on CenterPoint Energy common stock; and

- $35 million of maturing long-term debt, including $27 million of transition bonds.

We expect that revolving credit borrowings and anticipated cash flows from operations will be sufficient to meet our cash needs for 2004. Our $2.3 billion credit facility provides that, until such time as the credit facility has been reduced to $750 million, all of the net cash proceeds from any securitizations relating to the recovery of the true-up components, after making any payments required under CenterPoint Houston's term loan, and the net cash proceeds of any sales of the common stock of Texas Genco that we own, or of material portions of Texas Genco's assets, shall be applied to repay borrowings under our credit facility and reduce the amount available under the credit facility. Our $2.3 billion credit facility contains no other restrictions with respect to our use of proceeds from financing activities. CenterPoint Houston's term loan 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 term loan, subject to certain exceptions, limits the application of proceeds from capital markets transactions by CenterPoint Houston over $200 million to repayment of debt existing in November 2002.

CenterPoint Houston will distribute recovery of the true-up components not used to repay indebtedness to us through either the payment of dividends or the settlement of intercompany payables. We can then move funds back to CenterPoint Houston, either through equity or intercompany debt, in order to maintain CenterPoint Houston's capital structure at the appropriate levels. Under the orders described under " -- Certain Contractual and Regulatory Limits on Ability to Issue Securities and Pay Dividends on Our Common Stock," CenterPoint Houston's member's equity as a percentage of total capitalization must be at least 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.

Impact on Liquidity of a Downgrade in Credit Ratings. As of May 1, 2004, Moody's Investors Service, Inc. (Moody's), Standard & Poor's Ratings Services, a division of The McGraw Hill Companies (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to 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...   Ba2      Negative     BBB-      Negative    BBB-      Negative
CenterPoint Houston Senior Secured Debt
  (First Mortgage Bonds)...................   Baa2     Negative     BBB       Negative    BBB+      Negative
CERC Corp. Senior Debt.....................   Ba1      Stable       BBB       Negative    BBB       Negative



(1) A "negative" outlook from Moody's reflects concerns over the next 12 to 18 months which will either lead to a review for a potential downgrade or a return to a stable outlook. 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 "negative" outlook from Fitch encompasses a one-to-two year horizon as to the likely ratings direction.

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On February 27, 2004, Moody's announced that it was downgrading our senior unsecured debt to Ba2 from Ba1. Moody's explained in its announcement that the action was to reflect the structural differences in rights and claims afforded to our senior secured bank lenders, who benefit from their priority claim on proceeds from the monetization of Texas Genco and from the up-streaming of proceeds resulting from securitization of the true-up components at CenterPoint Houston. Moody's announced that its action concluded a review for possible downgrade of us that it initiated in October 2003.

On April 30, 2004, Moody's announced that it had changed the CERC outlook to stable from negative. Moody's explained in its announcement that the action was to reflect the mitigation of concerns that underlay its negative outlook including CERC 's establishment of a steady operating track record as a subsidiary of CenterPoint Energy, CERC's establishment of adequate stand-alone liquidity, CERC's progress made in addressing certain regulatory issues and greater comfort with the ringfencing protections provided to CERC by the 1935 Act.

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

A decline in credit ratings would increase borrowing costs under CERC's $250 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 and Pay Dividends on Our Common Stock" below. Additionally, a decline in credit ratings could increase cash collateral requirements that could exist in connection with certain contracts relating to gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution business segment.

Our revolving credit facilities contain "material adverse change" clauses that could impact our ability to make new borrowings under these facilities. The "material adverse change" clauses in our revolving credit facilities generally relate to an event, development or circumstance that has or would reasonably be expected to have a material adverse effect on (a) the business, financial condition or operations of the borrower and its subsidiaries taken as a whole, or (b) the legality, validity or enforceability of the loan documents.

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 noteholders 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 Gas Services, Inc. (CEGS), a wholly owned subsidiary of CERC Corp., provides comprehensive natural gas sales and services to industrial and commercial customers, which are primarily located within or near the territories served by our pipelines and natural gas distribution subsidiaries. In order to hedge its exposure to natural gas prices, CEGS has agreements with provisions standard for the industry that establish credit thresholds and require a party to provide additional collateral on two business days' notice when that party's rating or the rating of a credit support provider for that party (CERC Corp. in this case) falls below those levels. As of March 31, 2004, the senior unsecured debt of CERC Corp. was rated BBB by S&P and Ba1 by Moody's. We estimate that as of March 31, 2004, unsecured credit limits related to hedge instruments extended to CEGS by counterparties could aggregate $82 million; however, utilized credit capacity is significantly lower.

32

Cross Defaults. Under our revolving credit facility and our term loan, 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 April 30, 2004, 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.

Pension Plan. As discussed in Note 10(b) to the consolidated annual financial statements in the CenterPoint Energy Form 10-K (CenterPoint Energy Notes), which is incorporated herein by reference, 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, 2003, the projected benefit obligation exceeded the market value of plan assets by $498 million. In September 2003, we elected to make a $22.7 million contribution to our pension plan. As a result, we will not be required to make any contributions to our pension plan prior to 2005. Changes in interest rates and the market values of the securities held by the plan during 2004 could materially, positively or negatively, change our under-funded status and affect the level of pension expense and required contributions in 2005 and beyond. Plan assets used to satisfy pension obligations have been adversely impacted by the decline in equity market values prior to 2003.

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 (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 $23 million and $19 million for the three months ended March 31, 2003 and 2004, respectively. 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 Code mandated limits on these benefits or on the level of compensation on which these benefits may be calculated. The expense associated with this non-qualified plan was $2 million and $1 million for the three months ended March 31, 2003 and 2004, respectively.

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, 2003, the expected long-term rate of return on plan assets was 9.0%. 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, 2003, the projected benefit obligation was calculated assuming a discount rate of 6.25%, which is a 0.5% decline from the 6.75% discount rate assumed in 2002. 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 obligation specific to the characteristics of our plan.

Pension expense for 2004, including the benefit restoration plan, is estimated to be $82 million based on an expected return on plan assets of 9.0% and a discount rate of 6.25% as of December 31, 2003. If the expected return assumption were lowered by 0.5% (from 9.0% to 8.5%), 2004 pension expense would increase by approximately $6 million. Similarly, if the discount rate were lowered by 0.5% (from 6.25% to 5.75%), this assumption change would increase our projected benefit obligation, pension liabilities and 2004 pension expense by approximately $121 million, $111 million and $10 million, respectively. In addition, the assumption change would result in an additional charge to comprehensive income during 2004 of $72 million, net of tax.

33

Primarily due to the decline in the market value of the pension plan's assets and increased benefit obligations associated with a reduction in the discount rate, the value of the plan's assets is less than our accumulated benefit obligation. In December 2003, we recorded a minimum liability adjustment in the Consolidated Balance Sheet ($72 million decrease in pension liability) to reflect a liability equal to the unfunded accumulated benefit obligation, with an offsetting credit of $47 million to equity, net of a $25 million deferred tax effect.

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 the future.

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

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

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

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

- various regulatory actions; and

- the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and Texas Genco and in respect of RRI's indemnity obligations to us and our subsidiaries.

Money Pool. We have two "money pools" 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. Prior to October 2003, we had only one money pool. Following Texas Genco's certification by FERC as an "exempt wholesale generator" under the 1935 Act in October 2003, it could no longer participate with our regulated subsidiaries in the same money pool. In October 2003, we established a second money pool in which Texas Genco and certain of our other unregulated subsidiaries can participate.

The net funding requirements of the money pool in which our regulated subsidiaries participate are expected to be met with borrowings under credit facilities. Except in an emergency situation (in which case we could provide funding pursuant to applicable SEC rules), we would be required to obtain approval from the SEC to issue and sell securities for purposes of funding Texas Genco's operations via the money pool established in October 2003. The terms of both money pools 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 30, 2003 (June 2003 Financing Order).

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

- a $0.10 per share per quarter limitation on common stock dividend payments under our $2.3 billion revolving credit and term loan facility;

- covenants and other provisions in our credit or loan facilities and the credit facilities and receivables facility of our subsidiaries and other borrowing agreements; and

- limitations imposed on us as a registered public utility holding company under the 1935 Act.

The collateralized term loan 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

34

CERC's debt as a percentage of its total capitalization to 60% and contain an earnings before interest, taxes, depreciation and amortization (EBITDA) to interest covenant. Our $2.3 billion credit facility: limits dividend payments as described above; contains a debt to EBITDA covenant; contains an EBITDA to interest covenant; and provides that, until such time as the credit facility has been reduced to $750 million, all of the net cash proceeds from any securitizations relating to the recovery of the true-up components, after making any payments required under CenterPoint Houston's term loan, and the net cash proceeds of any sales of the common stock of Texas Genco that we own, or of material portions of Texas Genco's assets, shall be applied to repay borrowings under our credit facility and reduce the amount available under the credit facility. These facilities include certain restrictive covenants. We and our subsidiaries are in compliance with such covenants.

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 affiliate transactions.

The June 2003 Financing Order is effective until June 30, 2005. Additionally, we have received several subsequent orders which provide additional financing authority. These orders establish limits on the amount of external debt and equity securities that can be issued by us and our regulated subsidiaries without additional authorization but generally permit us to refinance our existing obligations and those of our 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 after giving effect to our capital markets transactions in 2003 and the first four months of 2004. The orders also permit utilization of undrawn credit facilities at CenterPoint Energy and CERC. As of April 30, 2004:

- CenterPoint Energy is authorized to issue an additional aggregate $250 million of preferred stock, preferred securities and equity-linked securities, $291 million of debt and 198 million shares of common stock;

- CenterPoint Houston is authorized to issue an additional aggregate $46 million of debt and an aggregate $250 million of preferred stock and preferred securities; and

- CERC is authorized to issue an additional $2 million of debt and an additional aggregate $250 million of preferred stock and preferred securities.

The SEC has reserved jurisdiction over, and must take further action to permit, the issuance of $478 million of additional debt at CenterPoint Energy, $430 million of additional debt at CERC and $250 million of additional debt at CenterPoint Houston.

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

The 1935 Act limits the payment of dividends to payment from current and retained earnings unless specific authorization is obtained to pay dividends from other sources. The SEC has reserved jurisdiction over payment of $500 million of dividends from CenterPoint Energy's unearned surplus or capital. Further authorization would be required to make those payments. As of March 31, 2004, we had a retained deficit on our Consolidated Balance Sheets. We expect to pay dividends out of current earnings. If as a result of the 2004 True-Up Proceeding or the monetization of our remaining interest in Texas Genco we are required to take a charge against our net income, our current earnings could be reduced below the level that would enable us to pay the quarterly dividend on our common stock under our current SEC financing order. We have filed an application with the SEC under the 1935 Act requesting an order authorizing us to pay dividends in the second and third quarters of 2004 out of capital or unearned surplus in the event that we are required to take such a charge against earnings. The June 2003 Financing Order requires that CenterPoint Houston and CERC maintain a ratio of common equity to total capitalization of thirty percent (30%).

35

Security Interests in Receivables of RRI. Pursuant to a Master Power Purchase and Sale Agreement with a subsidiary of RRI related to power sales in the Electric Reliability Council of Texas (ERCOT) market, Texas Genco has been granted a security interest in accounts receivable and/or notes associated with the accounts receivable of certain subsidiaries of RRI to secure up to $250 million in purchase obligations.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to the 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 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 $3.3 billion of recoverable electric generation-related regulatory assets as of March 31, 2004. These costs are recoverable under the provisions of the Texas electric restructuring law. The ultimate amount of cost recovery is subject to a final determination, which will occur in 2004, and is contingent upon the market value of Texas Genco. Any significant changes in the regulatory recovery mechanism currently in place could result in a material write-down of these regulatory assets.

IMPAIRMENT OF LONG-LIVED ASSETS AND INTANGIBLES

We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and annually for goodwill as required by SFAS No. 142, "Goodwill and Other Intangible Assets." No impairment of goodwill was indicated based on our analysis as of January 1, 2004. 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.

36

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.

We have engaged a financial advisor to assist in exploring alternatives for monetizing our 81% interest in Texas Genco, including possible sale of our ownership interest in Texas Genco. As a result of our intention to monetize our interest in Texas Genco, we performed an impairment analysis of Texas Genco's assets as of December 31, 2003 in accordance with the provisions of SFAS No.
144. As of December 31, 2003 no impairment had been indicated. The fair value of our Texas Genco assets could be materially affected by a change in the estimated future cash flows for these assets. We estimate future cash flows for Texas Genco using a probability-weighted approach based on the fair value of its common stock, operating projections and estimates of how long we will retain these assets. Changes in any of these assumptions, including the timing of a possible sale, could result in an impairment charge.

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 electric 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.

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 March 31, 2004 levels would have decreased the fair value of our Energy Derivatives from their levels on that date by $34 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), securities held in our nuclear decommissioning trusts, some lease obligations and our obligations under the ZENS that subject us to the risk of loss associated with movements in market interest rates.

37

Our floating-rate obligations to third parties aggregated $3 billion at March 31, 2004. If the floating rates were to increase by 10% from March 31, 2004 rates, our combined interest expense to third parties would increase by a total of $2 million each month in which such increase continued.

At March 31, 2004, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $8 billion in principal amount and having a fair value of $8 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 $405 million if interest rates were to decline by 10% from their levels at March 31, 2004. 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 12(e) to the CenterPoint Energy Notes, which note is incorporated herein by reference, CenterPoint Houston contributes $2.9 million per year to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project. The securities held by the trusts for decommissioning costs had an estimated fair value of $201 million as of March 31, 2004, of which approximately 36% were debt securities that subject us to risk of loss of fair value with movements in market interest rates. If interest rates were to increase by 10% from their levels at March 31, 2004, the fair value of the fixed-rate debt securities would decrease by approximately $1 million. Any unrealized gains or losses are accounted for as a long-term asset/liability as we will not benefit from any gains, and losses will be recovered through the rate making process. For further discussion regarding the recovery of decommissioning costs pursuant to the Texas electric restructuring law, please read Note 4(a) to the CenterPoint Energy Notes, which is incorporated herein by reference.

As discussed in Note 7 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 $106 million at March 31, 2004 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 $16 million if interest rates were to decline by 10% from levels at March 31, 2004. 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 March 31, 2004 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.

EQUITY MARKET VALUE RISK

We are exposed to equity market value risk through our ownership of 21.6 million shares of TW common stock, which we hold to facilitate our ability to meet our obligations under the ZENS. Please read Note 7 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 March 31, 2004 market value of Time Warner common stock would result in a net loss of approximately $3 million, which would be recorded as a loss in our Statements of Consolidated Income.

As discussed above under " -- Interest Rate Risk," CenterPoint Houston contributes to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project, which held debt (36%) and equity (64%) securities as of March 31, 2004. The equity securities expose us to losses in fair value. If the market prices of the individual equity securities were to decrease by 10% from their levels at March 31, 2004, the resulting loss in fair value of these securities would be approximately $13 million. Currently, the risk of an economic loss is mitigated as discussed above under " -- Interest Rate Risk."

38

 
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 March 31, 2004 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 March 31, 2004 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

39

 
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 10-K, "Legal Proceedings" in Item 3 of the CenterPoint Energy Form 10-K and Notes 4 and 12 to the CenterPoint Energy Notes, each of which is incorporated herein by reference.

 
ITEM 2. CHANGES IN SECURITIES, USE OF PROCEEDS AND ISSUER REPURCHASES OF EQUITY  
SECURITIES

The following table provides information about purchases by or on behalf of CenterPoint Energy and its affiliated purchasers during the quarter ended March 31, 2004 of its common stock. These purchases are related to CenterPoint Energy's discretionary matching contributions under the CenterPoint Energy, Inc. Savings Plan.


                 (a)           (b)             (c)               (d)
                                           TOTAL NUMBER        MAXIMUM
                                          OF SHARES (OR      NUMBER (OR
                                              UNITS)         APPROXIMATE
                                           PURCHASED AS   DOLLAR VALUE) OF
                TOTAL                        PART OF      SHARES (OR UNITS)
              NUMBER OF   AVERAGE PRICE      PUBLICLY      THAT MAY YET BE
             SHARES (OR     PAID PER        ANNOUNCED         PURCHASED
               UNITS)       SHARE (OR        PLANS OR      UNDER THE PLANS
  PERIOD      PURCHASED       UNIT)          PROGRAMS        OR PROGRAMS
----------   ----------   -------------   -------------   ----------------
01/01/04 -
 01/31/04        --            --               --                --
02/01/04 -
 02/29/04        --            --               --                --
03/01/04 -
 03/31/04     850,877(1)    $11.0613            --                --


(1) The shares indicated were purchased by the trustee of the Savings Plan in open-market transactions and are included because they were purchased to fund benefits to employees established by CenterPoint Energy on a discretionary basis. An additional 576,317 shares for the discretionary matching contributions were allocated to plan participants as a result of the repayment of a loan to a related leveraged Employee Stock Ownership Plan using cash contributions from CenterPoint Energy at an average price per share of $10.3751. Shares purchased to fund acquisitions from employee contributions and non-discretionary matching contributions have been regarded as purchased on behalf of plan participants and are not included in the table.

40

 
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(a) Exhibits.

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing 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 of        CenterPoint Energy's Registration Statement      3-69502        3.1
            Incorporation of CenterPoint Energy     on Form S-4

3.1.2    -- Articles of Amendment to Amended and
            Restated Articles of Incorporation of   CenterPoint Energy's Form 10-K for the year      1-31447      3.1.1
            CenterPoint Energy                      ended December 31, 2001

3.2      -- Amended and Restated Bylaws of          CenterPoint Energy's Form 10-K for the year      1-31447        3.2
            CenterPoint Energy                      ended December 31, 2001

3.3      -- Statement of Resolution Establishing
            Series of Shares designated Series A    CenterPoint Energy's Form 10-K for the year      1-31447        3.3
            Preferred Stock of CenterPoint Energy   ended December 31, 2001

4.1      -- Form of CenterPoint Energy Stock        CenterPoint Energy's Registration Statement      3-69502        4.1
            Certificate                             on Form S-4

4.2      -- Rights Agreement dated January 1,
            2002, between CenterPoint Energy and    CenterPoint Energy's Form 10-K for the year      1-31447        4.2
            JPMorgan Chase Bank, as Rights Agent    ended December 31, 2001

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
------                   -----------                       --------------------------------           ------      ---------
10.1.1   -- $1,310,000,000 Credit Agreement dated     CenterPoint Energy's Form 10-K for the year
            as of November 12, 2002, among            ended December 31, 2002                          1-31447     4(g)(1)
            CenterPoint Houston and the banks named
            therein

10.1.2   -- First Amendment to Exhibit 10.1.1,        CenterPoint Energy's Form 10-Q for the           1-31447      10.7
            dated as of September 3, 2003             quarter ended September 30, 2003

41

 
                                                                                                       SEC FILE
                                                                                                          OR
EXHIBIT                                                                                              REGISTRATION    EXHIBIT
NUMBER                   DESCRIPTION                       REPORT OR REGISTRATION STATEMENT             NUMBER      REFERENCE
------                   -----------                       --------------------------------             ------      ---------
10.1.3   -- Pledge Agreement, dated as of November
            12, 2002 executed in connection with      CenterPoint Energy's Form 10-K for the year
            Exhibit 10.1.1                            ended December 31, 2002                           1-31447      4(g)(2)

10.2     -- $250,000,000 Credit Agreement, dated as
            of March 23, 2004, among CERC Corp., as   CenterPoint Energy's Form 8-K dated March 31,
            Borrower, and the Initial Lenders named   2004                                              1-31447        4.1
            therein, as Initial Lenders

10.3.1   -- Credit Agreement, dated as of October
            7, 2003 among CenterPoint Energy and      CenterPoint Energy's Form 10-Q for the            1-31447       10.8
            the banks named therein                   quarter ended September 30, 2003

10.3.2   -- Pledge Agreement, dated as of October
            7, 2003, executed in connection with      CenterPoint Energy's Form 10-Q for the            1-31447       10.9
            Exhibit 10.3.1                            quarter ended September 30, 2003

10.4.1   -- $75,000,000 revolving credit facility
            dated as of December 23, 2003 among       CenterPoint Energy's Form 10-K for the year
            Texas Genco, LP and the banks named       ended December 31, 2003                           1-31447     10(pp)(1)
            therein

+31.1    -- Rule 13a-14(a)/15d-14(a) Certification
            of David M. McClanahan

+31.2    -- Rule 13a-14(a)/15d-14(a) Certification
            of Gary L. Whitlock

+32.1    -- Section 1350 Certification of David M.
            McClanahan

+32.2    -- Section 1350 Certification of Gary L.
            Whitlock

+99.1    -- Items incorporated by reference from
            the CenterPoint Energy Form 10-K. Item
            1 "Business -- Regulation," " --
            Environmental Matters," " -- Risk
            Factors," Item 3 "Legal Proceedings,"
            Item 7 "Management's Discussion and
            Analysis of Financial Condition and
            Results of Operations -- Certain
            Factors Affecting Future Earnings" and
            Notes 2(d) (Long-Lived Assets and
            Intangibles), 2(e) (Regulatory Assets
            and Liabilities), 4 (Regulatory
            Matters), 5 (Derivative Instruments), 7
            (Indexed Debt Securities (ZENS) and
            Time Warner Securities), 10(b) (Pension
            and Postretirement Benefits) and 12
            (Commitments and Contingencies)

(b) Reports on Form 8-K.

On January 29, 2004, we filed a Current Report on Form 8-K dated January 23, 2004 to report that Reliant Energy, Inc. (formerly named Reliant Resources, Inc. (RRI)) notified us it would not exercise its option to purchase our 81% interest in Texas Genco.

42

On February 12, 2004, we filed a Current Report on Form 8-K dated February 12, 2004, in which we reported certain fourth quarter and full year 2003 earnings information and furnished a press release under Item 12 of that form.

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

On March 10, 2004, we filed a Current Report on Form 8-K dated March 4, 2004 to report the administrative law judge's recommendation regarding CenterPoint Houston's final fuel reconciliation proceeding and its effect on our previously reported 2003 earnings.

On April 1, 2004, we filed a Current Report on Form 8-K dated March 31, 2004 to report that CERC Corp. had entered into a new three-year, $250 million credit agreement with a group of lenders.

On April 1, 2004, we filed a Current Report on Form 8-K dated April 1, 2004 to report that CenterPoint Houston, Texas Genco LP and Reliant Energy Retail Services LLC filed the final true-up application required by the 1999 Texas Electric Choice Law with the Texas Utility Commission. A slide showing the components of the true-up balance for CenterPoint Energy was furnished under Item 9 of that form.

On April 1, 2004, we filed a Current Report on Form 8-K dated April 1, 2004 to furnish under Item 9 of that form a slide presentation we expect will be presented to various members of the financial and investment community from time to time.

On April 22, 2004, we filed a Current Report on Form 8-K dated April 22, 2004, in which we reported certain first quarter 2004 earnings information and furnished a press release under Item 12 of that form.

43

 
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: May 7, 2004

44

 
INDEX TO EXHIBITS

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 of        CenterPoint Energy's Registration Statement      3-69502        3.1
            Incorporation of CenterPoint Energy     on Form S-4

3.1.2    -- Articles of Amendment to Amended and
            Restated Articles of Incorporation of   CenterPoint Energy's Form 10-K for the year      1-31447      3.1.1
            CenterPoint Energy                      ended December 31, 2001

3.2      -- Amended and Restated Bylaws of          CenterPoint Energy's Form 10-K for the year      1-31447        3.2
            CenterPoint Energy                      ended December 31, 2001

3.3      -- Statement of Resolution Establishing
            Series of Shares designated Series A    CenterPoint Energy's Form 10-K for the year      1-31447        3.3
            Preferred Stock of CenterPoint Energy   ended December 31, 2001

4.1      -- Form of CenterPoint Energy Stock        CenterPoint Energy's Registration Statement      3-69502        4.1
            Certificate                             on Form S-4

4.2      -- Rights Agreement dated January 1,
            2002, between CenterPoint Energy and    CenterPoint Energy's Form 10-K for the year      1-31447        4.2
            JPMorgan Chase Bank, as Rights Agent    ended December 31, 2001

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
------                   -----------                       --------------------------------           ------      ---------
10.1.1   -- $1,310,000,000 Credit Agreement dated     CenterPoint Energy's Form 10-K for the year
            as of November 12, 2002, among            ended December 31, 2002                          1-31447     4(g)(1)
            CenterPoint Houston and the banks named
            therein

10.1.2   -- First Amendment to Exhibit 10.1.1,        CenterPoint Energy's Form 10-Q for the           1-31447      10.7
            dated as of September 3, 2003             quarter ended September 30, 2003


 
                                                                                                       SEC FILE
                                                                                                          OR
EXHIBIT                                                                                              REGISTRATION    EXHIBIT
NUMBER                   DESCRIPTION                       REPORT OR REGISTRATION STATEMENT             NUMBER      REFERENCE
------                   -----------                       --------------------------------             ------      ---------
10.1.3   -- Pledge Agreement, dated as of November
            12, 2002 executed in connection with      CenterPoint Energy's Form 10-K for the year
            Exhibit 10.1.1                            ended December 31, 2002                           1-31447      4(g)(2)

10.2     -- $250,000,000 Credit Agreement, dated as
            of March 23, 2004, among CERC Corp., as   CenterPoint Energy's Form 8-K dated March 31,
            Borrower, and the Initial Lenders named   2004                                              1-31447         4.1
            therein, as Initial Lenders

10.3.1   -- Credit Agreement, dated as of October
            7, 2003 among CenterPoint Energy and      CenterPoint Energy's Form 10-Q for the            1-31447        10.8
            the banks named therein                   quarter ended September 30, 2003

10.3.2   -- Pledge Agreement, dated as of October
            7, 2003, executed in connection with      CenterPoint Energy's Form 10-Q for the            1-31447        10.9
            Exhibit 10.3.1                            quarter ended September 30, 2003

10.4.1   -- $75,000,000 revolving credit facility
            dated as of December 23, 2003 among       CenterPoint Energy's Form 10-K for the year
            Texas Genco, LP and the banks named       ended December 31, 2003                           1-31447     10(pp)(1)
            therein

+31.1    -- Rule 13a-14(a)/15d-14(a) Certification
            of David M. McClanahan

+31.2    -- Rule 13a-14(a)/15d-14(a) Certification
            of Gary L. Whitlock

+32.1    -- Section 1350 Certification of David M.
            McClanahan

+32.2    -- Section 1350 Certification of Gary L.
            Whitlock

+99.1    -- Items incorporated by reference from
            the CenterPoint Energy Form 10-K. Item
            1 "Business -- Regulation," " --
            Environmental Matters," " -- Risk
            Factors," Item 3 "Legal Proceedings,"
            Item 7 "Management's Discussion and
            Analysis of Financial Condition and
            Results of Operations -- Certain
            Factors Affecting Future Earnings" and
            Notes 2(d) (Long-Lived Assets and
            Intangibles), 2(e) (Regulatory Assets
            and Liabilities), 4 (Regulatory
            Matters), 5 (Derivative Instruments), 7
            (Indexed Debt Securities (ZENS) and
            Time Warner Securities), 10(b) (Pension
            and Postretirement Benefits) and 12
            (Commitments and Contingencies)


 
 
EXHIBIT 31.1

CERTIFICATION

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 officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers 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: May 7, 2004


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



 
 
EXHIBIT 31.2

CERTIFICATION

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 officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b) Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(c) Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officers 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: May 7, 2004


By:         /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 March 31, 2004 (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
May 7, 2004



 
 
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 March 31, 2004 (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
May 7, 2004



 
 
EXHIBIT 99.1

ITEM 1. BUSINESS

REGULATION

We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.

PUBLIC UTILITY HOLDING COMPANY ACT OF 1935

As a registered public utility holding company, we, along with our subsidiaries except Texas Genco, 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 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, 2003, 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, 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 require that CenterPoint Houston and CERC maintain a ratio of common equity to total capitalization of at least 30%. The SEC has acknowledged that prior to the monetization of Texas Genco and the securitization of the true-up components, our common equity as a percentage of total capitalization is expected to remain less than 30%. In addition, after the securitization, our common equity as a percentage of total capitalization, including securitized debt, is expected to be less than 30%, which the SEC has permitted for other companies.

In October 2003, the FERC granted exempt wholesale generator status to Texas Genco, LP, a wholly owned subsidiary of Texas Genco that owns and operates our electric generating plants. As a result of the FERC's actions, Texas Genco, LP is exempt from all provisions of the 1935 Act as long as it remains an exempt wholesale generator and Texas Genco is no longer a public utility holding company within the meaning of the 1935 Act.

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.

FEDERAL ENERGY REGULATORY COMMISSION

The transportation and sale or resale of natural gas in interstate commerce is subject to regulation by the FERC under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended. The FERC has jurisdiction over, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC.

Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of

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return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates.

On November 25, 2003, the FERC issued Order No. 2004, the final rule modifying the Standards of Conduct applicable to electric and natural gas transmission providers, governing the relationship between regulated transmission providers and certain of their affiliates. The rule significantly changes and expands the regulatory burdens of the Standards of Conduct and applies essentially the same standards to jurisdictional electric transmission providers and natural gas pipelines. On February 9, 2004, our natural gas pipeline subsidiaries filed Implementation Plans required under the new rule. Those subsidiaries are further required to post their Implementation Procedures on their websites by June 1, 2004, and to be in compliance with the requirements of the new rule by that date.

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. Texas Genco makes electric sales wholly within ERCOT and, as a result, its rates are not subject to regulation as a "public utility" under the Federal Power Act.

STATE AND LOCAL REGULATION

Electric Transmission and 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 forty 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 current 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 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 August 2002, a settlement was approved by the APSC that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $27 million annually. In addition, the APSC approved a gas

2

main replacement surcharge that provided $2 million of additional revenue in 2003 and is expected to provide additional amounts in subsequent years. In December 2002, a settlement was approved by the Oklahoma Corporation Commission that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $6 million annually. In November 2003, Arkla filed a request with the Louisiana Public Service Commission (LPSC) for a $16 million increase to its base rate and service charge revenues in Louisiana. The case is expected to be resolved in mid-2004.

In December 2003, a settlement was approved by the City of Houston that will result in an increase in the base rate and service charge revenues of Entex of approximately $7 million annually. Entex has submitted these settlement rates to the 28 other cities within its Houston Division and the Railroad Commission of Texas for consideration and approval. If all regulatory approvals are received from these 29 jurisdictions, Entex's base rate and service charge revenues are expected to increase by approximately $7 million annually in addition to the $7 million discussed above. On February 10, 2004, a settlement was approved by the LPSC that is expected to result in an increase in Entex's base rate and service charge revenues of approximately $2 million annually.

Our gas distribution divisions generally recover the cost of gas provided to customers through gas cost adjustment mechanisms prescribed in their tariffs that are approved by the appropriate regulatory authority. Recently, our Arkla and Entex divisions have been involved in both litigation and regulatory proceedings in which parties have challenged the gas costs that have been recovered from customers. In response to a claim by the City of Tyler, Texas that excessive costs, ranging from $2.8 million to $39.2 million, may have been incurred for gas purchased by Entex for resale to residential and small commercial customers, Entex and the City of Tyler have requested that the Railroad Commission determine whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. Similarly, a complaint has been filed with the LPSC by a private party alleging that certain gas costs recovered from Entex customers in Louisiana were excessive and/or were not properly authorized by the LPSC. Additionally, certain private litigants have filed suit in Louisiana state courts, alleging that inappropriate or excessive gas costs have been recovered from Arkla's customers.

NUCLEAR REGULATORY COMMISSION

Texas Genco is subject to regulation by the United States Nuclear Regulatory Commission (NRC) with respect to the operation of the South Texas Project. 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 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.

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DEPARTMENT OF TRANSPORTATION

In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (the Act). This legislation applies to our interstate pipelines as well as our intrastate pipelines and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities, in accordance with the requirements of the legislation over a 10-year period.

In December 2003, the Department of Transportation Office of Pipeline Safety issued the final regulations to implement the Act. These regulations became effective on February 14, 2004. These regulations provided guidance on, among other things, the areas that should be classified as HCA.

Our Pipelines and Gathering business segment and our natural gas distribution companies anticipate that compliance with the new regulations will require increases in both capital and operating cost. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we anticipate compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period.

ENVIRONMENTAL MATTERS

We are subject to a number of federal, state and local laws and regulations relating to the protection of the environment and the safety and health of company personnel and the public. These requirements relate to a broad range of our activities, including:

- the discharge of pollutants into the air, water and soil;

- the identification, generation, storage, handling, transportation, disposal, record keeping, labeling and reporting of, and the emergency response in connection with, hazardous and toxic materials and wastes, including asbestos, associated with our operations;

- noise emissions from our facilities; and

- safety and health standards, practices and procedures that apply to the workplace and the operation of our facilities.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

- construct or acquire new equipment;

- acquire permits and/or marketable allowance or other emission credits 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, including generation facilities.

If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose upon us civil fines or liabilities for property damage, personal injury and possibly other costs.

Under the federal Comprehensive Environmental Response, Compensation and Liability Act of 1980 (CERCLA), owners and operators of facilities from which there has been a release or threatened release of

4

hazardous substances, together with those who have transported or arranged for the disposal of those substances, are liable for:

- the costs of responding to that release or threatened release; and

- the restoration of natural resources damaged by any such release.

AIR EMISSIONS

As part of the 1990 amendments to the Federal Clean Air Act, requirements and schedules for compliance were developed for attainment of health-based standards. In furtherance of the Act's requirements, standards for NOx emissions, a product of the combustion process associated with power generation, have been finalized by the Texas Commission on Environmental Quality (TCEQ). These TCEQ standards, as well as provisions of the Texas electric restructuring law, require substantial reductions in NOx emissions from electric generating units. Texas Genco is currently installing cost-effective controls at its generating plants to comply with these requirements. As of December 31, 2003, Texas Genco has invested $664 million for NOx emissions controls and is planning to make expenditures of $131 million for the remainder of 2004 through 2007. Further revisions to these NOx standards may result from the TCEQ's future rules, expected by 2007, implementing more stringent federal eight-hour ozone standards.

In 1998, the United States became a signatory to the United Nations Framework Convention on Climate Change (Kyoto Protocol). The Kyoto Protocol calls for developed nations to reduce their emissions of greenhouse gases. Carbon dioxide, which is a major byproduct of the combustion of fossil fuel, is considered to be a greenhouse gas. In 2002, President Bush withdrew the United States' support for the Kyoto Protocol while endorsing voluntary greenhouse gas reduction measures. Congress has also explored a number of other alternatives for regulating domestic greenhouse gas emissions. If the country re-enters and the United States Senate ultimately ratifies the Kyoto Protocol and/or if the United States Congress adopts other measures for the control of greenhouse gases, any resulting limitations on power plant carbon dioxide emissions could have a material adverse impact on all fossil fuel-fired electric generating facilities, including those belonging to Texas Genco.

In July 2002, the White House sent to the United States Congress a Bill proposing the Clear Skies Act, which is designed to achieve long-term reductions of multiple pollutants produced from fossil fuel-fired power plants. If enacted, the Clear Skies Act would target reductions averaging 70% for sulfur dioxide (SO(2)), NOx and mercury emissions and would create a gradually imposed market-based compliance program that would come into effect initially in 2008 with full compliance required by 2018. Fossil fuel-fired power plants owned by companies such as Texas Genco would be affected by the adoption of this program, or other legislation currently pending in Congress addressing similar issues. To comply with such programs, we and other regulated entities could pursue a variety of strategies, including the installation of pollution controls, purchase of emission allowances, or the curtailment of operations. To date, Congress has taken little action to enact the Clear Skies Act.

In response to Congressional inaction on the proposed Clear Skies Act, the Environmental Protection Agency (EPA) in December 2003 proposed the Interstate Air Quality Rule, which would require reductions in NOx and SO(2) similar to those found in the Clear Skies Act. However, in contrast to the Clear Skies Act, the Interstate Air Quality Rule affects emissions in 29 states in the eastern U.S., including Texas. As with the Clear Skies Act, emissions are reduced in two phases, and the reduction targets are similar, but are effective in 2010 and 2015 for both NOx and SO(2). EPA has announced an intent to finalize these rules in late 2004 or early 2005.

In December 2003, EPA proposed two alternatives for regulating emissions of mercury from coal-fired power plants in the U.S. A final rulemaking is scheduled to be adopted in December 2004. Under the first option, the EPA would set Maximum Achievable Control Technology (MACT) standards under Section 112 of the Clean Air Act, which would require mercury reductions on a facility-by-facility basis regardless of cost. The MACT standard requires reductions to be achieved by 2008, although it is possible that this compliance date will be delayed. The second option would regulate coal-fired power plants under Section 111 of the Clean

5

Air Act. Under this option, similar mercury reductions would be achieved on a national scale through a cap-and-trade program, allowing reductions to be made at the most economical locations, and not requiring reductions on a facility-by-facility basis. The MACT standard would require a reduction of about 30% from coal-fired facilities, which will require the installation of control equipment. The cap-and-trade rule would require deeper reductions, but may be more economical because it allows trading of emissions among facilities. The mercury cap-and-trade rule would be accomplished in two phases, in 2010 and 2015, with reduction levels set at approximately 50% and 70%, respectively. The cost of complying with the final rules is not yet known but is likely to be material.

In addition to mercury control from coal-fired boilers, the MACT rule, if adopted, would require the control of nickel emissions from oil-fired facilities. At this point, the impact of this proposal is uncertain, but is not expected to significantly affect our operations.

The EPA has also issued MACT standards for sources other than boilers used for power generation. The MACT rule for combustion turbines was issued in August 2003 and there is no impact on our existing facilities. The MACT rulemaking for engines and industrial boilers was issued in February 2004. These rules are not expected to have a significant impact on Texas Genco's operations.

WATER

On February 16, 2004, the EPA signed final rules under Section 316(b) of the Clean Water Act relating to the design and operation of existing cooling water intake structures. The requirements to achieve compliance with this rule are subject to various factors, including the results of anticipated litigation, but we currently do not expect any capital expenditures required for compliance to be material.

The EPA and State of Texas periodically modify water quality standards and, where necessary, initiate total maximum daily load allocations for water-bodies not meeting those standards. Such actions could cause our facilities to incur significant costs to comply with revised discharge permit limitations.

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 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). On January 28, 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.

LIABILITY FOR PREEXISTING CONDITIONS AND REMEDIATION

Asbestos and Other. As a result of their age, many of our facilities contain significant amounts of asbestos insulation, other asbestos-containing materials and lead-based paint. Existing state and federal rules require the proper management and disposal of these potentially toxic materials. We have developed a management plan that includes proper maintenance of existing non-friable asbestos installations, and removal and abatement of asbestos containing materials where necessary because of maintenance, repairs, replacement or damage to the asbestos itself. We have planned for the proper management, abatement and disposal of asbestos and lead-based paint at our facilities.

We have been named, along with numerous others, as a defendant in a number of lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been third party workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by us.

6

We anticipate that additional claims like those received may be asserted in the future, and we intend to continue our practice of vigorously contesting claims that we do not consider to have merit.

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among some of the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. The Company is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters.

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory, two of which CERC believes were neither owned nor operated by CERC, and for which CERC believes it has no liability.

At December 31, 2003, CERC had accrued $19 million for remediation of certain Minnesota sites. At December 31, 2003, the estimated range of possible remediation costs for these sites was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. CERC has collected or accrued $12.5 million as of December 31, 2003 to be used for environmental remediation.

CERC has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for other 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. Based on current information, we have not been able to quantify a range of environmental expenditures for such sites.

Mercury Contamination. Our pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by us at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows.

Other Environmental. From time to time, we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. Although their ultimate outcome cannot be predicted at this time, we do not

7

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.

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 12 to our consolidated financial statements, which information is incorporated herein by reference.

In addition to the matters incorporated herein by reference, the following matters that we previously reported have been resolved:

In August and October 2003, class action lawsuits were filed against CenterPoint Houston and Reliant Energy Services in federal court in New York on behalf of purchasers of natural gas futures contracts on the New York Mercantile Exchange. A third, similar class action was filed in the same court in November 2003. The complaints alleged that the defendants manipulated the price of natural gas through their gas trading activities and price reporting practices in violation of the Commodity Exchange Act during the period January 1, 2000 through December 31, 2002. The plaintiffs sought damages based on the effect of such alleged manipulation on the value of the gas futures contracts they bought or sold. In January 2004, the plaintiffs voluntarily dismissed CenterPoint Houston from these lawsuits.

During 2003, we and Texas Genco were engaged in a dispute with Northwestern Resources Co. (NWR), the supplier of fuel to the Limestone electric generation facility, over the terms and pricing at which NWR supplies fuel to that facility under a 1999 settlement agreement between the parties and under ancillary obligations. Both sides to the dispute initiated lawsuits, but in January 2004, NWR and Texas Genco reached a settlement under which they agreed to dismiss those lawsuits and under which NWR would continue to provide certain quantities of lignite at specified prices during the period from 2004 through 2007, after which time the pricing would revert to pricing provided for under the 1999 settlement.

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RISK FACTORS

PRINCIPAL RISK FACTORS ASSOCIATED WITH OUR BUSINESSES

RISK FACTORS AFFECTING OUR ELECTRIC TRANSMISSION & DISTRIBUTION BUSINESS

CENTERPOINT HOUSTON MAY NOT BE SUCCESSFUL IN RECOVERING THE FULL VALUE OF ITS
TRUE-UP COMPONENTS.

CenterPoint Houston expects to make a filing on March 31, 2004 in a true-up proceeding provided for by the Texas electric restructuring law. The purpose of this proceeding will be to quantify and reconcile the following costs or true-up components:

- "stranded costs," which consist of the positive excess of the regulatory net book value of generation assets, as defined, over the market value of the assets;

- the difference between the Texas Utility Commission's projected market prices for generation during 2002 and 2003 and the actual market prices for generation as determined in the state-mandated capacity auctions during that period;

- the Texas jurisdictional amount reported by the previously vertically integrated electric utilities as generation-related regulatory assets and liabilities (offset and adjusted by specified amounts) in their audited financial statements for 1998;

- final fuel over- or under-recovery; less

- "price to beat" clawback components.

CenterPoint Houston will be required to establish and support the amounts it seeks to recover in the 2004 True-Up Proceeding. CenterPoint Houston expects these amounts to be substantial. Third parties will have the opportunity and are expected to challenge CenterPoint Houston's calculation of these amounts. To the extent recovery of a portion of these amounts is denied or if we agree to forego recovery of a portion of the request under a settlement agreement, CenterPoint Houston would be unable to recover those amounts in the future. Additionally, in October 2003, a group of intervenors filed a petition asking the Texas Utility Commission to open a rulemaking proceeding and reconsider certain aspects of its true-up rules. In November 2003, the Texas Utility Commission voted to deny the petition. Despite the denial of the petition, we expect that issues could be raised in the 2004 True-Up Proceeding regarding our compliance with the Texas Utility Commission's rules regarding ECOM recovery, including whether Texas Genco has auctioned all capacity it is required to auction in view of the fact that some capacity has failed to sell in the state-mandated auctions. We believe Texas Genco has complied with the requirements under the applicable rules, including re-offering the unsold capacity in subsequent auctions. If events were to occur during the 2004 True-Up Proceeding that made the recovery of the ECOM true-up regulatory asset no longer probable, we would write off the unrecoverable balance of such asset as a charge against earnings.

In the event CenterPoint Houston has not begun to recover the amounts established in the 2004 True-Up Proceeding prior to its $1.3 billion term loan maturity date in November 2005, CenterPoint Houston's ability to repay or refinance this term loan may be adversely affected.

The Texas Utility Commission's ruling that the 2004 True-Up Proceeding filing will be made on March 31, 2004 means that the calculation of the market value of a share of Texas Genco common stock for purposes of the Texas Utility Commission's stranded cost determination will be based on market prices during the 120 trading days ending on March 30, 2004 plus a control premium, if any, up to a maximum of 10%. If Texas Genco is sold to a third party at a lower price than the market value used by the Texas Utility Commission, CenterPoint Houston would be unable to recover the difference.

CENTERPOINT HOUSTON'S RECEIVABLES ARE CONCENTRATED IN A SMALL NUMBER OF RETAIL
ELECTRIC PROVIDERS.

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 43 retail electric providers. Adverse economic

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conditions, structural problems in the new ERCOT market 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. Reliant Resources, through its subsidiaries, is CenterPoint Houston's largest customer. Approximately 70% of CenterPoint Houston's $83 million in billed receivables from retail electric providers at December 31, 2003 was owed by subsidiaries of Reliant Resources. Pursuant to the Texas electric restructuring law, Reliant Resources will be obligated to make a "price to beat" clawback payment to CenterPoint Houston in 2004 which is currently estimated by Reliant Resources to be $175 million. CenterPoint Houston's financial condition may be adversely affected if Reliant Resources is unable to meet these obligations.

RATE REGULATION OF CENTERPOINT HOUSTON'S BUSINESS MAY DELAY OR DENY
CENTERPOINT HOUSTON'S FULL RECOVERY OF 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 incurred in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. While rate regulation in Texas is premised on providing a reasonable opportunity to recover reasonable and necessary operating expenses and to earn a reasonable return on its invested capital, there can be no assurance that the Texas Utility Commission will judge all of CenterPoint Houston's costs to be reasonable or necessary or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of CenterPoint Houston's costs.

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 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 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 ELECTRIC GENERATION BUSINESS

TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE IMPACTED BY MARKET RISKS
THAT ARE BEYOND ITS CONTROL.

Texas Genco sells electric generation capacity, energy and ancillary services in the ERCOT market. The ERCOT market consists of the majority of the population centers in Texas and represents approximately 85% of the demand for power in the state. Under the Texas electric restructuring law, Texas Genco and other power generators in Texas are not subject to traditional cost-based regulation and, therefore, may sell electric generation capacity, energy and ancillary services to wholesale purchasers at prices determined by the market. As a result, Texas Genco is not guaranteed any rate of return on its capital investments through mandated rates, and its revenues and results of operations depend, in large part, upon prevailing market prices for electricity in the ERCOT market. Market prices for electricity, generation capacity, energy and ancillary services may fluctuate substantially. Texas Genco's gross margins are primarily derived from the sale of capacity entitlements associated with its large, solid fuel base-load generating units, including its coal and

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lignite fueled generating stations and its interest in the South Texas Project nuclear generating station. The gross margins generated from payments associated with the capacity of these units are directly impacted by natural gas prices. Since the fuel costs for Texas Genco's base-load units are largely fixed under long-term contracts, they are generally not subject to significant daily and monthly fluctuations. However, the market price for power in the ERCOT market is directly affected by the price of natural gas. Because natural gas is the marginal fuel for facilities serving the ERCOT market during most hours, its price has a significant influence on the price of electric power. As a result, the price customers are willing to pay for entitlements to Texas Genco's solid fuel-fired base-load capacity generally rises and falls with natural gas prices.

Market prices in the ERCOT market may also fluctuate substantially due to other factors. Such fluctuations may occur over relatively short periods of time. Volatility in market prices may result from:

- oversupply or undersupply of generation capacity,

- power transmission or fuel transportation constraints or inefficiencies,

- weather conditions,

- seasonality,

- availability and market prices for natural gas, crude oil and refined products, coal, enriched uranium and uranium fuels,

- changes in electricity usage,

- additional supplies of electricity from existing competitors or new market entrants as a result of the development of new generation facilities or additional transmission capacity,

- illiquidity in the ERCOT market,

- availability of competitively priced alternative energy sources,

- natural disasters, wars, embargoes, terrorist attacks and other catastrophic events, and

- federal and state energy and environmental regulation and legislation.

THERE IS CURRENTLY A SURPLUS OF GENERATING CAPACITY IN THE ERCOT MARKET AND WE
EXPECT THE MARKET FOR WHOLESALE POWER TO BE HIGHLY COMPETITIVE.

The amount by which power generating capacity exceeds peak demand (reserve margin) in the ERCOT market has exceeded 30% since 2001, and the Texas Utility Commission and the ERCOT Independent System Operator (ISO) have forecasted the reserve margin for 2004 to continue to exceed 30%. The commencement of commercial operation of new power generation facilities in the ERCOT market has increased and will continue to increase the competitiveness of the wholesale power market, which could have a material adverse effect on Texas Genco's results of operations, financial condition, cash flows and the market value of Texas Genco's assets.

Texas Genco's competitors include generation companies affiliated with Texas-based utilities, independent power producers, municipal and co-operative generators and wholesale power marketers. The unbundling of vertically integrated utilities into separate generation, transmission and distribution, and retail businesses pursuant to the Texas electric restructuring law could result in a significant number of additional competitors participating in the ERCOT market. Some of Texas Genco's competitors may have greater financial resources, lower cost structures, more effective risk management policies and procedures, greater ability to incur losses, greater potential for profitability from ancillary services, and greater flexibility in the timing of their sale of generating capacity and ancillary services than Texas Genco does.

TEXAS GENCO IS SUBJECT TO OPERATIONAL AND MARKET RISKS ASSOCIATED WITH ITS
CAPACITY AUCTIONS.

Texas Genco has sold entitlements to a significant portion of its available 2004 and 2005 generating capacity in its capacity auctions held to date. Although Texas Genco's obligation to conduct contractually-

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mandated auctions terminated in January 2004, it currently remains obligated to sell 15% of its installed generation capacity and related ancillary services pursuant to state-mandated auctions and it expects to conduct future capacity auctions with respect to all or part of its remaining capacity from time to time. In these auctions, Texas Genco sold firm entitlements on a forward basis to capacity and ancillary services dispatched within specified operational constraints. Although Texas Genco has reserved a portion of its aggregate net generation capacity from its capacity auctions for planned or forced outages at its facilities, unanticipated plant outages or other problems with its generation facilities could result in its firm capacity and ancillary services commitments exceeding its available generation capacity. As a result, an unexpected outage at one of Texas Genco's lower-cost facilities could require it to run one of its higher-cost plants or obtain replacement power from third parties in the open market in order to satisfy its obligations even though the energy payments for the dispatched power are based on the cost of its lower-cost facilities.

THE OPERATION OF TEXAS GENCO'S POWER GENERATION FACILITIES INVOLVES RISKS THAT COULD ADVERSELY AFFECT ITS REVENUES, COSTS, RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

Texas Genco is subject to various risks associated with operating its power generation facilities, any of which could adversely affect its revenues, costs, results of operations, financial condition and cash flows. These risks include:

- operating performance below expected levels of output or efficiency,

- breakdown or failure of equipment or processes,

- disruptions in the transmission of electricity,

- shortages of equipment, material or labor,

- labor disputes,

- fuel supply interruptions,

- limitations that may be imposed by regulatory requirements, including, among others, environmental standards,

- limitations imposed by the ERCOT ISO,

- violations of permit limitations,

- operator error, and

- catastrophic events such as fires, hurricanes, explosions, floods, terrorist attacks or other similar occurrences.

A significant portion of Texas Genco's facilities were constructed many years ago. Older generation equipment, even if maintained in accordance with good engineering practices, may require significant capital expenditures to keep it operating at high efficiency and to meet regulatory requirements. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure to produce power, including failure caused by breakdown or forced outage, could result in increased costs of operations and reduced earnings.

In December 2003, one of the three auxiliary standby diesel generators for Unit 2 at the South Texas Project failed during a routine test. The NRC allowed continued operation of Unit 2 while repairs to the generator were made. Repairs are expected to be completed before the end of a scheduled refueling outage on the unit in the spring of 2004. Should Unit 2 experience an unplanned shutdown prior to its scheduled outage, there is a risk that the NRC would not permit restarting the unit until the diesel generator was fully repaired. Texas Genco's share of the ultimate cost of repairs to the diesel generator is estimated to be approximately $5 million and is expected to be substantially covered by insurance.

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TEXAS GENCO RELIES ON POWER TRANSMISSION FACILITIES THAT IT DOES NOT OWN OR CONTROL AND THAT ARE SUBJECT TO TRANSMISSION CONSTRAINTS WITHIN THE ERCOT MARKET. IF THESE FACILITIES FAIL TO PROVIDE TEXAS GENCO WITH ADEQUATE TRANSMISSION CAPACITY, IT MAY NOT BE ABLE TO DELIVER WHOLESALE ELECTRIC POWER TO ITS CUSTOMERS AND IT MAY INCUR ADDITIONAL COSTS.

Texas Genco depends on transmission and distribution facilities owned and operated by CenterPoint Houston and by others to deliver the wholesale electric power it sells from its power generation facilities to its customers, who in turn deliver power to the end users. If transmission is disrupted, or if transmission capacity infrastructure is inadequate, Texas Genco's ability to sell and deliver wholesale electric energy may be adversely impacted.

The single control area of the ERCOT market for 2004 is organized into five congestion zones. Transmission congestion between the zones could impair Texas Genco's ability to schedule power for transmission across zonal boundaries, which are defined by the ERCOT ISO, thereby inhibiting Texas Genco's efforts to match its facility scheduled outputs with its customer scheduled requirements. In addition, power generators participating in the ERCOT market could be liable for congestion costs associated with transferring power between zones.

TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD
BE ADVERSELY IMPACTED BY A DISRUPTION OF ITS FUEL SUPPLIES.

Texas Genco relies primarily on natural gas, coal, lignite and uranium to fuel its generation facilities. Texas Genco purchases its fuel from a number of different suppliers under long-term contracts and on the spot market. Texas Genco sells firm entitlements to capacity and ancillary services. Therefore, any disruption in the delivery of fuel could prevent Texas Genco from operating its facilities, or force Texas Genco to enter into alternative arrangements at higher than prevailing market prices, to meet its auction commitments, which could adversely affect its results of operations, financial condition and cash flows.

TO DATE, TEXAS GENCO HAS SOLD A SUBSTANTIAL PORTION OF ITS CAPACITY ENTITLEMENTS TO SUBSIDIARIES OF RELIANT RESOURCES. ACCORDINGLY, TEXAS GENCO'S RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS COULD BE ADVERSELY AFFECTED IF RELIANT RESOURCES CEASES TO BE A MAJOR CUSTOMER OR FAILS TO MEET ITS OBLIGATIONS.

By participating in Texas Genco's contractually-mandated auctions, subsidiaries of Reliant Resources have purchased entitlements to 79% of Texas Genco's sold 2004 capacity and 68% of Texas Genco's sold 2005 capacity. Reliant Resources has made these purchases either through the exercise of its contractual rights to purchase 50% of the entitlements Texas Genco auctioned in its prior contractually-mandated auctions or through the submission of bids. In the event Reliant Resources ceases to be a major customer or fails to meet its obligations to Texas Genco, Texas Genco's results of operations, financial condition and cash flows could be adversely affected. As of December 31, 2003, Reliant Resources' securities ratings are below investment grade. Texas Genco has been granted a security interest in accounts receivable and/or securitization notes associated with the accounts receivable of certain subsidiaries of Reliant Resources to secure up to $250 million in purchase obligations.

TEXAS GENCO MAY INCUR SUBSTANTIAL COSTS AND LIABILITIES AS A RESULT OF ITS
OWNERSHIP OF NUCLEAR FACILITIES.

Texas Genco owns a 30.8% interest in the South Texas Project, a nuclear powered generation facility. As a result, Texas Genco is subject to risks associated with the ownership and operation of nuclear facilities. These risks include:

- liability associated with the potential harmful effects on the environment and human health resulting from the operation of nuclear facilities and the storage, handling and disposal of radioactive materials,

- limitations on the amounts and types of insurance commercially available to cover losses that might arise in connection with nuclear operations, and

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- uncertainties with respect to the technological and financial aspects of decommissioning nuclear plants at the end of their licensed lives.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. In the event of non-compliance, the NRC has the authority to impose fines, shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Any revised safety requirements promulgated by the NRC could necessitate substantial capital expenditures at nuclear plants. In addition, although we have no reason to anticipate a serious nuclear incident at the South Texas Project, if an incident were to occur, it could have a material adverse effect on Texas Genco's results of operations, financial condition and cash flows.

TEXAS GENCO'S OPERATIONS ARE SUBJECT TO EXTENSIVE REGULATION, INCLUDING ENVIRONMENTAL REGULATION. IF TEXAS GENCO FAILS TO COMPLY WITH APPLICABLE REGULATIONS OR TO OBTAIN OR MAINTAIN ANY NECESSARY GOVERNMENTAL PERMIT OR APPROVAL, IT MAY BE SUBJECT TO CIVIL, ADMINISTRATIVE AND/OR CRIMINAL PENALTIES THAT COULD ADVERSELY IMPACT ITS RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

Texas Genco's operations are subject to complex and stringent energy, environmental and other governmental laws and regulations. The acquisition, ownership and operation of power generation facilities require numerous permits, approvals and certificates from federal, state and local governmental agencies. These facilities are subject to regulation by the Texas Utility Commission regarding non-rate matters. Existing regulations may be revised or reinterpreted, new laws and regulations may be adopted or become applicable to Texas Genco or any of its generation facilities or future changes in laws and regulations may have a detrimental effect on its business.

Operation of the South Texas Project is subject to regulation by the NRC. 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.

Water for certain of Texas Genco's facilities is obtained from public water authorities. New or revised interpretations of existing agreements by those authorities or changes in price or availability of water may have a detrimental effect on Texas Genco's business.

Texas Genco's business is subject to extensive environmental regulation by federal, state and local authorities. Texas Genco is required to comply with numerous environmental laws and regulations and to obtain numerous governmental permits in operating its facilities. Texas Genco may incur significant additional costs to comply with these requirements. If Texas Genco fails to comply with these requirements or with any other regulatory requirements that apply to its operations, it could be subject to administrative, civil and/or criminal liability and fines, and regulatory agencies could take other actions seeking to curtail its operations. These liabilities or actions could adversely impact its results of operations, financial condition and cash flows.

Existing environmental regulations could be revised or reinterpreted, new laws and regulations could be adopted or become applicable to Texas Genco or its facilities, and future changes in environmental laws and regulations could occur, including potential regulatory and enforcement developments related to air emissions. If any of these events were to occur, Texas Genco's business, results of operations, financial condition and cash flows could be adversely affected.

Texas Genco may not be able to obtain or maintain from time to time all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals or if Texas Genco fails to obtain and comply with them, it may not be able to operate its facilities or it may be required to incur additional costs. Texas Genco is generally responsible for all on-site liabilities associated with the environmental condition of its power generation facilities, regardless of when the liabilities arose and whether the liabilities are known or unknown. These liabilities may be substantial.

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TEXAS GENCO'S REVENUES AND RESULTS OF OPERATIONS ARE SEASONAL.

The demand for power in the ERCOT market is seasonal, with higher demand occurring during the warmer months. Accordingly, Texas Genco's customers are generally willing to pay higher prices for entitlements to Texas Genco's capacity during warmer months. As a result, Texas Genco's revenues and results of operations are subject to seasonality, 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 FULL RECOVERY OF
ITS COSTS.

CERC's rates for natural gas distribution are regulated by certain municipalities and state commissions based on an analysis of its invested capital and its expenses incurred in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. While rate regulation is, generally, premised on providing a reasonable opportunity to recover reasonable and necessary operating expenses and to earn a reasonable return on invested capital, there can be no assurance that the municipalities and state commissions will judge all of CERC's costs to be reasonable or necessary or that the regulatory process in which rates are determined will always result in rates that will produce full recovery of CERC's costs.

CERC'S BUSINESSES MUST COMPETE WITH ALTERNATIVE ENERGY SOURCES, AND ITS PIPELINES AND GATHERING BUSINESSES MUST COMPETE DIRECTLY WITH OTHERS IN THE TRANSPORTATION AND STORAGE OF NATURAL GAS.

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.

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 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 CERC's service territory. Additionally, increasing gas prices could create the need for CERC to provide collateral in order to purchase gas.

CERC MAY INCUR CARRYING COSTS ASSOCIATED WITH PASSING THROUGH CHANGES IN THE
COSTS OF NATURAL GAS.

Generally, the regulations of the states in which CERC operates allow it to pass through changes in the costs of natural gas to its customers through purchased gas adjustment provisions in the applicable tariffs. There is, however, a timing difference between its purchases of natural gas and the ultimate recovery of these costs. Consequently, CERC may incur carrying costs as a result of this timing difference that are not recoverable from its customers. The failure to recover those additional carrying costs may have an adverse effect on CERC's results of operations, financial condition and cash flows.

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IF CERC WERE TO FAIL TO EXTEND CONTRACTS WITH TWO OF ITS SIGNIFICANT PIPELINE
CUSTOMERS, THERE COULD BE AN ADVERSE IMPACT ON ITS OPERATIONS.

Contracts with two of our significant pipeline customers, CenterPoint Energy Arkla and Laclede Gas Company, are currently scheduled to expire in 2005 and 2007, respectively. To the extent the pipelines are unable to extend these contracts or the contracts are renegotiated at rates substantially different than the rates provided in the current contracts, there could be an adverse effect on CERC's results of operations, financial condition and cash flows.

CERC'S INTERSTATE PIPELINES' REVENUES AND RESULTS OF OPERATIONS ARE SUBJECT TO
FLUCTUATIONS IN THE SUPPLY OF GAS.

CERC's interstate pipelines largely rely on gas sourced in the various supply basins located in the Midcontinent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on 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 are 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 FUND FUTURE CAPITAL EXPENDITURES AND REFINANCE EXISTING INDEBTEDNESS COULD BE LIMITED.

As of December 31, 2003, we had $11.0 billion of outstanding indebtedness on a consolidated basis. Approximately $3.5 billion principal amount of this debt must be paid through 2006, excluding principal repayments of approximately $142 million on transition bonds. In addition, the capital constraints and other factors currently impacting our businesses may require our future indebtedness to include terms that are more restrictive or burdensome than those of our current indebtedness. These terms may negatively impact our ability to operate our business, adversely affect our financial condition and results of operations or severely restrict or prohibit distributions from our subsidiaries. The success of our future financing efforts may depend, at least in part, on:

- our ability to recover the true-up components and to monetize our investment in Texas Genco;

- 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 Reliant Resources 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.

Our capital structure and liquidity will be significantly impacted in the 2004/2005 period by our ability to recover the true-up components through the regulatory process beginning in March 2004. To the extent our recovery is denied or materially reduced, our liquidity and financial condition will be materially adversely affected.

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As of March 1, 2004, our CenterPoint Houston subsidiary has $3.2 billion principal amount of general mortgage bonds outstanding and $382 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 $400 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 December 31, 2003, CenterPoint Houston has agreed under the $1.3 billion collateralized term loan maturing in 2005 to not issue, subject to certain exceptions, more than $200 million of incremental secured or unsecured debt. In addition, CenterPoint Houston is contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.

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 7 of Part II of this report. We cannot assure you that these credit ratings will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

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 substantially all our operating income from, and hold substantially 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.

As of December 31, 2003, we had $2.8 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. While we may seek to use interest rate swaps in order to hedge portions of our floating-rate debt, we may not be successful in obtaining hedges on acceptable terms. 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.

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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 directly or through subsidiaries and include:

- those transferred to Reliant Resources or its subsidiaries in connection with the organization and capitalization of Reliant Resources prior to its initial public offering in 2001,

- those transferred to Texas Genco in connection with its organization and capitalization, and

- those transferred to us and CenterPoint Houston in connection with the August 2002 restructuring of Reliant Energy.

In connection with the organization and capitalization of Reliant Resources, Reliant Resources and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. Reliant Resources 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 Reliant Resources and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Reliant Resources, regardless of the time those liabilities arose. If Reliant Resources is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy has not been released from the liability in connection with the transfer, we or CenterPoint Houston could be responsible for satisfying the liability.

Reliant Resources reported in its Annual Report on Form 10-K for the year ended December 31, 2003 that as of December 31, 2003 it had $6.1 billion of total debt and its unsecured debt ratings are currently below investment grade. If Reliant Resources were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event Reliant Resources might not honor its indemnification obligations and claims by Reliant Resources' creditors might be made against us as its former owner.

Reliant Energy and Reliant Resources 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 Reliant Resources, claims against Reliant Energy have been made on grounds that include the effect of Reliant Resources' financial results on Reliant Energy's historical financial statements and liability of Reliant Energy as a controlling shareholder of Reliant Resources. 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 Reliant Resources were determined to be unavailable or if Reliant Resources 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 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. If Texas Genco were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.

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WE MAY NOT BE ABLE TO MONETIZE TEXAS GENCO ON TERMS WE FIND ACCEPTABLE.

On January 23, 2004, Reliant Resources announced that it would not exercise its option to purchase the common stock of Texas Genco that we own. We will continue to operate Texas Genco's facilities and are pursuing an alternative strategy to monetize Texas Genco, and we have engaged a financial advisor to assist us in that pursuit. We may not be able to monetize our interest in Texas Genco under any alternative strategy on terms we find acceptable. In addition, delays in monetization may increase the risk that the value of the ownership interest used in the stranded cost determination, which is to be based on market prices for Texas Genco common stock during the 120 trading days ending on March 30, 2004, will be higher than the proceeds received in the monetization process.

WE, TOGETHER WITH OUR SUBSIDIARIES, EXCLUDING TEXAS GENCO, 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, excluding Texas Genco, are subject to regulation by the SEC under the 1935 Act. The 1935 Act, among other things, limits the ability of a holding company and its regulated subsidiaries to issue debt and equity securities without prior authorization, restricts the source of dividend payments to current and retained earnings without prior authorization, regulates sales and acquisitions of certain assets and businesses and governs affiliate transactions.

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

If as a result of the 2004 True-Up Proceeding or any other event we are required to take a charge against our net income, our current earnings could be reduced below the level which would enable us to pay the quarterly dividend on our common stock under our current SEC financing order. We expect to file an application with the SEC under the 1935 Act requesting an order authorizing us, in the event that we are required to take such a charge against our net income, to pay quarterly dividends out of capital or unearned surplus.

In addition, we would be required under the 1935 Act to obtain approval from the SEC to issue and sell securities for purposes of funding Texas Genco's operations or to guarantee a security of Texas Genco, except in emergency situations (in which we could provide funding pursuant to applicable SEC rules). Our failure to obtain approvals under the 1935 Act in a timely manner could adversely affect our and our subsidiaries' results of operations, financial condition and cash flows.

The United States Congress is currently considering legislation that has a provision that would repeal the 1935 Act. We cannot predict at this time whether this legislation or any variation thereof will be adopted or, if adopted, the effect of any such law on our business.

OUR INSURANCE COVERAGE MAY NOT BE SUFFICIENT. INSUFFICIENT INSURANCE COVERAGE AND INCREASED INSURANCE COSTS COULD ADVERSELY IMPACT OUR RESULTS OF OPERATIONS, FINANCIAL CONDITION AND CASH FLOWS.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. We cannot assure you that insurance coverage will be available in the future at current costs or on commercially reasonable terms or that the insurance proceeds received for any loss of or any damage to any of our facilities will be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

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

19

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 federal Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $10.6 billion as of December 31, 2003. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners of the South Texas Project currently maintain the required nuclear liability insurance and participate in the industry retrospective rating plan. In addition, the security procedures at this facility have recently been enhanced to provide additional protection against terrorist attacks. All potential losses or liabilities associated with the South Texas Project may not be insurable, and the amount of insurance may not be sufficient to cover them.

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 would be entitled to seek to recover such loss or damage through a change in its regulated rates, although there is no assurance that CenterPoint Houston ultimately would obtain any such rate recovery or that any such rate recovery would be timely granted. Therefore, we cannot assure you that CenterPoint Houston will 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.

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 outcome of the regulatory process leading to the determination and recovery of the true-up components and the securitization of these amounts;

- the timing and results of the monetization of our interest in Texas Genco;

- state and federal legislative and regulatory actions or developments, including deregulation, re-regulation and restructuring of the electric utility industry, 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;

- termination of accruals of ECOM true-up after 2003;

- 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;

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- commercial bank and financial market conditions, our access to capital, the cost of such capital, receipt of certain approvals under the 1935 Act, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

- actions by rating agencies;

- inability of various counterparties to meet their obligations to us;

- non-payment for our services due to financial distress of our customers, including Reliant Resources;

- the outcome of the pending securities lawsuits against us, Reliant Energy and Reliant Resources;

- the ability of Reliant Resources to satisfy its obligations to us, including indemnity obligations and obligations to pay the "price to beat" clawback; and

- other factors discussed in Item 1 of this report under "Risk Factors."

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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:

                                                                          DECEMBER 31,
                                                     ESTIMATED USEFUL   -----------------
                                                      LIVES (YEARS)      2002      2003
                                                     ----------------   -------   -------
                                                                          (IN MILLIONS)
Electric transmission & distribution...............        5-75         $ 5,960   $ 6,085
Electric generation................................        5-60           9,610     9,436
Natural gas distribution...........................        5-50           2,151     2,316
Pipelines and gathering............................        5-75           1,686     1,722
Other property.....................................        3-40             446       446
                                                                        -------   -------
  Total............................................                      19,853    20,005
Accumulated depreciation and amortization..........                      (7,738)   (8,194)
                                                                        -------   -------
     Property, plant and equipment, net............                     $12,115   $11,811
                                                                        =======   =======

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

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

22

With the adoption of SFAS No. 142, the Company ceased amortization of goodwill as of January 1, 2002. A reconciliation of previously reported net income and earnings per share to the amounts adjusted for the exclusion of goodwill amortization follows (in millions, except per share amounts):

 

                                                                YEAR ENDED
                                                               DECEMBER 31,
                                                                   2001
                                                               ------------
Reported income from continuing operations before cumulative
  effect of accounting change...............................      $ 499
Add: Goodwill amortization, net of tax......................         49
                                                                  -----
Adjusted income from continuing operations before cumulative
  effect of accounting change...............................      $ 548
                                                                  =====
Basic Earnings Per Share:
Reported income from continuing operations before cumulative
  effect of accounting change...............................      $1.72
Add: Goodwill amortization, net of tax......................       0.17
                                                                  -----
Adjusted income from continuing operations before cumulative
  effect of accounting change...............................      $1.89
                                                                  =====
Diluted Earnings Per Share:
Reported income from continuing operations before cumulative
  effect of accounting change...............................      $1.71
Add: Goodwill amortization, net of tax......................       0.17
                                                                  -----
Adjusted income from continuing operations before cumulative
  effect of accounting change...............................      $1.88
                                                                  =====

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

 

                                                DECEMBER 31, 2002         DECEMBER 31, 2003
                                             -----------------------   -----------------------
                                             CARRYING   ACCUMULATED    CARRYING   ACCUMULATED
                                              AMOUNT    AMORTIZATION    AMOUNT    AMORTIZATION
                                             --------   ------------   --------   ------------
                                                               (IN MILLIONS)
Land Use Rights............................    $61          $(12)        $61          $(14)
Other......................................     19            (2)         38            (5)
                                               ---          ----         ---          ----
  Total....................................    $80          $(14)        $99          $(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 December 31, 2003. The Company amortizes other acquired intangibles on a straight-line basis over the lesser of their contractual or estimated useful lives that range from 40 to 75 years for land rights and 4 to 25 years for other intangibles.

Amortization expense for other intangibles for 2001, 2002 and 2003 was $1 million, $2 million and $4 million, respectively. Estimated amortization expense for the five succeeding fiscal years is as follows (in millions):

 

2004........................................................   $ 5
2005........................................................     3
2006........................................................     2
2007........................................................     2
2008........................................................     2
                                                               ---
  Total.....................................................   $14
                                                               ===

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

 

                                                               DECEMBER 31,
                                                               2002 AND 2003
                                                               -------------
Natural Gas Distribution....................................      $1,085
Pipelines and Gathering.....................................         601
Other Operations............................................          55
                                                                  ------
  Total.....................................................      $1,741
                                                                  ======

The Company completed its review during the second quarter of 2003 pursuant to SFAS No. 142 for its reporting units in the Natural Gas Distribution, Pipelines and Gathering and Other Operations business segments. No impairment was indicated as a result of this assessment.

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. An impairment analysis of generating facilities requires estimates of possible future market prices, load growth, competition and many other factors over the lives of the facilities. A resulting impairment loss is highly dependent on these underlying assumptions.

The Company has engaged a financial advisor to assist in exploring alternatives for monetizing its 81% interest in Texas Genco, including possible sale of its ownership interest in Texas Genco. As a result of the Company's intention to monetize its interest in Texas Genco, the Company performed an impairment analysis of Texas Genco's assets as of December 31, 2003 in accordance with the provisions of SFAS No. 144. As of December 31, 2003 no impairment had been indicated. The fair value of Texas Genco's assets could be materially affected by a change in the estimated future cash flows for these assets. Future cash flows for Texas Genco are estimated using a probability-weighted approach based on the fair value of its common stock, operating projections and estimates of how long these assets will be retained. Changes in any of these assumptions could result in an impairment charge.

(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.

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The following is a list of regulatory assets/liabilities reflected on the Company's Consolidated Balance Sheets as of December 31, 2002 and 2003:

 

                                                               DECEMBER 31,
                                                              ---------------
                                                               2002     2003
                                                              ------   ------
                                                               (IN MILLIONS)
Recoverable Electric Generation-Related Regulatory Assets,
  net:
     Recoverable electric generation plant mitigation.......  $2,051   $2,116
     Excess mitigation liability............................    (969)    (778)
                                                              ------   ------
          Net electric generation plant mitigation asset....   1,082    1,338
     Excess cost over market (ECOM/capacity auction)
      true-up...............................................     697    1,357
     Texas Genco distribution/impairment....................      --      399
     Regulatory tax asset...................................     175      119
     Final fuel under/(over) recovery balance...............      64      (98)
     Other 2004 True-Up Proceeding items....................      53      119
                                                              ------   ------
       Total Recoverable Electric Generation-Related
        Regulatory Assets...................................   2,071    3,234
Securitized regulatory asset................................     706      682
Unamortized loss on reacquired debt.........................      58       80
Estimated removal costs.....................................      --     (647)
Other long-term regulatory assets/liabilities...............      38       38
                                                              ------   ------
  Total.....................................................  $2,873   $3,387
                                                              ======   ======

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. In addition, the Company would be required to determine any impairment of the carrying costs of plant and inventory assets. Because estimates of the fair value of Texas Genco are required, the financial impacts of the Texas electric restructuring law with respect to the final determination of stranded costs are subject to material changes. Factors affecting such changes may include estimation risk, uncertainty of future energy and commodity prices and the economic lives of the plants. See Note 4 for additional discussion of regulatory assets.

(4) REGULATORY MATTERS

(a) TRUE-UP COMPONENTS AND SECURITIZATION

The Texas Electric Restructuring Law. In June 1999, the Texas legislature adopted the Texas Electric Choice Plan (the Texas electric restructuring law), which substantially amended the regulatory structure governing electric utilities in order to allow and encourage retail competition which began in January 2002. The Texas electric restructuring law required the separation of the generation, transmission and distribution, and retail sales functions of electric utilities into three different units. Under the law, neither the generation function nor the retail function is subject to traditional cost of service regulation, and the generation and the retail function are each operated on a competitive basis.

The transmission and distribution function that CenterPoint Houston performs remains subject to traditional utility rate regulation. CenterPoint Houston recovers the cost of its service through an energy delivery charge approved by the Texas Utility Commission. As a result of these changes, there are no meaningful comparisons for the Electric Transmission & Distribution and Electric Generation business segments prior to 2002 when retail sales became fully competitive.

Under the Texas electric restructuring law, transmission and distribution utilities in Texas, such as CenterPoint Houston, whose generation assets were "unbundled" may recover, following a regulatory

25

proceeding to be held in 2004 (2004 True-Up Proceeding) as further discussed below in "-- 2004 True-Up Proceeding":

- "stranded costs," which consist of the positive excess of the regulatory net book value of generation assets, as defined, over the market value of the assets, taking specified factors into account;

- the difference between the Texas Utility Commission's projected market prices for generation during 2002 and 2003 and the actual market prices for generation as determined in the state-mandated capacity auctions during that period;

- the Texas jurisdictional amount reported by the previously vertically integrated electric utilities as generation-related regulatory assets and liabilities (offset and adjusted by specified amounts) in their audited financial statements for 1998;

- final fuel over- or under-recovery; less

- "price to beat" clawback components.

The Texas electric restructuring law permits transmission and distribution utilities to recover the true-up components through transition charges on retail electric customers' bills, to the extent that such components are established in certain regulatory proceedings. These transition charges are non-bypassable, meaning that they must be paid by essentially all customers and cannot, except in limited circumstances, be avoided by switching to self-generation. The law also authorizes the Texas Utility Commission to permit those utilities to issue transition bonds based on the securitization of revenues associated with the transition charges. CenterPoint Houston recovered a portion of its regulatory assets in 2001 through the issuance of transition bonds. For a further discussion of these matters, see "-- Securitization" below.

The Texas electric restructuring law also provides specific regulatory remedies to reduce or mitigate a utility's stranded cost exposure. During a base rate freeze period from 1999 through 2001, earnings above the utility's authorized rate of return formula were required to be applied in a manner to accelerate depreciation of generation-related plant assets for regulatory purposes if the utility was expected to have stranded costs. In addition, depreciation expense for transmission and distribution-related assets could be redirected to generation assets for regulatory purposes during that period if the utility was expected to have stranded costs. CenterPoint Houston undertook both of these remedies provided in the Texas electric restructuring law, but in a rate order issued in October 2001, the Texas Utility Commission required CenterPoint Houston to reverse those actions. For a further discussion of these matters, see "-- Mitigation" below.

2004 True-Up Proceeding. In 2004, the Texas Utility Commission will conduct true-up proceedings for investor-owned utilities. The purpose of the true-up proceeding is to quantify and reconcile the amount of the true-up components. The true-up proceeding will result in either additional charges being assessed on, or credits being issued to, retail electric customers. CenterPoint Houston expects to make the filing to initiate its final true-up proceeding on March 31, 2004. The Texas electric restructuring law requires a final order to be issued by the Texas Utility Commission not more than 150 days after a proper filing is made by the regulated utility, although under its rules the Texas Utility Commission can extend the 150-day deadline for good cause. Any delay in the final order date will result in a delay in the securitization of CenterPoint Houston's true-up components and the implementation of the non-bypassable charges described above, and could delay the recovery of carrying costs on the true-up components determined by the Texas Utility Commission.

CenterPoint Houston will be required to establish and support the amounts it seeks to recover in the 2004 True-Up Proceeding. CenterPoint Houston expects these amounts to be substantial. Third parties will have the opportunity and are expected to challenge CenterPoint Houston's calculation of these amounts. To the extent recovery of a portion of these amounts is denied or if CenterPoint Houston agrees to forego recovery of a portion of the request under a settlement agreement, CenterPoint Houston would be unable to recover those amounts in the future.

Following adoption of the true-up rule by the Texas Utility Commission in 2001, CenterPoint Houston appealed the provisions of the rule that permitted interest to be recovered on stranded costs only from the date of the Texas Utility Commission's final order in the 2004 True-Up Proceeding, instead of from January 1,

26

2002 as CenterPoint Houston contends is required by law. On January 30, 2004, the Texas Supreme Court granted CenterPoint Houston's petition for review of the true-up rule. Oral arguments were heard on February 18, 2004. The decision by the Court is pending. The Company has not accrued interest income on stranded costs in its consolidated financial statements, but estimates such interest income would be material to the Company's consolidated financial statements.

Stranded Cost Component. CenterPoint Houston will be entitled to recover stranded costs through a transition charge to its customers if the regulatory net book value of generating plant assets exceeds the market value of those assets. The regulatory net book value of generating plant assets is the balance as of December 31, 2001 plus certain costs incurred for reductions in emissions of oxides of nitrogen (NOx), any above-market purchased power contracts and certain other amounts. The market value will be equal to the average daily closing price on The New York Stock Exchange for publicly held shares of Texas Genco common stock for 30 consecutive trading days chosen by the Texas Utility Commission out of the last 120 trading days immediately preceding the true-up filing, plus a control premium, up to a maximum of 10%, to the extent included in the valuation determination made by the Texas Utility Commission. If Texas Genco is sold to a third party at a lower price than the market value used by the Texas Utility Commission, CenterPoint Houston would be unable to recover the difference.

ECOM True-Up Component. The Texas Utility Commission used a computer model or projection, called an excess cost over market (ECOM) model, to estimate stranded costs related to generation plant assets. Accordingly, the Texas Utility Commission estimated the market power prices that would be received in the generation capacity auctions mandated by the Texas electric restructuring law during 2002 and 2003. Any difference between the Texas Utility Commission's projected market prices for generation during 2002 and 2003 and the actual market prices for generation as determined in the state-mandated capacity auctions during that period will be a component of the 2004 True-Up Proceeding. In accordance with the Texas Utility Commission's rules regarding the ECOM True-Up, for the years ended December 31, 2002 and 2003, CenterPoint Energy recorded approximately $697 million and $661 million, respectively, in non-cash ECOM True-Up revenue. ECOM True-Up revenue is recorded as a regulatory asset and totaled $1.4 billion as of December 31, 2003.

In 2003, some parties sought modifications to the true-up rules. Although the Texas Utility Commission denied that request, the Company expects that issues could be raised in the 2004 True-Up Proceeding regarding its compliance with the Texas Utility Commission's rules regarding the ECOM true-up, including whether Texas Genco has auctioned all capacity it is required to auction in view of the fact that some capacity has failed to sell in the state-mandated auctions. The Company believes Texas Genco has complied with the requirements under the applicable rules, including re-offering the unsold capacity in subsequent auctions. If events were to occur during the 2004 True-Up Proceeding that made the recovery of the ECOM true-up regulatory asset no longer probable, the Company would write off the unrecoverable balance of that asset as a charge against earnings.

Fuel Over/Under Recovery Component. CenterPoint Houston and Texas Genco filed their joint application to reconcile fuel revenues and expenses with the Texas Utility Commission in July 2002. This final fuel reconciliation filing covered reconcilable fuel expense and interest of approximately $8.5 billion incurred from August 1, 1997 through January 30, 2002. In January 2003, a settlement agreement was reached, as a result of which certain items totaling $24 million were written off during the fourth quarter of 2002 and items totaling $203 million were carried forward for later resolution by the Texas Utility Commission. In late 2003, a hearing was concluded on those remaining issues. On March 4, 2004, an Administrative Law Judge (ALJ) recommended that CenterPoint Houston not be allowed to recover $87 million in fuel expenses incurred during the reconciliation period. CenterPoint Houston will contest this recommendation when the Texas Utility Commission considers the ALJ's conclusions on April 15, 2004. However, since the recovery of this portion of the regulatory asset is no longer probable, CenterPoint Houston reserved $117 million, including interest, in the fourth quarter of 2003. The ALJ also recommended that $46 million be recovered in the 2004 True-Up Proceeding rather than in the fuel proceeding. The results of the Texas Utility Commission's decision will be a component of the 2004 True-Up Proceeding.

27

"Price to Beat" Clawback Component. In connection with the implementation of the Texas electric restructuring law, the Texas Utility Commission has set a "price to beat" that retail electric providers affiliated or formerly affiliated with a former integrated utility must charge residential and small commercial customers within their affiliated electric utility's service area. The true-up provides for a clawback of the "price to beat" in excess of the market price of electricity if 40% of the "price to beat" load is not served by other retail electric providers by January 1, 2004. Pursuant to the Texas electric restructuring law and a master separation agreement entered into in connection with the September 30, 2002 spin-off of the Company's interest in Reliant Resources to the Company's shareholders, Reliant Resources is obligated to pay CenterPoint Houston the clawback component of the true-up. Based on an order issued on February 13, 2004 by the Texas Utility Commission, the clawback will equal $150 times the number of residential customers served by Reliant Resources in CenterPoint Houston's service territory, less the number of residential customers served by Reliant Resources outside CenterPoint Houston's service territory, on January 1, 2004. As reported in Reliant Resources' Annual Report on Form 10-K for the year ended December 31, 2003, Reliant Resources expects that the clawback payment will be $175 million. The clawback will reduce the amount of recoverable costs to be determined in the 2004 True-Up Proceeding.

Securitization. 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 out of funds from non-bypassable transition charges.

The Company expects that upon completion of the 2004 True-Up Proceeding, CenterPoint Houston will seek to securitize the amounts established for the true-up components. Before CenterPoint Houston can securitize these amounts, the Texas Utility Commission must conduct a proceeding and issue a financing order authorizing CenterPoint Houston to do so. Under the Texas electric restructuring law, CenterPoint Houston is entitled to recover any portion of the true-up balance not securitized by transition bonds through a non-bypassable competition transition charge.

Mitigation. In an order issued in October 2001, the Texas Utility Commission established the transmission and distribution rates that became effective in January 2002. 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 transition plan and the Texas electric restructuring law. In this final order, CenterPoint Houston was required to reverse the amount of redirected depreciation ($841 million) and accelerated depreciation ($1.1 billion) taken for regulatory purposes as allowed under the transition plan and the Texas electric restructuring law. In accordance with the order, CenterPoint Houston recorded a regulatory liability of $1.1 billion to reflect the prospective refund of the accelerated depreciation, and in January 2002 CenterPoint Houston began refunding excess mitigation credits, which are to be refunded over a seven-year period. The annual refund of excess mitigation credits is approximately $238 million. As of December 31, 2002 and 2003, the Company had recorded net electric plant mitigation regulatory assets of $1.1 billion and $1.3 billion, respectively, based on the Company's expectation that these amounts will be recovered in the 2004 True-Up Proceeding as stranded costs. In the event that the excess mitigation credits prove to have been unnecessary and CenterPoint Houston is determined to have stranded costs, the excess mitigation credits will be included in the stranded costs to be recovered. In June 2003, CenterPoint Houston sought authority from the Texas Utility Commission to terminate these credits based on then current estimates of what that final determination would be. The Texas Utility Commission denied the request in January 2004.

(b) RATE CASES

In August 2002, a settlement was approved by the Arkansas Public Service Commission (APSC) that resulted in an increase in the base rate and service charge revenues of CenterPoint Energy Arkla (Arkla) of

28

approximately $27 million annually. In addition, the APSC approved a gas main replacement surcharge that provided $2 million of additional revenue in 2003 and is expected to provide additional amounts in subsequent years.

In December 2002, a settlement was approved by the Oklahoma Corporation Commission that resulted in an increase in the base rate and service charge revenues of Arkla of approximately $6 million annually.

In November 2003, Arkla filed a request with the Louisiana Public Service Commission (LPSC) for a $16 million increase to its base rate and service charge revenues in Louisiana. The case is expected to be resolved in mid-2004.

In December 2003, a settlement was approved by the City of Houston that will result in an increase in the base rate and service charge revenues of CenterPoint Energy Entex (Entex) of approximately $7 million annually. Entex has submitted these settlement rates to the 28 other cities within its Houston Division and the Railroad Commission of Texas for consideration and approval. If all regulatory approvals are received from these 29 jurisdictions, Entex's base rate and service charge revenues are expected to increase by approximately $7 million annually in addition to the $7 million increase discussed above.

On February 10, 2004, a settlement was approved by the LPSC that is expected to result in an increase in Entex's base rate and service charge revenues of approximately $2 million annually.

(c) NUCLEAR DECOMMISSIONING TRUST

Texas Genco is the beneficiary of decommissioning trusts that have been established to provide funding for decontamination and decommissioning of a nuclear electric generation station in which Texas Genco owns a 30.8% interest (see Notes 6 and 12(e)). CenterPoint Houston collects through rates or other authorized charges to its electric utility customers amounts designated for funding the decommissioning trusts, and deposits these amounts into the decommissioning trusts. Upon decommissioning of the facility, in the event funds from the trusts are inadequate, CenterPoint Houston or its successor will be required to collect through rates or other authorized charges to customers as contemplated by the Texas Utilities Code all additional amounts required to fund Texas Genco's obligations relating to the decommissioning of the facility. Following the completion of the decommissioning, if surplus funds remain in the decommissioning trust, the excess will be refunded to the ratepayers of CenterPoint Houston or its successor.

(d) OTHER REGULATORY PROCEEDINGS

City of Tyler, Texas Dispute. In July 2002, the City of Tyler, Texas, asserted that Entex had overcharged residential and small commercial customers in that city for excessive gas costs under supply agreements in effect since 1992. That dispute has been referred to the Texas Railroad Commission by agreement of the parties for a determination of whether Entex has properly and lawfully charged and collected for gas service to its residential and commercial customers in its Tyler distribution system for the period beginning November 1, 1992, and ending October 31, 2002. The Company believes that all costs for Entex's Tyler distribution system have been properly included and recovered from customers pursuant to Entex's filed tariffs.

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

Following issuance of the Show Cause Order, CEGT made certain compliance filings, met with members of the FERC's staff and provided additional information relating to the FERC's Show Cause Order. On March 4, 2004, the FERC issued orders accepting CEGT's compliance filings and approving a Stipulation and

29

Consent Agreement with CEGT that resolved the issues raised by the Show Cause Order. The resolution of these issues did not have a material impact on our results of operations, financial condition and cash flows.

(5) DERIVATIVE INSTRUMENTS

Effective January 1, 2001, the Company adopted SFAS No. 133, which establishes accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. This statement requires that derivatives be recognized at fair value in the balance sheet and that changes in fair value be recognized either currently in earnings or deferred as a component of other comprehensive income, depending on the intended use of the derivative instrument as hedging
(a) the exposure to changes in the fair value of an asset or liability (Fair Value Hedge) or (b) the exposure to variability in expected future cash flows (Cash Flow Hedge) or (c) the foreign currency exposure of a net investment in a foreign operation. For a derivative not designated as a hedging instrument, the gain or loss is recognized in earnings in the period it occurs.

Adoption of SFAS No. 133 on January 1, 2001 resulted in an after-tax increase in net income of $59 million and a cumulative after-tax increase in accumulated other comprehensive income of $38 million.

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 and cash flows of its natural gas businesses on its operating results and cash flows.

(a) NON-TRADING ACTIVITIES

Cash Flow Hedges. To reduce the risk from market fluctuations associated with purchased gas costs, the Company enters into energy derivatives in order to hedge certain expected purchases and sales of natural gas (non-trading energy derivatives). The Company applies hedge accounting for its non-trading energy derivatives utilized in non-trading activities only if there is a high correlation between price movements in the derivative and the item designated as being hedged. The Company analyzes its physical transaction portfolio to determine its net exposure by delivery location and delivery period. Because the Company's physical transactions with similar delivery locations and periods are highly correlated and share similar risk exposures, the Company facilitates hedging for customers by aggregating physical transactions and subsequently entering into non-trading energy derivatives to mitigate exposures created by the physical positions.

During 2003, no hedge ineffectiveness was recognized in earnings from derivatives that are designated and qualify as Cash Flow Hedges. No component of the derivative instruments' gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction will not occur, the Company realizes in net income the deferred gains and losses recognized in accumulated other comprehensive 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 "Fuel and Cost of Gas Sold." Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of December 31, 2003, the Company expects $38 million in accumulated other comprehensive loss 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.

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, and was marked to market in the Company's Consolidated Balance Sheets with changes reflected in interest expense in the Statements of Consolidated Operations.

30

During the year ended December 31, 2002, the Company settled its 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 reclassified $36 million and $12 million to interest expense in 2002 and 2003, respectively. The remaining $108 million in other comprehensive income is being amortized into interest expense in the same period during which the interest payments are made for the designated fixed-rate debt.

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 9), 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 December 31, 2003.

(b) CREDIT RISKS

In addition to the risk associated with price movements, credit risk is also inherent in the Company's non-trading derivative activities. Credit risk relates to the risk of loss resulting from non-performance of contractual obligations by a counterparty. The following table shows the composition of the non-trading derivative assets of the Company as of December 31, 2002 and 2003 (in millions):

 

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


(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 $35 million non-trading derivative asset includes an $11 million asset due to trades with Reliant Energy Services, Inc. (Reliant Energy Services), an affiliate until the date of the Reliant Resources Distribution. As of December 31, 2003, 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.

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(7) 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). 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.

(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, 2003, ZENS having an original principal amount of $840 million and a contingent principal amount of $848 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, 2003, the market value of such shares was approximately $389 million, which would provide an exchange amount of $440 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.

Through December 31, 2003, holders of approximately 16% of the 17.2 million ZENS originally issued had exercised their right to exchange their ZENS for cash, resulting in aggregate cash payments by CenterPoint Energy of approximately $45 million.

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. In connection with the exchanges in 2002, 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, resulting in a transition adjustment pre-tax gain of $90 million ($59 million net of tax). The transition adjustment gain was reported in the first quarter of 2001 as the effect of a change in accounting principle. 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 2001, 2002 and 2003, the Company recorded a loss of $70 million, a loss of $500 million and a gain of $106 million, respectively, on the Company's investment in TW Common. During 2001, 2002 and 2003, the Company recorded a gain of $58 million, a gain of $480 million and a loss of $96 million, respectively, associated with the fair value of the derivative

32

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.

The following table sets forth summarized financial information regarding the Company's investment in TW securities and the Company's ZENS obligation (in millions).

 

                                                                      DEBT      DERIVATIVE
                                                           TW       COMPONENT   COMPONENT
                                                       INVESTMENT    OF ZENS     OF ZENS
                                                       ----------   ---------   ----------
Balance at December 31, 2000.........................     $897       $1,000       $  --
Transition adjustment from adoption of SFAS No.
  133................................................       --          (90)         --
Bifurcation of ZENS obligation.......................       --         (788)        788
Accretion of debt component of ZENS..................       --            1          --
Gain on indexed debt securities......................       --           --         (58)
Loss on TW Common....................................      (70)          --          --
                                                          ----       ------       -----
Balance at December 31, 2001.........................      827          123         730
Accretion of debt component of ZENS..................       --            1          --
Gain on indexed debt securities......................       --           --        (480)
Loss on TW Common....................................     (500)          --          --
Liquidation of TW Common.............................      (43)          --          --
Liquidation of ZENS, net of gain.....................       --          (20)        (25)
                                                          ----       ------       -----
Balance at December 31, 2002.........................      284          104         225
Accretion of debt component of ZENS..................       --            1          --
Loss on indexed debt securities......................       --           --          96
Gain on TW Common....................................      106           --          --
                                                          ----       ------       -----
Balance at December 31, 2003.........................     $390       $  105       $ 321
                                                          ====       ======       =====

(10) STOCK-BASED INCENTIVE COMPENSATION PLANS AND EMPLOYEE BENEFIT PLANS

(b) PENSION AND POSTRETIREMENT BENEFITS

The Company maintains a non-contributory qualified defined benefit plan covering substantially all employees, with benefits determined using a cash balance formula. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. As a result, certain employees participating in the plan as of December 31, 1998 are eligible to receive the greater of the accrued benefit calculated under the prior plan through 2008 or the cash balance formula.

The Company provides certain healthcare and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments, effective in early 1999, healthcare benefits for future retirees were changed to limit employer contributions for medical coverage.

Such benefit costs are accrued over the active service period of employees. The net unrecognized transition obligation, resulting from the implementation of accrual accounting, is being amortized over approximately 20 years.

On January 12, 2004, the FASB issued FSP FAS 106-1. In accordance with FSP FAS 106-1, the Company's postretirement benefits obligations and net periodic postretirement benefit cost in the financial statements and accompanying notes do not reflect the effects of the legislation. Specific authoritative guidance on the accounting for the legislation is pending and that guidance, when issued, may require the Company to change previously reported information.

33

The Company's net periodic cost includes the following components relating to pension and postretirement benefits:

 

                                                      YEAR ENDED DECEMBER 31,
                         ---------------------------------------------------------------------------------
                                   2001                        2002                        2003
                         -------------------------   -------------------------   -------------------------
                         PENSION    POSTRETIREMENT   PENSION    POSTRETIREMENT   PENSION    POSTRETIREMENT
                         BENEFITS      BENEFITS      BENEFITS      BENEFITS      BENEFITS      BENEFITS
                         --------   --------------   --------   --------------   --------   --------------
                                                           (IN MILLIONS)
Service cost...........   $  35          $  5         $  32          $  5          $ 37          $  4
Interest cost..........      99            31           104            32           102            31
Expected return on plan
  assets...............    (138)          (13)         (126)          (13)          (92)          (11)
Net amortization.......      (3)           14            16            13            43            13
Curtailment............     (23)           40            --            --            --            --
Benefit enhancement....      69            --             9             3            --            --
Settlement.............      --            --            --           (18)           --            --
                          -----          ----         -----          ----          ----          ----
Net periodic cost......   $  39          $ 77         $  35          $ 22          $ 90          $ 37
                          =====          ====         =====          ====          ====          ====
Above amounts reflect
  the following net
  periodic cost
  (benefit) related to
  discontinued
  operations...........   $  45          $ 42         $  (4)         $(16)         $ --          $ --
                          =====          ====         =====          ====          ====          ====

The Company used the following assumptions to determine net periodic cost relating to pension and postretirement benefits:

 

                                                      YEAR ENDED DECEMBER 31,
                         ---------------------------------------------------------------------------------
                                   2001                        2002                        2003
                         -------------------------   -------------------------   -------------------------
                         PENSION    POSTRETIREMENT   PENSION    POSTRETIREMENT   PENSION    POSTRETIREMENT
                         BENEFITS      BENEFITS      BENEFITS      BENEFITS      BENEFITS      BENEFITS
                         --------   --------------   --------   --------------   --------   --------------
Discount rate..........     7.50%            7.50%      7.25%            7.25%      6.75%            6.75%
Expected return on plan
  assets...............     10.0%            10.0%       9.5%             9.5%       9.0%             9.0%
Rate of increase in
  compensation
  levels...............      4.1%               --       4.1%               --       4.1%               --

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

34

The following table displays the change in the benefit obligation, the fair value of plan assets and the amounts included in the Company's Consolidated Balance Sheets as of December 31, 2002 and 2003 for the Company's pension and postretirement benefit plans:

 

                                                                DECEMBER 31,
                                        -------------------------------------------------------------
                                                    2002                            2003
                                        -----------------------------   -----------------------------
                                          PENSION      POSTRETIREMENT     PENSION      POSTRETIREMENT
                                          BENEFITS        BENEFITS        BENEFITS        BENEFITS
                                        ------------   --------------   ------------   --------------
                                                                (IN MILLIONS)
CHANGE IN BENEFIT OBLIGATION
Benefit obligation, beginning of
  year................................  $      1,485    $        456    $      1,550    $        479
Service cost..........................            32               5              37               4
Interest cost.........................           104              32             102              31
Participant contributions.............            --               7              --               8
Benefits paid.........................          (136)            (26)           (142)            (43)
Plan amendments.......................            --              --               4              (5)
Actuarial loss........................            56              20             141              44
Curtailment, benefit enhancement and
  settlement..........................             9             (15)             --              --
                                        ------------    ------------    ------------    ------------
Benefit obligation, end of year.......  $      1,550    $        479    $      1,692    $        518
                                        ============    ============    ============    ============
CHANGE IN PLAN ASSETS
Plan assets, beginning of year........  $      1,376    $        139    $      1,054    $        131
Employer contributions................            --              30              23              34
Participant contributions.............            --               7              --               8
Benefits paid.........................          (136)            (26)           (142)            (43)
Actual investment return..............          (186)            (19)            259              20
                                        ------------    ------------    ------------    ------------
Plan assets, end of year..............  $      1,054    $        131    $      1,194    $        150
                                        ============    ============    ============    ============
RECONCILIATION OF FUNDED STATUS
Funded status.........................  $       (496)   $       (348)   $       (498)   $       (368)
Unrecognized actuarial loss...........           811              27             733              63
Unrecognized prior service cost.......           (84)             60             (71)             49
Unrecognized transition (asset)
  obligation..........................            --              87              --              79
                                        ------------    ------------    ------------    ------------
Net amount recognized.................  $        231    $       (174)   $        164    $       (177)
                                        ============    ============    ============    ============
AMOUNTS RECOGNIZED IN BALANCE SHEETS
Benefit obligations...................  $       (392)   $       (174)   $       (395)   $       (177)
Accumulated other comprehensive
  income..............................           623              --             559              --
                                        ------------    ------------    ------------    ------------
Prepaid (accrued) pension cost........  $        231    $       (174)   $        164    $       (177)
                                        ============    ============    ============    ============
ACTUARIAL ASSUMPTIONS
Discount rate.........................          6.75%           6.75%           6.25%           6.25%
Expected return on plan assets........           9.0%            9.0%            9.0%            8.5%
Rate of increase in compensation
  levels..............................           4.1%             --             4.1%             --
Healthcare cost trend rate assumed for
  the next year.......................            --           11.25%             --           10.50%
Rate to which the cost trend rate is
  assumed to decline (the ultimate
  trend rate).........................            --             5.5%             --             5.5%
Year that the rate reaches the
  ultimate trend rate.................            --            2011              --            2011

35

 
                                                                DECEMBER 31,
                                        -------------------------------------------------------------
                                                    2002                            2003
                                        -----------------------------   -----------------------------
                                          PENSION      POSTRETIREMENT     PENSION      POSTRETIREMENT
                                          BENEFITS        BENEFITS        BENEFITS        BENEFITS
                                        ------------   --------------   ------------   --------------
                                                                (IN MILLIONS)
ADDITIONAL INFORMATION
Accumulated benefit obligation........  $      1,446    $        479    $      1,589    $        518
Change in minimum liability included                                                )
  in other comprehensive income.......           623              --             (64              --
Measurement date used to determine      December 31,    December 31,    December 31,    December 31,
  plan obligations and assets.........          2002            2002            2003            2003

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

 

                                                                 1%         1%
                                                              INCREASE   DECREASE
                                                              --------   --------
                                                                 (IN MILLIONS)
Effect on total of service and interest cost................    $ 2        $ 2
Effect on the postretirement benefit obligation.............     30         26

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

 

                                                                DECEMBER 31,
                                            -----------------------------------------------------
                                                      2002                        2003
                                            -------------------------   -------------------------
                                            PENSION    POSTRETIREMENT   PENSION    POSTRETIREMENT
                                            BENEFITS      BENEFITS      BENEFITS      BENEFITS
                                            --------   --------------   --------   --------------
Domestic equity securities................     55%           35%           60%           41%
International equity securities...........     12             8            15             9
Debt securities...........................     29            54            22            48
Real estate...............................      4            --             3            --
Cash......................................     --             3            --             2
                                              ---           ---           ---           ---
  Total...................................    100%          100%          100%          100%
                                              ===           ===           ===           ===

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

As part of the investment strategy discussed above, the Company has adopted and maintains the following weighted average allocation targets for its benefit plans:

 

                                                              PENSION    POSTRETIREMENT
                                                              BENEFITS      BENEFITS
                                                              --------   --------------
Domestic equity securities..................................  50-60%       28-38%
International equity securities.............................  10-20%        5-15%
Debt securities.............................................  20-30%       52-62%
Real estate.................................................   0-5%          --
Cash........................................................   0-2%         0-2%

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

Equity securities for the pension plan include CenterPoint Energy common stock in the amounts of $38 million (4.7% of total pension plan assets) and $44 million (3.7% of total pension plan assets) and as of December 31, 2002 and 2003, respectively.

The Company expects to contribute $38 million to its postretirement benefits plan in 2004. Contributions to the pension plan are not required or expected in 2004.

36

In addition to the non-contributory pension plans discussed above, the Company maintains a non-qualified benefit restoration plan which allows participants to retain the benefits to which they would have been entitled under the Company's non-contributory pension plan except for the federally mandated limits on these benefits or on the level of compensation on which these benefits may be calculated. The expense associated with this non-qualified plan was $25 million, $9 million and $8 million in 2001, 2002 and 2003, respectively. Included in the net benefit cost in 2001 and 2002 is $17 million and $3 million, respectively, of expense related to Reliant Resources' participants, which is reflected in discontinued operations in the Statements of Consolidated Operations. The accrued benefit liability for the non-qualified pension plan was $83 million and $75 million at December 31, 2002 and 2003, respectively. In addition, these accrued benefit liabilities include the recognition of minimum liability adjustments of $23 million as of December 31, 2002 and $15 million as of December 31, 2003, which are reported as a component of other comprehensive income, net of income tax effects.

The following table displays the Company's plans with accumulated benefit obligations in excess of plan assets:

 

                                                                DECEMBER 31,
                              ---------------------------------------------------------------------------------
                                               2002                                      2003
                              ---------------------------------------   ---------------------------------------
                              PENSION    RESTORATION   POSTRETIREMENT   PENSION    RESTORATION   POSTRETIREMENT
                              BENEFITS    BENEFITS        BENEFITS      BENEFITS    BENEFITS        BENEFITS
                              --------   -----------   --------------   --------   -----------   --------------
                                                                (IN MILLIONS)
Accumulated benefit
  obligation................   $1,446        $83            $479         $1,589        $75            $518
Projected benefit
  obligation................    1,550         86             479          1,692         77             518
Plan assets.................    1,054         --             131          1,194         --             150

(12) COMMITMENTS AND CONTINGENCIES

(a) COMMITMENTS

Environmental Capital Commitments. CenterPoint Energy anticipates investing up to $131 million in capital and other special project expenditures between 2004 and 2008 for environmental compliance. CenterPoint Energy anticipates expenditures to be as follows (in millions):

 

2004........................................................   $ 42
2005........................................................     32
2006........................................................     43
2007........................................................     14
2008(1).....................................................     --
                                                               ----
  Total.....................................................   $131
                                                               ====


(1) NOx control estimates for 2008 have not been finalized.

Fuel and Purchased Power. Fuel commitments include several long-term coal, lignite and natural gas contracts related to Texas power generation operations and 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, 2003 as these contracts meet the SFAS No. 133 exception to be classified as "normal purchases contracts" or do not meet the definition of a derivative. Minimum payment obligations for coal and transportation agreements and lignite mining and lease agreements that extend through 2012 are approximately $309 million in 2004, $251 million in 2005, $256 million in 2006, $248 million in 2007 and $162 million in 2008. Minimum payment obligations for natural gas supply contracts are approximately $1 billion in 2004, $565 million in 2005, $344 million in 2006, $171 million in 2007 and $24 million in 2008. Purchase commitments related to purchased power are not material to CenterPoint Energy's operations.

37

(b) LEASE COMMITMENTS

The following table sets forth information concerning the Company's obligations under non-cancelable long-term operating leases at December 31, 2003, which primarily consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions):

 

2004........................................................   $ 42
2005........................................................     27
2006........................................................     24
2007........................................................     20
2008........................................................     17
2009 and beyond.............................................     56
                                                               ----
  Total.....................................................   $186
                                                               ====

Total lease expense for all operating leases was $45 million, $47 million and $46 million during 2001, 2002 and 2003, respectively.

(c) LEGAL, ENVIRONMENTAL AND OTHER REGULATORY MATTERS

Legal Matters

Reliant Resources 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 Reliant Energy and Reliant Resources, the Company and its subsidiaries are entitled to be indemnified by Reliant Resources 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, Reliant Resources 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, but most of the lawsuits remain in early procedural stages. Our former subsidiary, Reliant Resources, 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. Reliant Resources, 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, CenterPoint Houston or their predecessor, Reliant Energy, have also been named in approximately 25 of these lawsuits, which were instituted in 2002 and 2003 and are pending in state courts in San Diego, San Francisco and Los Angeles Counties and in federal district courts in San Francisco, San Diego, Los Angeles and Nevada. However, neither the Company nor Reliant Energy was a participant 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 the remaining cases.

Other Class Action Lawsuits. Fifteen class action lawsuits filed in May, June and July 2002 on behalf of purchasers of securities of Reliant Resources and/or Reliant Energy have been consolidated in federal district

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court in Houston. Reliant Resources and certain of its former and current executive officers are named as defendants. Reliant Energy is also named as a defendant in seven of the lawsuits. Two of the lawsuits also name as defendants the underwriters of the initial public offering of Reliant Resources common stock in May 2001 (Reliant Resources Offering). One lawsuit names Reliant Resources' and Reliant Energy's independent auditors as a defendant. The consolidated amended complaint seeks monetary relief purportedly on behalf of purchasers of common stock of Reliant Energy or Reliant Resources during certain time periods ranging from February 2000 to May 2002, including purchasers of common stock that can be traced to the Reliant Resources 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 Reliant Resources Offering remain.

In February 2003, a lawsuit was filed by three individuals in federal district court in Chicago against CenterPoint Energy and certain former and current officers of Reliant Resources 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 inflate artificially 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, but granted the plaintiffs leave to amend their complaint.

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. Reliant Energy and its directors are named as defendants in all of the lawsuits. Two of the lawsuits have been dismissed without prejudice. The remaining 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. 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 complaints seek monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held Reliant Energy or Reliant Resources securities, as well as equitable relief in the form of restitution. In January 2004 the trial judge dismissed the complaints against a number of defendants, but allowed the case to proceed against members of the Reliant Energy benefits committee.

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 sets forth claims for breach of fiduciary duty, waste of corporate assets, abuse of control and gross mismanagement. Specifically, the shareholder plaintiff alleges that the defendants caused the Company to overstate its revenues through so-called "round trip" transactions. The plaintiff also alleges breach of fiduciary duty in connection with the spin-off of Reliant Resources and the Reliant Resources Offering. The complaint seeks 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. 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'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 latter 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.

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 any of the plaintiffs.

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Other Legal Matters

Texas Antitrust Action. In July 2003, Texas Commercial Energy filed a lawsuit against Reliant Energy, Reliant Resources, Reliant Electric Solutions, LLC, several other Reliant Resources subsidiaries and several other participants in the ERCOT power market in federal court in Corpus Christi, Texas. The plaintiff, a retail electricity provider in the Texas market served by ERCOT, alleges 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 seeks damages in excess of $500 million, exemplary damages, treble damages, interest, costs of suit and attorneys' fees. In February 2004, this complaint was amended to add the Company and CenterPoint Houston, as successors to Reliant Energy, and Texas Genco, LP as defendants. The plaintiff's principal allegations have previously been investigated by the Texas Utility Commission and found to be without merit. The Company also believes the plaintiff's allegations are without merit and will seek their dismissal.

Municipal Franchise Fee Lawsuits. In February 1996, the cities of Wharton, Galveston and Pasadena (Three Cities) filed suit, 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 of the original claimant cities (but not the class of cities), the trial court decertified the class and reduced the damages awarded by the jury to $1.7 million, including interest, plus an award of $13.7 million in legal fees. Despite other jury findings for the plaintiffs, the trial court's judgment was based on the jury's finding in favor of Reliant Energy on the affirmative defense of laches, a defense similar to a statute of limitations defense, due to the original claimant cities having unreasonably delayed bringing their claims during the 43 years since the alleged wrongs began. 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 found that the jury's finding of laches barred all of the Three Cities' claims and that the Three Cities were not entitled to recovery of any attorneys' fees. The Three Cities filed a petition for review at the Texas Supreme Court, which declined to hear the case, although the time period for the Three Cities to file a motion for rehearing has not yet expired. The extent to which issues in the Three Cities case may affect the claims of the other cities served by CenterPoint Houston cannot be assessed until judgments are final and no longer subject to appeal.

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a suit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs, and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs' alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the Btu content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a class of royalty owners, in which they assert their claims that the defendants have engaged

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in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees.

Gas Cost Recovery Litigation. In October 2002, a suit was filed in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company, and others alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act. The plaintiffs seek class certification, but no class has been certified. The plaintiffs allege that defendants inflated the prices charged to certain consumers of natural gas. In February 2003, a similar suit was filed against CERC in state court in Caddo Parish, Louisiana purportedly on behalf of a class of residential or business customers in Louisiana who allegedly have been overcharged for gas or gas service provided by CERC. In February 2004, another suit was filed against CERC in Calcasieu Parish, Louisiana, seeking to recover alleged overcharges for gas or gas services allegedly provided by Entex without advance approval by the LPSC. The plaintiffs in these cases seek injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages and civil penalties. In these cases, the Company, CERC and Entex Gas Marketing Company deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been in accordance with what is permitted by state regulatory authorities.

Environmental Matters

Clean Air Standards. The Texas electric restructuring law and regulations adopted by the Texas Commission on Environmental Quality (TCEQ) in 2001 require substantial reductions in emission of oxides of nitrogen (NOx) from electric generating units. The Company is currently installing cost-effective controls at its generating plants to comply with these requirements. Through December 31, 2003, the Company has invested $664 million for NOx emission control, and plans to make expenditures of up to approximately $131 million during the years 2004 through 2007. Further revisions to these NOx standards may result from the TCEQ's future rules, expected by 2007, implementing more stringent federal eight-hour ozone standards. The Texas electric restructuring law provides for stranded cost recovery for expenditures incurred before May 1, 2003 to achieve the NOx reduction requirements. Incurred costs include costs for which contractual obligations have been made. The Texas Utility Commission has determined that the Company's emission control plan is the most cost-effective option for achieving compliance with applicable air quality standards for the Company's generating facilities and the final amount for recovery will be determined in the 2004 True-Up Proceeding.

Hydrocarbon Contamination. CERC Corp. and certain of its subsidiaries are among some of the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits allege that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination is alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the "Sligo Facility," which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating gasoline and hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.

Beginning about 1985, the predecessors of certain CERC Corp. defendants engaged in a voluntary remediation of any subsurface contamination of the groundwater below the property they owned or leased. This work has been done in conjunction with and under the direction of the Louisiana Department of Environmental Quality. The plaintiffs seek monetary damages for alleged damage to the aquifer underlying their property, unspecified alleged personal injuries, alleged fear of cancer, alleged property damage or diminution of value of their property, and, in addition, seek damages for trespass, punitive, and exemplary damages. The quantity of monetary damages sought is unspecified. The Company is unable to estimate the monetary damages, if any, that the plaintiffs may be awarded in these matters.

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, remediation has been completed on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC's Minnesota service territory, two of

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which CERC believes were neither owned nor operated by CERC, and for which CERC believes it has no liability.

At December 31, 2003, CERC had accrued $19 million for remediation of certain Minnesota sites. At December 31, 2003, the estimated range of possible remediation costs for these sites was $8 million to $44 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. CERC has collected or accrued $12.5 million as of December 31, 2003 to be used for environmental remediation.

CERC has received notices from the United States Environmental Protection Agency and others regarding its status as a PRP for other 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. Based on current information, the Company has not been able to quantify a range of environmental expenditures for such sites.

Mercury Contamination. The Company's pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. This type of contamination has been found by the Company at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs cannot be known at this time, based on experience by the Company and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company's financial condition, results of operations or cash flows.

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named as a defendant in litigation related to such sites and in recent years has been named, along with numerous others, as a defendant in several lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos while working at sites along the Texas Gulf Coast. Most of these claimants have been workers who participated in construction of various industrial facilities, including power plants, and some of the claimants have worked at locations owned by the Company. The Company anticipates that additional claims like those received may be asserted in the future and intends to continue vigorously contesting claims which it does not consider to have merit. Although their ultimate outcome cannot be predicted at this time, the Company does not believe, based on its experience to date, that these matters, either individually or in the aggregate, will have a material adverse effect on the Company's financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, 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.

(d) 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.

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Pursuant to the Price Anderson Act, the maximum liability to the public of owners of nuclear power plants was $10.6 billion as of December 31, 2003. Owners are required under the Price Anderson Act to insure their liability for nuclear incidents and protective evacuations. Texas Genco and the other owners of the South Texas Project 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 incident per year. In addition, the security procedures at this facility have been enhanced to provide additional protection against terrorist attacks.

There can be no assurance that all potential losses or liabilities 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 the Company's financial condition, results of operations and cash flows.

(e) NUCLEAR DECOMMISSIONING

CenterPoint Houston contributed $14.8 million in 2001 to trusts established to fund Texas Genco's share of the decommissioning costs for the South Texas Project. CenterPoint Houston contributed $2.9 million in both 2002 and 2003 to these trusts. There are various investment restrictions imposed upon Texas Genco by the Texas Utility Commission and the United States Nuclear Regulatory Commission (NRC) relating to Texas Genco's nuclear decommissioning trusts. Texas Genco and CenterPoint Energy 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 $189 million as of December 31, 2003, of which approximately 37% were fixed-rate debt securities and the remaining 63% were equity securities. For a discussion of the accounting treatment for the securities held in the nuclear decommissioning trust, see Note 2(k). In July 1999, an outside consultant estimated Texas Genco's portion of decommissioning costs to be approximately $363 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 have not been recovered as of January 1, 2002, will continue to be subject to cost-of-service rate regulation and will be included in a charge to transmission and distribution customers. For information regarding the effect of the business separation plan on funding of the nuclear decommissioning trust fund, see Note 4(c).

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End of Filing


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