CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-Q, Received: 04/30/2008 08:02:12)
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q
(Mark One)
     
þ   QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
FOR THE QUARTERLY PERIOD ENDED MARCH 31, 2008
OR
     
o   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
(State or other jurisdiction of incorporation or organization)
  74-0694415
(I.R.S. Employer Identification No.)
     
1111 Louisiana
Houston, Texas 77002
  (713) 207-1111
(Address and zip code of principal executive offices)   (Registrant’s telephone number, including area code )
 
     Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o
     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o
        (Do not check if a smaller reporting company)    
     Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ
     As of March 31, 2008, CenterPoint Energy, Inc. had 328,265,076 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, 2008
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  Articles of Amendment to Amended and Restated Articles of Incorporation
  Computation of Ratios of Earnings to Fixed Charges
  Certification of David M. McClanahan Pursuant to Rule 13a-14(a)/15d-14(a)
  Certification of Gary L. Whitlock Pursuant to Rule 13a-14(a)/15d-14(a)
  Certification of David M. McClanahan Pursuant to Section 1350
  Certification of Gary L. Whitlock Pursuant to Section 1350
  Risk Factors From the Form 10-K


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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION
     From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words “anticipate,” “believe,” “continue,” “could,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “objective,” “plan,” “potential,” “predict,” “projection,” “should,” “will,” or other similar words.
     We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.
     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 resolution of the true-up proceedings, including, in particular, the results of appeals to the courts regarding rulings obtained to date;
 
    state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change, and changes in or application of laws or regulations applicable to the various aspects of our business;
 
    timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;
 
    cost overruns on major capital projects that cannot be recouped in prices;
 
    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;
 
    the timing and extent of changes in the supply of natural gas;
 
    the timing and extent of changes in natural gas basis differentials;
 
    weather variations and other natural phenomena;
 
    changes in interest rates or rates of inflation;
 
    commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;
 
    actions by rating agencies;
 
    effectiveness of our risk management activities;
 
    inability of various counterparties to meet their obligations to us;
 
    non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (RRI);
 
    the ability of RRI and its subsidiaries to satisfy their other obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

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    the outcome of litigation brought by or against us;
 
    our ability to control costs;
 
    the investment performance of our employee benefit plans;
 
    our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us;
 
    acquisition and merger activities involving us or our competitors; and
 
    other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2007, which is incorporated herein by reference, and other reports we file from time to time 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.

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PART I. FINANCIAL INFORMATION
Item 1. FINANCIAL STATEMENTS
CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED INCOME
(Millions of Dollars, Except Per Share Amounts)
(Unaudited)
                 
    Three Months Ended  
    March 31,  
    2007     2008  
Revenues
  $ 3,106     $ 3,363  
 
           
 
               
Expenses:
               
Natural gas
    2,150       2,393  
Operation and maintenance
    352       365  
Depreciation and amortization
    145       158  
Taxes other than income taxes
    106       111  
 
           
Total
    2,753       3,027  
 
           
Operating Income
    353       336  
 
           
 
               
Other Income (Expense):
               
Loss on Time Warner investment
    (44 )     (54 )
Gain on indexed debt securities
    41       50  
Interest and other finance charges
    (123 )     (115 )
Interest on transition bonds
    (31 )     (33 )
Other, net
    6       13  
 
           
Total
    (151 )     (139 )
 
           
 
               
Income Before Income Taxes
    202       197  
Income tax expense
    (72 )     (74 )
 
           
Net Income
  $ 130     $ 123  
 
           
 
               
Basic Earnings Per Share
  $ 0.41     $ 0.38  
 
           
 
               
Diluted Earnings Per Share
  $ 0.38     $ 0.36  
 
           
See Notes to the Company’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS
(Millions of Dollars)
(Unaudited)
ASSETS
                 
    December 31,     March 31,  
    2007     2008  
Current Assets:
               
Cash and cash equivalents
  $ 129     $ 70  
Investment in Time Warner common stock
    357       303  
Accounts receivable, net
    910       1,097  
Accrued unbilled revenues
    558       455  
Natural gas inventory
    395       65  
Materials and supplies
    95       98  
Non-trading derivative assets
    38       59  
Prepaid expenses and other current assets
    306       204  
 
           
Total current assets
    2,788       2,351  
 
           
 
               
Property, Plant and Equipment:
               
Property, plant and equipment
    13,250       13,332  
Less accumulated depreciation and amortization
    3,510       3,530  
 
           
Property, plant and equipment, net
    9,740       9,802  
 
           
 
               
Other Assets:
               
Goodwill
    1,696       1,696  
Regulatory assets
    2,993       2,907  
Non-trading derivative assets
    11       22  
Notes receivable from unconsolidated affiliates
    148       150  
Other
    496       607  
 
           
Total other assets
    5,344       5,382  
 
           
 
               
Total Assets
  $ 17,872     $ 17,535  
 
           
See Notes to the Company’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)
(Millions of Dollars)
(Unaudited)
LIABILITIES AND SHAREHOLDERS’ EQUITY
                 
    December 31,     March 31,  
    2007     2008  
Current Liabilities:
               
Short-term borrowings
  $ 232     $ 200  
Current portion of transition bond long-term debt
    159       186  
Current portion of other long-term debt
    1,156       724  
Indexed debt securities derivative
    261       211  
Accounts payable
    726       779  
Taxes accrued
    316       269  
Interest accrued
    170       145  
Non-trading derivative liabilities
    61       33  
Accumulated deferred income taxes, net
    350       367  
Other
    360       370  
 
           
Total current liabilities
    3,791       3,284  
 
           
 
               
Other Liabilities:
               
Accumulated deferred income taxes, net
    2,235       2,229  
Unamortized investment tax credits
    31       29  
Non-trading derivative liabilities
    14       4  
Benefit obligations
    499       493  
Regulatory liabilities
    828       795  
Other
    300       275  
 
           
Total other liabilities
    3,907       3,825  
 
           
 
               
Long-term Debt:
               
Transition bonds
    2,101       2,485  
Other
    6,263       6,061  
 
           
Total long-term debt
    8,364       8,546  
 
           
 
               
Commitments and Contingencies (Note 10)
               
 
               
Shareholders’ Equity:
               
Common stock (322,718,785 shares and 328,265,076 shares outstanding at December 31, 2007 and March 31, 2008, respectively)
    3       3  
Additional paid-in capital
    3,023       3,041  
Accumulated deficit
    (1,172 )     (1,109 )
Accumulated other comprehensive loss
    (44 )     (55 )
 
           
Total shareholders’ equity
    1,810       1,880  
 
           
 
               
Total Liabilities and Shareholders’ Equity
  $ 17,872     $ 17,535  
 
           
See Notes to the Company’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS
(Millions of Dollars)
(Unaudited)
                 
    Three Months Ended March 31,  
    2007     2008  
Cash Flows from Operating Activities:
               
Net income
  $ 130     $ 123  
Adjustments to reconcile net income to net cash provided by operating activities:
               
Depreciation and amortization
    145       158  
Amortization of deferred financing costs
    19       7  
Deferred income taxes
    (13 )     27  
Unrealized loss on Time Warner investment
    44       54  
Unrealized gain on indexed debt securities
    (41 )     (50 )
Changes in other assets and liabilities:
               
Accounts receivable and unbilled revenues, net
    16       (84 )
Inventory
    217       327  
Accounts payable
    (222 )     56  
Fuel cost over recovery
    23       29  
Non-trading derivatives, net
    18       28  
Margin deposits, net
    52       29  
Interest and taxes accrued
    (65 )     (72 )
Net regulatory assets and liabilities
    22       14  
Other current assets
    25       34  
Other current liabilities
    (85 )     (63 )
Other assets
    (4 )     (15 )
Other liabilities
    (34 )     (47 )
Other, net
    17       12  
 
           
Net cash provided by operating activities
    264       567  
 
           
 
               
Cash Flows from Investing Activities:
               
Capital expenditures
    (399 )     (187 )
Decrease (increase) in restricted cash of transition bond companies
    5       (13 )
Increase in notes receivable from unconsolidated affiliates
          (2 )
Investment in unconsolidated affiliates
          (105 )
Other, net
    (9 )     (5 )
 
           
Net cash used in investing activities
    (403 )     (312 )
 
           
 
               
Cash Flows from Financing Activities:
               
Increase (decrease) in short-term borrowings, net
    150       (32 )
Long-term revolving credit facilities, net
          (231 )
Proceeds from commercial paper, net
          35  
Proceeds from long-term debt
    400       488  
Payments of long-term debt
    (434 )     (515 )
Debt issuance costs
    (6 )      
Payment of common stock dividends
    (54 )     (60 )
Proceeds from issuance of common stock, net
    13       1  
Other, net
    3        
 
           
Net cash provided by (used in) financing activities
    72       (314 )
 
           
 
Net Decrease in Cash and Cash Equivalents
    (67 )     (59 )
Cash and Cash Equivalents at Beginning of Period
    127       129  
 
           
Cash and Cash Equivalents at End of Period
  $ 60     $ 70  
 
           
 
               
Supplemental Disclosure of Cash Flow Information:
               
Cash Payments:
               
Interest, net of capitalized interest
  $ 177     $ 173  
Income taxes, net
    34       39  
See Notes to the Company’s Interim Condensed Consolidated Financial Statements

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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS
(1) Background and Basis of Presentation
      General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the Company). The Interim Condensed 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, 2007 (CenterPoint Energy Form 10-K).
      Background. CenterPoint Energy, Inc. is a public utility holding company. The Company’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of March 31, 2008, 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 and operates natural gas distribution systems in six states. Subsidiaries of CERC own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.
      Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, 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 Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in the Company’s Condensed 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.
     For a description of the Company’s reportable business segments, reference is made to Note 13.
(2) New Accounting Pronouncements
     In April 2007, the Financial Accounting Standards Board (FASB) issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39,” (FIN 39-1) which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. The Company adopted FIN 39-1 effective January 1, 2008 and began netting the cash collateral receivables and payables and also its derivative assets and liabilities with the same counterparty subject to master netting agreements.
     In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting

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standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.
     In December 2007, the FASB issued SFAS No. 141 (Revised 2007), Business Combinations” (SFAS No. 141R) . SFAS No. 141R will significantly change the accounting for business combinations. Under SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions. SFAS No. 141R also includes a substantial number of new disclosure requirements and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. As the provisions of SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until applicable transactions occur.
     In December 2007, the FASB issued SFAS No. 160, Noncontrolling Interests in Consolidated Financial Statements — An Amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The Company will adopt SFAS No. 160 as of January 1, 2009. The Company expects that the adoption of SFAS No. 160 will not have a material impact on its financial position, results of operations or cash flows.
     Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which requires additional disclosures about the Company’s financial assets and liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. As defined in SFAS No. 157, fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date. Where available, fair value is based on observable market prices or parameters or derived from such prices or parameters. Where observable prices or inputs are not available, valuation models are applied. These valuation techniques involve some level of management estimation and judgment, the degree of which is dependent on the price transparency for the instruments or market and the instruments’ complexity for disclosure purposes. Beginning in January 2008, assets and liabilities recorded at fair value in the Condensed Consolidated Balance Sheet are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows: 
Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets. 
Level 2:  Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets.
Level 3: Inputs are unobservable inputs for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset. Generally, assets and liabilities carried at fair value and included in this category are financial derivatives.
     The following table presents information about the Company’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of March 31, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

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    Quoted Prices in     Significant Other       Significant                
    Active Markets     Observable      Unobservable              Balance   
    for Identical Assets     Inputs     Inputs     Netting      as of  
    (Level 1)     (Level 2)     (Level 3)     Adjustments (1)     March 31, 2008  
                    (in millions)                  
Assets
                                       
Corporate equities
  $ 305     $     $     $     $ 305  
Investments
    74                   (1 )     73  
Derivative assets
    1       103       4       (27 )     81  
 
                             
Total assets
  $ 380     $ 103     $ 4     $ (28 )   $ 459  
 
                             
 
                                       
Liabilities
                                       
Indexed debt securities derivative
  $     $ 211     $     $     $ 211  
Derivative liabilities
    3       60       2       (28 )     37  
 
                             
Total liabilities
  $ 3     $ 271     $ 2     $ (28 )   $ 248  
 
                             
 
(1)   Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions and also cash collateral held or placed with the same counterparties.
     The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the three months ended March 31, 2008:
         
    Fair Value Measurements  
     Using Significant  
    Unobservable Inputs  
    (Level 3)  
    Derivatives, net  
    (in millions)  
Beginning balance as of January 1, 2008
  $ (3 )
Total gains or losses (realized and unrealized):
       
Included in earnings
    6  
Included in other comprehensive loss
     
Net transfers into level 3
     
Purchases, sales, other settlements, net
    (1 )
 
     
Ending balance as of March 31, 2008
  $ 2  
 
     
 
       
The amount of total gains or losses for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date
  $ 1  
 
     
(3) Employee Benefit Plans
     The Company’s net periodic cost includes the following components relating to pension and postretirement benefits:
                                 
    Three Months Ended March 31,  
    2007     2008  
    Pension     Postretirement     Pension     Postretirement  
    Benefits     Benefits     Benefits     Benefits  
            (in millions)          
Service cost
  $ 9     $     $ 8     $  
Interest cost
    25       7       25       7  
Expected return on plan assets
    (37 )     (3 )     (37 )     (3 )
Amortization of prior service cost
    (2 )     1       (2 )     1  
Amortization of net loss
    9             6        
Amortization of transition obligation
          2             2  
 
                       
Net periodic cost
  $ 4     $ 7     $     $ 7  
 
                       

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     The Company expects to contribute approximately $8 million to its pension plans in 2008, of which $2 million had been contributed as of March 31, 2008.
     The Company expects to contribute approximately $21 million to its postretirement benefits plan in 2008, of which $6 million had been contributed as of March 31, 2008.
(4) Regulatory Matters
(a) Recovery of True-Up Balance
     In March 2004, CenterPoint Houston filed its true-up application with the Public Utility Commission of Texas (Texas Utility Commission), requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and in certain other respects.
     CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:
    reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;
 
    reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers; and
 
    affirmed the True-Up Order in all other respects.
     The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.
     CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:
    reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;
 
    reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to Reliant Energy, Inc. (RRI);
 
    ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and
 
    affirmed the district court’s judgment in all other respects.
     CenterPoint Houston and two other parties filed motions for rehearing with the court of appeals. On April 17, 2008, the court of appeals denied those motions and reissued substantially the same opinion as it had rendered in December 2007.  CenterPoint Houston now plans to seek further review by the Texas Supreme Court. Although the Company and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its further appeal, the Company can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.
     To reflect the impact of the True-Up Order, in 2004 and 2005 the Company recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in the Company’s consolidated financial statements. However, if the court of appeals

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decision is not reversed or modified as a result of further review by the Texas Supreme Court, the Company anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $130 million to $350 million plus interest subsequent to December 31, 2007.
     In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, the Company received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT. 
     If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require the Company to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on the Company’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. However, the Company and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.
     The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through the issuance of transition bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.
     In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to a weighted average cost of capital of 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006.
     Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC

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amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston disagree with the district court’s conclusions and, in May 2006, appealed the judgment to the Texas Third Court of Appeals, and if required, CenterPoint Houston plans to seek further review from the Texas Supreme Court. All briefs in the appeal have been filed, and oral arguments were held in December 2006. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on the Company’s or CenterPoint Houston’s financial condition, results of operations or cash flows.
     During the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized approximately $11 million and $5 million, respectively, in operating income from the CTC, which was terminated in February 2008 when the transition bonds described below were issued. Additionally, during the three months ended March 31, 2007 and 2008, CenterPoint Houston recognized approximately $3 million and $2 million, respectively, of the allowed equity return not previously recorded.
     During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.
     As of March 31, 2008, the Company had not recorded an allowed equity return of $218 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates.
(b) Rate Cases
      Texas.   In March 2008, CERC Corp.’s natural gas distribution business (Gas Operations) filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston.  The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory.  The effect of the requested rate changes will be to increase the Texas Coast service territory’s revenues by approximately $7 million per year.
      Minnesota.   In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision. That court heard oral arguments on the appeal in February 2008 and is expected to render its decision within 90 days of that hearing. No prediction can be made as to the ultimate outcome of this matter.

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(5) Derivative Instruments
     The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows.
 (a)  Non-Trading Activities
      Cash Flow Hedges.   The Company has entered into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133). The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting the Company’s wholesale and retail customer obligations. During each of the three months ended March 31, 2007 and 2008, hedge ineffectiveness resulted in a loss of less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of March 31, 2008, the Company expects $2 million ($1 million after-tax) in accumulated other comprehensive income to be reclassified as a decrease in Natural gas expense during the next twelve months.
     The length of time the Company is hedging its exposure to the variability in future cash flows using derivative instruments that have been designated and have qualified as cash flow hedging instruments is less than one year. The Company’s policy is not to exceed ten years in hedging its exposure.
      Hedging of Future Debt Issuances. As of March 31, 2008, the Company had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008, as changes in the U.S treasury rate would cause variability in the Company’s forecasted interest payments. These treasury rate locks qualify as cash flow hedges under SFAS No. 133. Accordingly, unrealized gains and losses associated with the treasury rate locks are recorded as a component of accumulated other comprehensive loss. The realized gain or loss recognized upon settlement of the treasury rate locks will be initially recorded as a component of accumulated other comprehensive loss and will be recognized as a component of interest expense over the life of the related financing arrangement. During the three months ended March 31, 2008, the Company recognized a $14 million loss ($9 million after-tax) for these treasury rate locks in other comprehensive loss. Ineffectiveness for the treasury rate locks was not material during the three months ended March 31, 2008.
      Other Derivative Instruments.   The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended March 31, 2007 and 2008, the Company recognized unrealized net losses of $8 million and $22 million, respectively. During the three months ended March 31, 2007, the unrealized net losses are included in the Statements of Consolidated Income under the “Expenses” caption “Natural Gas.” During the three months ended March 31, 2008, unrealized net losses of $20 million are included in the Statements of Consolidated Income under the “Revenues” caption and unrealized net losses of $2 million are included in the Statements of Consolidated Income under the “Expenses” caption “Natural Gas.”
      Weather Derivatives. The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in certain of its Gas Operations jurisdictions. The remaining Gas Operations jurisdictions,

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Minnesota, Mississippi and Texas, do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations.
     In 2007, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of $18 million. During the three months ended March 31, 2008, the Company recognized an $11 million loss ($7 million after-tax) related to these swaps. This was offset in part by increased revenues due to colder than normal weather.
      Embedded Derivative.   The Company’s 3.75% convertible senior notes 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 component was not material at issuance or at March 31, 2008.
(6) Goodwill
     Goodwill by reportable business segment as of both December 31, 2007 and March 31, 2008 is as follows (in millions):
         
Natural Gas Distribution
  $ 746  
Interstate Pipelines
    579  
Competitive Natural Gas Sales and Services
    335  
Field Services
    25  
Other Operations
    11  
 
     
Total
  $ 1,696  
 
     
(7) Comprehensive Income
     The following table summarizes the components of total comprehensive income (net of tax):
                 
    For the Three Months Ended  
    March 31,  
    2007     2008  
    (in millions)  
Net income
  $ 130     $ 123  
 
           
Other comprehensive income (loss):
               
SFAS No. 158 adjustment (net of tax of $1 and $1)
    2       2  
Net deferred loss from cash flow hedges (net of tax of $5)
          (9 )
Reclassification of deferred gain from cash flow hedges realized in net income (net of tax of $14 and $2)
    (22 )     (4 )
 
           
Other comprehensive loss
    (20 )     (11 )
 
           
Comprehensive income
  $ 110     $ 112  
 
           
     The following table summarizes the components of accumulated other comprehensive loss:
                 
    December 31,     March 31,  
    2007     2008  
    (in millions)  
SFAS No. 158 adjustment
  $ (48 )   $ (46 )
Net deferred gain (loss) from cash flow hedges
    4       (9 )
 
           
Total accumulated other comprehensive loss
  $ (44 )   $ (55 )
 
           
(8) 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, 2007, 322,718,951 shares of CenterPoint Energy common stock were issued and 322,718,785 shares of CenterPoint Energy common stock were outstanding. At March 31, 2008, 328,265,242 shares of CenterPoint Energy common

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stock were issued and 328,265,076 shares of CenterPoint Energy common stock were outstanding. See Note 9(b) describing the conversion of the 3.75% Convertible Senior Notes in the first quarter of 2008. Outstanding common shares exclude 166 treasury shares at both December 31, 2007 and March 31, 2008.
(9) Short-term Borrowings and Long-term Debt
(a) Short-term Borrowings
     In October 2007, CERC amended its receivables facility and extended the termination date to October 28, 2008. The facility size will range from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility was designed to track the seasonal pattern of receivables in CERC’s natural gas businesses. At March 31, 2008, the facility size was $375 million. As of December 31, 2007 and March 31, 2008, $232 million and $200 million, respectively, was advanced for the purchase of receivables under CERC’s receivables facility.
(b) Long-term Debt
      Revolving Credit Facilities. As of March 31, 2008, the Company had no borrowings, approximately $28 million of outstanding letters of credit and no commercial paper outstanding under its $1.2 billion credit facility. As of March 31, 2008, CenterPoint Houston had no borrowings and approximately $4 million of outstanding letters of credit under its $300 million credit facility and CERC Corp. had $100 million of borrowings and $35 million of commercial paper outstanding under its $950 million credit facility. The Company, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of March 31, 2008.
      Transition Bonds.   Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. See Note 4(a) for further discussion.
      Convertible Debt.   On May 19, 2003, the Company issued $575 million aggregate principal amount of convertible senior notes due May 15, 2023 with an interest rate of 3.75%. As of March 31, 2008, holders could convert each of their notes into shares of CenterPoint Energy common stock at a conversion rate of 89.4381 shares of common stock per $1,000 principal amount of notes at any time prior to maturity under the following circumstances: (1) if the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the previous calendar quarter is greater than or equal to 120% or, following May 15, 2008, 110% of the conversion price per share of CenterPoint Energy common stock on such last trading day, (2) if the notes have been called for redemption, (3) during any period in which the credit ratings assigned to the notes by both Moody’s Investors Service, Inc. (Moody’s) and Standard & Poor’s Ratings Services (S&P), a division of The McGraw-Hill Companies, are lower than Ba2 and BB, respectively, or the notes are no longer rated by at least one of these ratings services or their successors, or (4) upon the occurrence of specified corporate transactions, including the distribution to all holders of CenterPoint Energy common stock of certain rights entitling them to purchase shares of CenterPoint Energy common stock at less than the last reported sale price of a share of CenterPoint Energy common stock on the trading day prior to the declaration date of the distribution or the distribution to all holders of CenterPoint Energy common stock of the Company’s assets, debt securities or certain rights to purchase the Company’s securities, which distribution has a per share value exceeding 15% of the last reported sale price of a share of CenterPoint Energy common stock on the trading day immediately preceding the declaration date for such distribution. The notes originally had a conversion rate of 86.3558 shares of common stock per $1,000 principal amount of notes. However, the conversion rate increased to 89.4381 shares at March 31, 2008, in accordance with the terms of the notes, because quarterly common stock dividends declared were in excess of $0.10 per share.
     Holders have the right to require the Company to purchase all or any portion of the notes for cash on May 15, 2008, May 15, 2013 and May 15, 2018 for a purchase price equal to 100% of the principal amount of the notes. The convertible senior notes also have a contingent interest feature requiring contingent interest to be paid to holders of

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notes commencing on or after May 15, 2008, in the event that the average trading price of a note for the applicable five-trading-day period equals or exceeds 120% of the principal amount of the note as of the day immediately preceding the first day of the applicable six-month interest period. For any six-month period, contingent interest will be equal to 0.25% of the average trading price of the note for the applicable five-trading-day period.
     In August 2005, the Company accepted for exchange approximately $572 million aggregate principal amount of its 3.75% convertible senior notes due 2023 (Old Notes) for an equal amount of its new 3.75% convertible senior notes due 2023 (New Notes). As of March 31, 2008, New Notes of approximately $401 million remained outstanding and Old Notes of approximately $1 million remained outstanding. Under the terms of the New Notes, which are substantially similar to the Old Notes, settlement of the principal portion will be made in cash rather than stock.
     During the three months ended March 31, 2008, the Company issued 4.4 million shares of its common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of its 3.75% convertible senior notes. In April 2008, the Company issued 0.25 million shares of its common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of its convertible notes.
     As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior notes are included as current portion of long-term debt in the Consolidated Balance Sheets because the last reported sale price of CenterPoint Energy common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the quarter was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes.
     In April 2008, the Company announced a call for redemption of its 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of the Company’s common stock for the excess value due converting holders. If the Company’s closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of the Company’s April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.
      Purchase of Pollution Control Bonds. In April 2008, the Company purchased $175 million principal amount of pollution control bonds issued on its behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, the Company expects to remarket both series of bonds, at 100% of their principal amounts, in 2008.
(10) Commitments and Contingencies
(a) Natural Gas Supply Commitments
     Natural gas supply commitments include natural gas contracts related to the Company’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in the Company’s Consolidated Balance Sheets as of December 31, 2007 and March 31, 2008 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. Natural gas supply commitments also include natural gas transportation contracts which do not meet the definition of a derivative. As of March 31, 2008, minimum payment obligations for natural gas supply commitments are approximately $532 million for the remaining nine months in 2008, $316 million in 2009, $296 million in 2010, $279 million in 2011, $272 million in 2012 and $1.2 billion after 2012.

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(b) Legal, Environmental and Other Regulatory Matters
Legal Matters
RRI Indemnified Litigation
     The Company, CenterPoint Houston or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between the Company and Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (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. Although the ultimate outcome of these matters cannot be predicted at this time, the Company has not considered it necessary to establish reserves related to this litigation.
      Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in federal court in Nevada and in state court in California, Missouri and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other 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 and attorneys’ fees. The Company’s former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally.
     The Company and/or Reliant Energy have been named in approximately 35 of these lawsuits, which were instituted between 2001 and 2007 and are pending in Nevada state court in Clark County, in Missouri state court in Jackson County and in federal district court in Nevada. However, the Company, CenterPoint Houston and Reliant Energy were not participants in the electricity or natural gas markets in California. The Company and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and the Company believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases.
     To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. Three of the gas complaints were dismissed based on defendants’ claims of the filed rate doctrine, but the Ninth Circuit Court of Appeals reversed those dismissals and remanded the cases back to the district court for further proceedings. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. In October 2006, RRI reached a tentative settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the remaining gas cases in state court in California, the Court of Appeals found that the Company was not a successor to the liabilities of a subsidiary of RRI and ordered the state court to dismiss the Company. The Company was dismissed in April 2008. The other gas cases remain in the early procedural stages.
     In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the three states and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases are pending. Two parties have appealed the courts’ approval of the settlement to the California Court of Appeals. A

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party in the FERC proceedings filed a motion for rehearing of the FERC’s order approving the settlement, which the FERC denied in May 2006. That party has filed for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when the Company was an affiliate of RRI. The terms of the settlement do not require payment by the Company.
      Other Class Action Lawsuits. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by the Company. Two of the lawsuits were dismissed without prejudice. In the remaining lawsuit, the Company and certain former members of its benefits committee are defendants. That lawsuit alleged that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by the Company, in violation of the Employee Retirement Income Security Act of 1974 by permitting the plans to purchase or hold securities issued by the Company when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint sought monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the federal district judge granted a motion for summary judgment filed by the Company and the individual defendants. The plaintiffs appealed the ruling to the Fifth Circuit Court of Appeals (Fifth Circuit), which in April 2008 affirmed the district court’s ruling. The plaintiffs could seek rehearing of that decision by Fifth Circuit and, if that is unsuccessful, further review by the United States Supreme Court. The Company believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time.
Other Legal Matters
      Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a lawsuit 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 October 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff has sought review of that dismissal from the Tenth Circuit Court of Appeals, where the matter remains pending.
     In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative 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 believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. CERC does not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
      Gas Cost Recovery Litigation. In October 2002, a lawsuit was filed on behalf of certain CERC ratepayers in state district court in Wharton County, Texas against the Company, CERC, Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust Act with respect to rates charged to certain consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The

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plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.
     In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against the Company, CERC, EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.
     In June 2007, the Company, CERC, EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has original exclusive jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS were joined as plaintiffs to the Travis County case.
     In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. That complaint remains pending at the APSC.
     In February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by CERC to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish lawsuits have been stayed pending the resolution of the petitions filed with the LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, CERC’s gas purchases were reviewed back to 1971. The review concluded that CERC’s gas costs were “reasonable and prudent,” but CERC agreed to credit to jurisdictional customers approximately $920,000, including interest, related to certain off-system sales. A regulatory liability was established and the Company began refunding that amount to jurisdictional customers in September 2007. A similar review by the LPSC related to the Caddo Parish litigation was resolved without additional payment by CERC.
     The range of relief sought by the plaintiffs in these cases includes injunctive and declaratory relief, restitution for the alleged overcharges, exemplary damages or trebling of actual damages, civil penalties and attorney’s fees. The Company, CERC and their affiliates deny that they have overcharged any of their customers for natural gas and believe that the amounts recovered for purchased gas have been shown in the reviews described above to be in accordance with what is permitted by state and municipal regulatory authorities. The Company and CERC do not expect the outcome of these matters to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
      Storage Facility Litigation. In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by a CERC entity that was the predecessor in interest of CEGT.

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The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT nor its predecessors had condemned those ownership interests. The court rejected CEGT’s contention that the claim should be barred by the statute of limitations, since the suit was filed over 25 years after the facility was constructed. The court also rejected CEGT’s contention that the suit is an impermissible attack on the determinations the FERC and Oklahoma Corporation Commission made regarding the absence of native gas in the lands when the facility was constructed. The summary judgment ruling was only on the issue of liability, though the court did rule that CEGT has the burden of proving that any gas in the Wapanucka formation is gas that has been injected and is not native gas. Further hearings and orders of the court are required to specify the appropriate relief for the plaintiffs. CEGT plans to appeal through the Oklahoma court system any judgment that imposes liability on CEGT in this matter. The Company and CERC do not expect the outcome of this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
  Environmental Matters
      Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.
     At March 31, 2008, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of March 31, 2008, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.
     In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP.
      Mercury Contamination. The Company’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination 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 is not known at this time, based on the Company’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company’s financial condition, results of operations or cash flows.
      Asbestos. Some facilities owned by the Company contain or have contained asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company or its subsidiaries. The Company anticipates that additional claims like those received may

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be asserted in the future. In 2004, the Company sold its generating business, to which most of these claims relate, to Texas Genco LLC, which is now known as NRG Texas LP (NRG). Under the terms of the arrangements regarding separation of the generating business from the Company and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
      Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
  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 regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.
  Guaranties
     Prior to the Company’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the Company, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.
     The potential exposure of CERC under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, the Company and CERC believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, the Company would retain exposure to the counterparty under the guaranty.
(11) Income Taxes
     During the three months ended March 31, 2007 and 2008, the effective tax rate was 36% and 37%, respectively.  The most significant item affecting the comparability of the effective tax rate is the 2008 classification of approximately $4 million of Texas margin tax as an income tax for CenterPoint Houston.

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     The following table summarizes the Company’s liability for uncertain tax positions in accordance with FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” at December 31, 2007 and March 31, 2008 (in millions):
                 
    December 31,   March 31,
    2007   2008
Liability for uncertain tax positions
  $ 82     $ 89  
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate
    10       11  
Interest accrued on uncertain tax positions
    4       5  
(12) Earnings Per Share
     The following table reconciles numerators and denominators of the Company’s basic and diluted earnings per share calculations:
                 
    Three Months Ended March 31,  
    2007     2008  
    (in millions, except share and  
    per share amounts)  
Basic earnings per share calculation:
               
Net income
  $ 130     $ 123  
 
           
Weighted average shares outstanding
    318,060,000       327,279,000  
 
           
 
               
Basic earnings per share:
               
Net income
  $ 0.41     $ 0.38  
 
           
 
               
Diluted earnings per share calculation:
               
Net income
  $ 130     $ 123  
 
           
 
Weighted average shares outstanding
    318,060,000       327,279,000  
Plus: Incremental shares from assumed conversions:
               
Stock options (1)
    1,237,000       869,000  
Restricted stock
    1,328,000       1,127,000  
2.875% convertible senior notes
    1,179,000        
3.75% convertible senior notes
    18,299,000       10,173,000  
 
           
Weighted average shares assuming dilution
    340,103,000       339,448,000  
 
           
 
               
Diluted earnings per share:
               
Net income
  $ 0.38     $ 0.36  
 
           
 
(1)   Options to purchase 3,752,647 and 2,848,340 shares were outstanding for the three months ended March 31, 2007 and 2008, respectively, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.
     Substantially all of the 3.75% contingently convertible senior notes provide for settlement of the principal portion in cash rather than stock. In accordance with EITF Issue No. 04-8, “Accounting Issues related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings Per Share,” the portion of the conversion value of such notes that must be settled in cash rather than stock is excluded from the computation of diluted earnings per share from continuing operations. The Company includes the conversion spread in the calculation of diluted earnings per share when the average market price of the Company’s common stock in the respective reporting period exceeds the conversion price. The conversion price for the 3.75% contingently convertible senior notes at March 31, 2008 was $11.18.
(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

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wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.
     The Company’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Other Operations consists primarily of other corporate operations which support all of the Company’s business operations.
     Long-lived assets include net property, plant and equipment, net goodwill and other intangibles and equity investments in unconsolidated subsidiaries. Intersegment sales are eliminated in consolidation.
     Financial data for business segments and products and services are as follows (in millions):
                                 
    For the Three Months Ended March 31, 2007        
    Revenues from     Net             Total Assets  
    External     Intersegment     Operating     as of December 31,  
    Customers     Revenues     Income (Loss)     2007  
Electric Transmission & Distribution
  $ 406 (1)   $     $ 104     $ 8,358  
Natural Gas Distribution
    1,564       3       129       4,332  
Competitive Natural Gas Sales and Services
    1,047       17       56       1,221  
Interstate Pipelines
    59       31       44       3,007  
Field Services
    28       11       22       669  
Other Operations
    2             (2 )     1,956 (2)
Eliminations
          (62 )           (1,671 )
 
                       
Consolidated
  $ 3,106     $     $ 353     $ 17,872  
 
                       
                                 
    For the Three Months Ended March 31, 2008        
    Revenues from     Net             Total Assets  
    External     Intersegment     Operating     as of March 31,  
    Customers     Revenues     Income (Loss)     2008  
Electric Transmission & Distribution
  $ 409 (1)   $     $ 91     $ 8,221  
Natural Gas Distribution
    1,697       3       121       4,171  
Competitive Natural Gas Sales and Services
    1,109       11       6       1,316  
Interstate Pipelines
    91       42       71       3,087  
Field Services
    54       4       45       724  
Other Operations
    3             2       2,050 (2)
Eliminations
          (60 )           (2,034 )
 
                       
Consolidated
  $ 3,363     $     $ 336     $ 17,535  
 
                       
 
(1)   Sales to subsidiaries of RRI in the three months ended March 31, 2007 and 2008 represented approximately $149 million and $142 million, respectively, of CenterPoint Houston’s transmission and distribution revenues.
 
(2)   Included in total assets of Other Operations as of December 31, 2007 and March 31, 2008 are pension assets of $231 million and $236 million, respectively. Also included in total assets of Other Operations as of December 31, 2007 and March 31, 2008, are pension related regulatory assets of $319 million and $317 million, respectively, resulting from the Company’s adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R)”.

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(14) Subsequent Event
     On April 24, 2008, the Company’s board of directors declared a regular quarterly cash dividend of $0.1825 per share of common stock payable on June 10, 2008, to shareholders of record as of the close of business on May 16, 2008.

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      Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
      The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2007 (2007 Form 10-K ).
EXECUTIVE SUMMARY
Recent Events
Debt Financing Transactions
     In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.
     During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.
     In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.
Transition Bonds
     Pursuant to a financing order issued by the Public Utility Commission of Texas (Texas Utility Commission) in September 2007, in February 2008 a subsidiary of CenterPoint Energy Houston Electric, LLC (CenterPoint Houston) issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the competition transition charge (CTC) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement.
Interstate Pipelines
     In May 2007, CenterPoint Energy Gas Transmission (CEGT), a wholly owned subsidiary of CERC Corp., received Federal Energy Regulatory Commission (FERC) approval for the third phase of its Carthage to Perryville pipeline project, a 172-mile, 42-inch diameter pipeline and related compression facilities for the transportation of gas from Carthage, Texas to CEGT’s Perryville hub in northeast Louisiana, to expand capacity of the pipeline to 1.5 Bcf per day by adding additional compression and operating at higher pressures. In July 2007, CEGT received approval from the Pipeline and Hazardous Materials Administration (PHMSA) to increase the maximum allowable operating pressure.  The PHMSA’s approval contained certain conditions and requirements. In March 2008, CEGT met these conditions and gave notice to PHMSA that it would be increasing the pressure in 30 days. In April 2008, CEGT raised the maximum allowable pressure and concurrently placed the phase three expansion in-service. CEGT has executed contracts for approximately 150 MMcf per day of the 250 MMcf per day phase three expansion. 

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     In September 2007, CEGT initiated an investigation into allegations received from two former employees of the manufacturer of pipe installed in CEGT’s Carthage to Perryville pipeline segment. That pipeline segment was placed in commercial service in May 2007 after satisfactory completion of hydrostatic testing designed to ensure that the pipe and its welds would be structurally sound when placed in service and operated at design pressure. According to the complainants, records relating to radiographic inspections of certain welds made at the fabrication facility had been altered resulting in the possibility that pipe with alleged substandard welds had been installed in the pipeline. In conducting its investigation, among other things, CEGT and its counsel interviewed the complainants and other individuals, including CEGT and contractor personnel, and reviewed documentation related to the manufacture and construction of the pipeline, including radiographic records related to the allegedly deficient welds. CEGT kept appropriate governmental officials informed throughout its investigation and consulted appropriate technical consultants and pre-existing regulatory guidance.  Pursuant to a course of action proposed by CEGT, CEGT excavated and inspected certain welds, and in each case, CEGT found those welds to be structurally sound. CEGT and its counsel have now  formally concluded their investigation, finding no  credible support for the allegation that pipe with substandard welds  may have been installed in the pipeline.  CEGT has informed the relevant government agencies of these conclusions, and has informed those agencies that CEGT does not intend to take any additional action or to alter or modify the pipeline’s operations.
     Effective April 1, 2008, Mississippi River Transmission Corp. signed a 5-year extension of its firm transportation and storage contracts with Laclede Gas Company (Laclede).   In 2007, approximately 10% of Interstate Pipelines operating revenues was attributable to services provided to Laclede.
CONSOLIDATED RESULTS OF OPERATIONS
     All dollar amounts in the tables that follow are in millions, except for per share amounts.
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 3,106     $ 3,363  
Expenses
    2,753       3,027  
 
           
Operating Income
    353       336  
Interest and Other Finance Charges
    (123 )     (115 )
Interest on Transition Bonds
    (31 )     (33 )
Other Income, net
    3       9  
 
           
Income Before Income Taxes
    202       197  
Income Tax Expense
    (72 )     (74 )
 
           
Net Income
  $ 130     $ 123  
 
           
 
               
Basic Earnings Per Share
  $ 0.41     $ 0.38  
 
           
 
               
Diluted Earnings Per Share
  $ 0.38     $ 0.36  
 
           
Three months ended March 31, 2008 compared to three months ended March 31, 2007
     We reported consolidated net income of $123 million ($0.36 per diluted share) for the three months ended March 31, 2008 as compared to $130 million ($0.38 per diluted share) for the same period in 2007. The decrease in net income of $7 million was primarily due to decreased operating income of $50 million in our Competitive Natural Gas Sales and Services business segment, decreased operating income of $14 million in our Electric Transmission & Distribution utility and decreased operating income of $8 million in our Natural Gas Distribution business segment. These decreases in consolidated net income were partially offset by increased operating income of $27 million in our Interstate Pipelines business segment, increased operating income of $23 million in our Field Services business segment, decreased interest expense, excluding interest on transition bonds, of $8 million due to lower amortization of deferred financing costs and increased operating income of $4 million in our Other Operations business segment.
     During the three months ended March 31, 2008 and 2007, the effective tax rate was 37% and 36%, respectively.  The most significant item affecting the comparability of the effective tax rate is the 2008 classification of approximately $4 million of Texas margin tax as an income tax for CenterPoint Houston.

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RESULTS OF OPERATIONS BY BUSINESS SEGMENT
     The following table presents operating income (in millions) for each of our business segments for the three months ended March 31, 2007 and 2008.
                 
    Three Months Ended March 31,  
    2007     2008  
Electric Transmission & Distribution
  $ 104     $ 91  
Natural Gas Distribution
    129       121  
Competitive Natural Gas Sales and Services
    56       6  
Interstate Pipelines
    44       71  
Field Services
    22       45  
Other Operations
    (2 )     2  
 
           
Total Consolidated Operating Income
  $ 353     $ 336  
 
           
Electric Transmission & Distribution
     For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Electric Transmission & Distribution Business,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K.
     The following tables provide summary data of our Electric Transmission & Distribution business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues:
               
Electric transmission and distribution utility
  $ 347     $ 346  
Transition bond companies
    59       63  
 
           
Total revenues
    406       409  
 
           
Expenses:
               
Operation and maintenance, excluding transition bond companies
    154       168  
Depreciation and amortization, excluding transition bond companies
    63       66  
Taxes other than income taxes
    57       53  
Transition bond companies
    28       31  
 
           
Total expenses
    302       318  
 
           
Operating Income
  $ 104     $ 91  
 
           
 
               
Operating Income:
               
Electric transmission and distribution utility
    62       54  
Competition transition charge
    11       5  
Transition bond companies (1)
    31       32  
 
           
Total segment operating income
  $ 104     $ 91  
 
           
 
               
Throughput (in gigawatt-hours (GWh)):
               
Residential
    4,658       4,403  
Total
    16,660       16,570  
 
               
Average number of metered customers:
               
Residential
    1,752,264       1,801,272  
Total
    1,989,744       2,042,460  
 
(1)   Represents the amount necessary to pay interest on the transition bonds.

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Three months ended March 31, 2008 compared to three months ended March 31, 2007
     Our Electric Transmission & Distribution business segment reported operating income of $91 million for the three months ended March 31, 2008, consisting of $54 million for the regulated electric transmission and distribution utility (TDU), $5 million for the CTC and $32 million related to the transition bonds. For the three months ended March 31, 2007, operating income totaled $104 million, consisting of $62 million for the TDU, $11 million for the CTC and $31 million related to the transition bonds. The reduction in operating income from the TDU resulted from reduced usage ($11 million), in part due to milder weather, higher operating expenses ($8 million), and higher net transmission costs ($3 million), partially offset by higher revenues ($7 million) due to customer growth from the addition of over 52,000 new customers and higher revenues from ancillary services ($2 million). Taxes other than income taxes were lower by $4 million primarily as a result of the Texas margin tax being classified as an income tax for reporting purposes in 2008.
Natural Gas Distribution
     For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K.
     The following table provides summary data of our Natural Gas Distribution business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 1,567     $ 1,700  
 
           
Expenses:
               
Natural gas
    1,212       1,333  
Operation and maintenance
    147       156  
Depreciation and amortization
    38       39  
Taxes other than income taxes
    41       51  
 
           
Total expenses
    1,438       1,579  
 
           
Operating Income
  $ 129     $ 121  
 
           
 
               
Throughput (in Bcf):
               
Residential
    86       84  
Commercial and industrial
    81       83  
 
           
Total Throughput
    167       167  
 
           
 
               
Average number of customers:
               
Residential
    2,946,203       2,975,591  
Commercial and industrial
    245,576       250,988  
 
           
Total
    3,191,779       3,226,579  
 
           
Three months ended March 31, 2008 compared to three months ended March 31, 2007
     Our Natural Gas Distribution business segment reported operating income of $121 million for the three months ended March 31, 2008 compared to operating income of $129 million for the three months ended March 31, 2007. Operating margin (revenues less cost of gas) increased $12 million primarily due to increases in gross receipts taxes ($9 million) and recovery of energy-efficiency costs ($3 million), both of which are offset by the related expenses. Other margin increases primarily from new rates ($5 million) and customer growth ($3 million), with the addition of nearly 36,000 customers, was entirely offset by the cost of a winter weather hedge and customer conservation ($11 million). Operation and maintenance expenses increased primarily due to the energy efficiency costs above and higher bad debt expense ($2 million) related to higher revenues.

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Competitive Natural Gas Sales and Services
     For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Business,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K.
     The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput and customer data):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 1,064     $ 1,120  
 
           
Expenses:
               
Natural gas
    998       1,105  
Operation and maintenance
    9       8  
Depreciation and amortization
    ––       1  
Taxes other than income taxes
    1        
 
           
Total expenses
    1,008       1,114  
 
           
Operating Income
  $ 56     $ 6  
 
           
 
               
Throughput (in Bcf):
               
Wholesale – third parties
    94       70  
Wholesale – affiliates
    3       2  
Retail and Pipeline
    58       66  
 
           
Total Throughput
    155       138  
 
           
 
               
Average number of customers:
               
Wholesale
    223       154  
Retail and Pipeline
    6,764       8,338  
 
           
Total
    6,987       8,492  
 
           
Three months ended March 31, 2008 compared to three months ended March 31, 2007
     Our Competitive Natural Gas Sales and Services business segment reported operating income of $6 million for the three months ended March 31, 2008 compared to $56 million for the three months ended March 31, 2007. The decrease in operating income of $50 million was primarily due to higher operating margins (revenues less natural gas costs) in 2007 related to sales of gas from inventory that was written down to the lower of cost or market in prior periods of $28 million in the first quarter of 2007 compared to $4 million in the first quarter of 2008 for a net decrease of $24 million. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The unfavorable mark-to-market accounting for non-trading financial derivatives for the first quarter of 2008 of $22 million versus $8 million for the same period in 2007 accounted for a further net $14 million decrease. The additional decrease in operating income of $12 million in this quarter compared to the same quarter last year was primarily due to a reduction in margin as basis and summer/winter spreads narrowed.
Interstate Pipelines
     For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K.

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     The following table provides summary data of our Interstate Pipelines business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput data):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 90     $ 133  
 
           
Expenses:
               
Natural gas
    4       15  
Operation and maintenance
    27       30  
Depreciation and amortization
    10       12  
Taxes other than income taxes
    5       5  
 
           
Total expenses
    46       62  
 
           
Operating Income
  $ 44     $ 71  
 
           
 
               
Throughput (in Bcf ):
               
Transportation
    294       424  
Three months ended March 31, 2008 compared to three months ended March 31, 2007
     The Interstate Pipeline business segment reported operating income of $71 million for the three months ended March 31, 2008 compared to $44 million for the same period of 2007. The increase in operating income of $27 million was primarily driven by the new Carthage to Perryville pipeline ($19 million), other transportation and ancillary services ($8 million), and lower other tax expense and refunds ($2 million). These favorable variances in operating income were partially offset by a 2007 gain on sale of excess gas associated with storage enhancement projects ($2 million).
Field Services
     For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “ — Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K.
     The following table provides summary data of our Field Services business segment for the three months ended March 31, 2007 and 2008 (in millions, except throughput data):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 39     $ 58  
 
           
Expenses:
               
Natural gas
    (3 )     (2 )
Operation and maintenance
    16       11  
Depreciation and amortization
    3       3  
Taxes other than income taxes
    1       1  
 
           
Total expenses
    17       13  
 
           
Operating Income
  $ 22     $ 45  
 
           
 
               
Throughput (in Bcf ):
               
Gathering
    93       98  
Three months ended March 31, 2008 compared to three months ended March 31, 2007
     The Field Services business segment reported operating income of $45 million for the three months ended March 31, 2008 compared to $22 million for the same period of 2007. The increase in operating income of $23 million was primarily driven by a one-time gain ($11 million) related to a settlement and contract buyout of one of

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our customers and a one-time gain ($6 million) related to the sale of assets, both recognized in the first quarter of 2008. In addition to these one-time items, increased revenues from gas gathering and ancillary services and higher commodity prices were partially offset by increased operating expenses associated with new assets and general cost increases.
     In addition, this business segment recorded equity income of $2 million and $4 million in the three months ended March 31, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other – net under the Other Income (Expense) caption.
Other Operations
     The following table shows the operating income (loss) of our Other Operations business segment for the three months ended March 31, 2007 and 2008 (in millions):
                 
    Three Months Ended March 31,  
    2007     2008  
Revenues
  $ 2     $ 3  
Expenses
    4       1  
 
           
Operating Income (Loss)
  $ (2 )   $ 2  
 
           
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 and “Risk Factors” in Item 1A of Part I of our 2007 Form 10-K, and “Cautionary Statement Regarding Forward-Looking Information.”
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, 2007 and 2008:
                 
    Three Months Ended March 31,
    2007   2008
    (in millions)
Cash provided by (used in):
               
Operating activities
  $ 264     $ 567  
Investing activities
    (403 )     (312 )
Financing activities
    72       (314 )
Cash Provided by Operating Activities
     Net cash provided by operating activities in the first quarter of 2008 increased $303 million compared to the same period in 2007 primarily due to increased net accounts receivable/payable ($178 million) and decreased gas storage inventory ($116 million).
Cash Used in Investing Activities
     Net cash used in investing activities decreased $91 million in the first quarter of 2008 as compared to the same period in 2007 due to decreased capital expenditures of $212 million primarily related to the completion of certain pipeline projects for our Interstate Pipelines business segment, offset by increased investment in unconsolidated affiliates of $105 million primarily related to the Southeast Supply Header (SESH) pipeline project, and increased restricted cash of transition bond companies of $18 million.

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Cash Provided by (Used In) Financing Activities
     Net cash used in financing activities in the first quarter of 2008 increased $386 million compared to the same period in 2007 primarily due to decreased borrowings under revolving credit facilities ($231 million), decreased short-term borrowings ($182 million) and increased repayments of long-term debt ($81 million), which were partially offset by increased proceeds from the issuance of long-term debt ($88 million) and increased proceeds from commercial paper ($35 million).
Future Sources and Uses of Cash
     Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the remaining nine months of 2008 include the following:
    approximately $813 million of capital expenditures;
 
    cash settlement obligations in connection with possible conversions by holders of our 3.75% convertible senior notes, having an aggregate principal amount of $402 million at March 31, 2008 or in connection with the redemption of such notes on May 30, 2008;
 
    maturing long-term debt aggregating approximately $282 million, including $82 million of transition bonds;
 
    the cash purchase of $175 million of pollution control bonds issued on our behalf;
 
    investment in and advances to SESH of approximately $185 million;
 
    dividend payments on CenterPoint Energy common stock and interest payments on debt.
     We expect that borrowings under our credit facilities, the proceeds from the February 2008 issuance of $488 million of transition bonds (discussed below), anticipated cash proceeds from the remarketing of $175 million of pollution control bonds purchased in April 2008 (discussed below) and anticipated cash flows from operations will be sufficient to meet our cash needs in 2008. Cash needs or discretionary financing or refinancing may also result in the issuance of equity or debt securities in the capital markets.
      Transition Bonds. In February 2008, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million in transition bonds pursuant to a financing order issued by the Texas Utility Commission in September 2007. Through issuance of the transition bonds, CenterPoint Houston securitized transition property of approximately $483 million representing the remaining balance of the CTC adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement. Proceeds were used by the special purpose entity to purchase $483 million of transition property from CenterPoint Houston and to pay costs of issuance. Following a subsequent distribution to us, we used the proceeds for general corporate purposes, including the repayment of debt and the making of loans to or investments in affiliates.
      Purchase of Pollution Control Bonds. In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we expect to remarket both series of bonds, at 100% of their principal amounts, in 2008.
      Convertible Debt.   As of December 31, 2007 and March 31, 2008, the 3.75% convertible senior notes discussed in Note 9(b) to our consolidated financial statements have been included as current portion of long-term debt in our Consolidated Balance Sheets because the last reported sale price of our common stock for at least 20 trading days during the period of 30 consecutive trading days ending on the last trading day of the fourth quarter of 2007 was greater than or equal to 120% of the conversion price of the 3.75% convertible senior notes and therefore, during the

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first quarter of 2008, the 3.75% convertible senior notes meet the criteria that make them eligible for conversion at the option of the holders of these notes. During the three months ended March 31, 2008, we issued 4.4 million shares of our common stock and paid cash of approximately $131 million to settle conversions of approximately $133 million principal amount of our 3.75% convertible senior notes. Convertible senior notes aggregating $402 million remained outstanding at March 31, 2008. In April 2008, we issued 0.25 million shares of our common stock and paid cash of approximately $11 million to settle a conversion of approximately $11 million principal amount of our 3.75% convertible notes.
     In April 2008, we announced a call for redemption of our 3.75% convertible senior notes, at 100% of their principal amount, on May 30, 2008. Substantially all of such notes are expected to be converted by holders prior to the redemption date, and substantially all of such conversions are expected to be settled with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due converting holders. If our closing stock price of $15.57 at April 25, 2008 were unchanged at the dates of the conversions, assuming the conversion of approximately $391 million aggregate principal amount of the notes at the current conversion rate, common stock reflecting a conversion premium of $153 million would be issued to the converting holders.  The conversion rate will be increased as a result of our April 24, 2008 declaration of a regular quarterly cash dividend of $0.1825 per share.  Under the terms of the indenture governing the notes, the increased conversion rate will be determined on May 13, 2008.
      Off-Balance Sheet Arrangements.   Other than operating leases and the guaranties described below, we have no off-balance sheet arrangements.
     Prior to the distribution of our ownership in Reliant Energy, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.
     The potential exposure of CERC under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, we and CERC believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain exposure to the counterparty under the guaranty.
      Credit and Receivables Facilities.   As of March 31, 2008, we had the following facilities (in millions):
                                         
                            Amount Utilized at    
Date Executed   Company   Type of Facility   Size of Facility   March 31, 2008   Termination Date
June 29, 2007   CenterPoint Energy  
Revolver
  $ 1,200     $ 28 (1)   June 29, 2012
June 29, 2007   CenterPoint Houston  
Revolver
    300       4 (1)   June 29, 2012
June 29, 2007   CERC Corp.  
Revolver
    950       135 (2)   June 29, 2012
October 30, 2007   CERC  
Receivables
    375       200     October 28, 2008
 
(1)   Represents outstanding letters of credit.
 
(2)   Includes $100 million of borrowings under the credit facility and $35 million of outstanding commercial paper supported by the CERC Corp. credit facility.
     Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt (excluding transition bonds) to earnings before interest, taxes, depreciation and amortization covenant.

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     CenterPoint Houston’s $300 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The facility contains a debt (excluding transition bonds) to total capitalization covenant.
     CERC Corp.’s $950 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.
     Under each of the credit facilities, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating. Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that we, CenterPoint Houston or CERC Corp. make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under each of the credit facilities are subject to acceleration upon the occurrence of events of default that we, CenterPoint Houston or CERC Corp. consider customary.
     We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective receivables and credit facilities.
     Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint Energy commercial paper program under which we began issuing commercial paper in June 2005. The $950 million CERC Corp. credit facility backstops a $950 million commercial paper program under which CERC Corp. began issuing commercial paper in February 2008. As of March 31, 2008, there was no CenterPoint Energy commercial paper outstanding and $35 million of CERC Corp. commercial paper outstanding. The CenterPoint Energy commercial paper is rated “Not Prime” by Moody’s Investors Service, Inc. (Moody’s), “A-2” by Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and “F3” by Fitch, Inc. (Fitch). The CERC Corp. commercial paper is rated “P-3” by Moody’s, “A-2” by S&P, and “F2” by Fitch. As a result of the credit ratings on the two commercial paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit Ratings,” will remain in effect for any given period of time or that one or more of these ratings will not be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities and may be revised or withdrawn at any time by the rating agency. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to obtain short- and long-term financing, the cost of such financings and the execution of our commercial strategies.
      Securities Registered with the SEC.   As of March 31, 2008, CenterPoint Energy had a shelf registration statement covering senior debt securities, preferred stock and common stock aggregating $750 million and CERC Corp. had a shelf registration statement covering $400 million principal amount of senior debt securities.
      Hedging of Future Debt Issuances.   As of March 31, 2008, we had outstanding treasury rate lock derivative instruments (treasury rate locks) with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008.
      Temporary Investments.   As of March 31, 2008, CERC Corp. had external temporary investments of approximately $4 million.
      Money Pool.   We have a money pool through which the holding company and participating subsidiaries can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under our revolving credit facility or the sale of our commercial paper.

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      Impact on Liquidity of a Downgrade in Credit Ratings.   As of April 15, 2008, Moody’s, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:
                         
    Moody’s   S&P   Fitch
Company/Instrument   Rating   Outlook(1)   Rating   Outlook(2)   Rating   Outlook(3)
CenterPoint Energy Senior Unsecured
     Debt
  Ba1   Stable   BBB-   Stable   BBB-   Stable
CenterPoint Houston Senior Secured
     Debt (First Mortgage Bonds)
  Baa2   Stable   BBB+   Stable   A-   Stable
CERC Corp. Senior Unsecured Debt
  Baa3   Stable   BBB   Stable   BBB   Stable
 
(1)   A “stable” outlook from Moody’s indicates that Moody’s does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed.
 
(2)   An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.
 
(3)   A “stable” outlook from Fitch encompasses a one- to two-year horizon as to the likely ratings direction.
     A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $300 million credit facility and CERC Corp.’s $950 million 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 could negatively impact our ability to complete capital market transactions. Additionally, a decline in credit ratings could increase cash collateral requirements and reduce earnings of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.
     In September 1999, we issued 2.0% ZENS having an original principal amount of $1.0 billion of which $840 million remain outstanding. 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. common stock (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW Common equal to approximately 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 or otherwise retired and TW Common shares are sold. A tax obligation of approximately $158 million relating to our “original issue discount” deductions on the ZENS would have been payable if all of the ZENS had been exchanged for cash on March 31, 2008. The ultimate tax obligation related to the ZENS notes continues to increase by the amount of the tax benefit realized each year and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes.
     CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of March 31, 2008, the amount posted as collateral amounted to approximately $20 million. Should the credit ratings of CERC Corp. (as the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days’ notice up to the amount of its previously unsecured credit limit. We estimate that as of March 31, 2008, unsecured credit limits extended to CES by counterparties aggregate $180 million; however, utilized credit capacity is significantly lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of

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$100 million based on CERC Corp.’s S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.
     In connection with the development of SESH’s 270-mile pipeline project, CERC Corp. has committed that it will advance funds to the joint venture or cause funds to be advanced for its 50% share of the cost to construct the pipeline. CERC Corp. also agreed to provide a letter of credit in an amount up to $400 million for its share of funds that have not been advanced in the event S&P reduces CERC Corp.’s bond rating below investment grade before CERC Corp. has advanced the required construction funds. However, CERC Corp. is relieved of these commitments (i) to the extent of 50% of any borrowing agreements that the joint venture has obtained and maintains for funding the construction of the pipeline and (ii) to the extent CERC Corp. or its subsidiary participating in the joint venture obtains committed borrowing agreements pursuant to which funds may be borrowed and used for the construction of the pipeline. A similar commitment has been provided by the other party to the joint venture. As of March 31, 2008, subsidiaries of CERC Corp. have advanced approximately $305 million to SESH, of which $159 million was in the form of an equity contribution and $146 million was in the form of a loan.
      Cross Defaults.   Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. In addition, six outstanding series of our senior notes, aggregating $1.3 billion in principal amount as of March 31, 2008, provide that 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. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.
      Other Factors that Could Affect Cash Requirements.   In addition to the above factors, our liquidity and capital resources could be affected by:
    cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price and weather hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, 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 natural gas suppliers;
 
    increased costs related to the acquisition of natural gas;
 
    increases in interest expense in connection with debt refinancings and borrowings under credit facilities;
 
    various regulatory actions;
 
    the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which CERC is a guarantor;
 
    slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;
 
    cash payments in connection with the exercise of contingent conversion rights of holders of convertible debt;
 
    the outcome of litigation brought by and against us;
 
    contributions to benefit plans;
 
    restoration costs and revenue losses resulting from natural disasters such as hurricanes; and
 
    various other risks identified in “Risk Factors” in Item 1A of our 2007 Form 10-K.

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      Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money.  CenterPoint Houston’s credit facility limits CenterPoint Houston’s debt (excluding transition bonds) as a percentage of its total capitalization to 65%. CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a percentage of its total capitalization to 65%. Our $1.2 billion credit facility contains a debt, excluding transition bonds, to EBITDA covenant. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.
NEWACCOUNTING PRONOUNCEMENTS
     See Note 2 to our Interim Condensed Financial Statements for a discussion of new accounting pronouncements that affect us.
Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
Commodity Price Risk From Non-Trading Activities
     We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At March 31, 2008, the recorded fair value of our non-trading energy derivatives was a net asset of $61 million. The net asset consisted of a net asset of less than $1 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $60 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their March 31, 2008 levels would have decreased the fair value of our non-trading energy derivatives net asset by $12 million.
     The above analysis of the non-trading energy derivatives utilized for commodity price risk management 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. Furthermore, the non-trading 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 non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.
Interest Rate Risk
     As of March 31, 2008, we had outstanding long-term debt, bank loans, lease obligations, treasury rate lock derivative instruments and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.
     Our floating-rate obligations aggregated $335 million at March 31, 2008. If the floating interest rates were to increase by 10% from March 31, 2008 rates, our combined interest expense would increase by approximately $1 million annually.
     At March 31, 2008, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $9.2 billion in principal amount and having a fair value of $9.4 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 (please read Note 9 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $379 million if interest rates were to decline by 10% from their levels at March 31, 2008. 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 of March 31, 2008, we had outstanding treasury rate locks with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%.

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These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the forecasted issuance of $300 million of fixed-rate debt in 2008. As of March 31, 2008, the treasury lock derivative instruments could be terminated at a cost of $16 million. The treasury rate locks qualify as cash flow hedges under SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), and are marked to market in our Consolidated Balance Sheets with changes reflected in accumulated other comprehensive loss. A decrease of 10% in the March 31, 2008 level of interest rates on 10-year U.S. treasury notes would increase the cost of terminating the treasury rate locks outstanding at March 31, 2008 by approximately $9 million.
     Upon adoption of SFAS No. 133, effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $115 million at March 31, 2008 was a fixed-rate obligation and, therefore, did 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 $19 million if interest rates were to decline by 10% from levels at March 31, 2008. Changes in the fair value of the derivative component, a $211 million recorded liability at March 31, 2008, are 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, 2008 levels, the fair value of the derivative component liability would increase by approximately $3 million, which would be recorded as an unrealized 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, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the March 31, 2008 market value of TW Common would result in a net loss of approximately $4 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.
Item 4. CONTROLS AND PROCEDURES
     In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of March 31, 2008 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 and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.
     There has been no change in our internal controls over financial reporting that occurred during the three months ended March 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
PART II. OTHER INFORMATION
Item 1. LEGAL PROCEEDINGS
     For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 4 and 10 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “ — Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2007 Form 10-K.
Item 1A. RISK FACTORS
     There have been no material changes from the risk factors disclosed in our 2007 Form 10-K.

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Item 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
      Conversion of 3.75% Convertible Senior Notes due 2023. Since February 20, 2008, we have issued 533,737 shares of our common stock upon conversion of approximately $21.4 million aggregate principal amount of our 3.75% Convertible Senior Notes due 2023, as set forth in the table below:
                   
Settlement Date     Principal Amount     Number of Shares  
of Conversion     of Notes Converted     of Common Stock Issued  
March 7, 2008
    $ 650,000       58,134 (1)
March 12, 2008
      10,000,000       227,803 (2)
April 18, 2008
      2,000       44 (2)
April 21, 2008
      2,000       45 (2)
April 22, 2008
      10,718,000       247,664 (2)
April 25, 2008
      2,000       47 (2)
 
             
 
    $ 21,374,000       533,737  
 
             
 
(1)   Based on terms of the notes, settled entirely through the issuance of shares except for a payment of cash in lieu of fractional shares.
 
(2)   The number of shares issued in respect of any principal amount of notes converted is in addition to payment of cash in an amount equal to the principal amount of such notes and cash in lieu of fractional shares.
     The shares of our common stock were issued solely to former holders of our 3.75% Convertible Senior Notes due 2023 upon conversion pursuant to the exemption from registration provided under Section 3(a)(9) of the Securities Act of 1933, as amended. This exemption is available because the shares of our common stock were exchanged by us with our existing security holders exclusively where no commission or other remuneration was paid or given directly or indirectly for soliciting such an exchange.
Item 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS
     At the annual meeting of our shareholders held on April 24, 2008, the matters voted upon and the number of votes cast for or against, as well as the number of abstentions and broker non-votes as to such matters (including a separate tabulation with respect to each nominee for office), were as stated below:
     The following nominees for Class III Directors were elected to serve three-year terms expiring at the 2011 annual meeting of shareholders (abstentions and broker non-votes were not counted):
                 
          Nominee   For   Against
O. Holcombe Crosswell
    272,278,964       5,954,739  
 
               
Janiece M. Longoria
    273,426,876       4,863,309  
 
               
Thomas F. Madison
    270,543,888       7,520,236  
 
               
Sherman M. Wolff
    272,791,233       5,358,604  
     Derrill Cody, David M. McClanahan, Robert T. O’Connell, Michael E. Shannon, Donald R. Campbell, Milton Carroll and Peter S. Wareing all continue as directors of CenterPoint Energy.
     The proposal to amend our Articles of Incorporation to phase out our board of directors’ classified structure was approved with 270,351,324 votes for, 7,301,896 votes against, 3,980,338 abstentions and no broker non-votes.
     The appointment of Deloitte & Touche LLP as independent registered public accountants for CenterPoint Energy for 2008 was ratified with 274,156,719 votes for, 4,013,996 votes against, 3,462,844 abstentions and no broker non-votes.

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Item 5. OTHER INFORMATION
     The ratio of earnings to fixed charges for the three months ended March 31, 2007 and 2008 was 2.16 and 2.25, respectively. We do not believe that the ratios for these three-month periods are necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.
Item 6. EXHIBITS
     The following exhibits are filed herewith:
     Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.
                         
                SEC File    
                or    
Exhibit             Registration   Exhibit
Number     Description   Report or Registration Statement   Number   Reference
3.1.1
    Amended and Restated Articles of Incorporation of CenterPoint Energy   CenterPoint Energy’s Registration Statement on Form S-4   3-69502     3.1  
 
                       
3.1.2
    Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated March 27, 2002   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     3.1.1  
 
                       
+3.1.3
    Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated April 24, 2008                
 
                       
3.2
    Amended and Restated Bylaws of CenterPoint Energy   CenterPoint Energy’s Form 8-K dated January 24, 2008   1-31447     3.1  
 
                       
3.3
    Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     3.3  
 
                       
4.1
    Form of CenterPoint Energy Stock Certificate   CenterPoint Energy’s Registration Statement on Form S-4   3-69502     4.1  
 
                       
4.2
    Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     4.2  
 
                       
4.3
    $1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.3  
 
                       
4.4
    $300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.4  
 
                       
4.5
    $950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.5  

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                SEC File    
                or    
Exhibit             Registration   Exhibit
Number     Description   Report or Registration Statement   Number   Reference
10.1
    Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.1  
 
                       
10.2
    Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.2  
 
                       
10.3
    First Amendment to CenterPoint Energy, Inc. Deferred Compensation Plan (as amended and restated effective January 1, 2003)   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.3  
 
                       
10.4
    CenterPoint Energy 2005 Deferred Compensation Plan (effective January 1, 2008)   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.3  
 
                       
+12
    Computation of Ratios of Earnings to Fixed Charges                
 
                       
+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 1A “Risk Factors”                

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
         
    CENTERPOINT ENERGY, INC.
 
 
  By:   /s/ Walter L. Fitzgerald    
    Walter L. Fitzgerald   
    Senior Vice President and Chief Accounting Officer   
 
Date: April 30, 2008

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EXHIBIT INDEX
                         
                SEC File    
                or    
Exhibit             Registration   Exhibit
Number     Description   Report or Registration Statement   Number   Reference
3.1.1
    Amended and Restated Articles of Incorporation of CenterPoint Energy   CenterPoint Energy’s Registration Statement on Form S-4   3-69502     3.1  
 
                       
3.1.2
    Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated March 27, 2002   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     3.1.1  
 
                       
+3.1.3
    Articles of Amendment to Amended and Restated Articles of Incorporation of CenterPoint Energy dated April 24, 2008                
 
                       
3.2
    Amended and Restated Bylaws of CenterPoint Energy   CenterPoint Energy’s Form 8-K dated January 24, 2008   1-31447     3.1  
 
                       
3.3
    Statement of Resolution Establishing Series of Shares designated Series A Preferred Stock of CenterPoint Energy   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     3.3  
 
                       
4.1
    Form of CenterPoint Energy Stock Certificate   CenterPoint Energy’s Registration Statement on Form S-4   3-69502     4.1  
 
                       
4.2
    Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent   CenterPoint Energy’s Form 10-K for the year ended December 31, 2001   1-31447     4.2  
 
                       
4.3
    $1,200,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.3  
 
                       
4.4
    $300,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.4  
 
                       
4.5
    $950,000,000 Second Amended and Restated Credit Agreement, dated as of June 29, 2007 among CERC Corp., as Borrower, and the banks named therein   CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007   1-31447     4.5  


Table of Contents

                         
                SEC File    
                or    
Exhibit             Registration   Exhibit
Number     Description   Report or Registration Statement   Number   Reference
10.1
    Form of Performance Share Award Agreement for 20XX — 20XX Performance Cycle under the Long-Term Incentive Plan of CenterPoint Energy, Inc.   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.1  
 
                       
10.2
    Form of Stock Award Agreement (With Performance Goal) under the Long-Term Incentive Plan of CenterPoint Energy, Inc.   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.2  
 
                       
10.3
    First Amendment to CenterPoint Energy, Inc. Deferred Compensation Plan (as amended and restated effective January 1, 2003)   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.3  
 
                       
10.4
    CenterPoint Energy 2005 Deferred Compensation Plan (effective January 1, 2008)   CenterPoint Energy’s Form 8-K dated February 20, 2008   1-31447     10.3  
 
                       
+12
    Computation of Ratios of Earnings to Fixed Charges                
 
                       
+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 1A “Risk Factors”                

 

Exhibit 3.1.3
ARTICLES OF AMENDMENT
TO THE
AMENDED AND RESTATED ARTICLES OF INCORPORATION
OF
CENTERPOINT ENERGY, INC.
          Pursuant to the provisions of Article 4.04 of the Texas Business Corporation Act, CenterPoint Energy, Inc., a Texas corporation (the “Company”), hereby adopts the following Articles of Amendment to its Amended and Restated Articles of Incorporation (as amended prior to the date hereof, the “Articles of Incorporation”):
ARTICLE I
          The name of the Company is CenterPoint Energy, Inc.
ARTICLE II
          The following amendment to the Articles of Incorporation (the “Amendment”) was duly adopted by the shareholders of the Company on April 24, 2008:
          The Articles of Incorporation are hereby amended by deleting all of the first paragraph of part (a) of ARTICLE V following the first sentence thereof and inserting in lieu thereof the following:
“Except as may otherwise be provided pursuant to the provisions established by the Board of Directors with respect to any series of Preferred Stock pursuant to Division A of Article VI of these Articles of Incorporation, at each annual meeting of shareholders, all directors shall be elected to hold office for a term expiring at the next succeeding annual meeting of shareholders and until their successors have been elected and qualified; provided, that any director elected for a longer term before the 2009 annual meeting of shareholders shall hold office for the entire term for which he or she was originally elected.”
ARTICLE III
          The Amendment has been approved in the manner required by the Texas Business Corporation Act and the constituent documents of the Company.
          IN WITNESS WHEREOF, the Company has caused these Articles of Amendment to be duly executed as of the 24 th day of April, 2008.
             
 
  CENTERPOINT ENERGY, INC.    
 
           
 
  By:   /s/ Richard B. Dauphin
 
Richard B. Dauphin
   
 
      Assistant Corporate Secretary    

 

Exhibit 12
CENTERPOINT ENERGY, INCORPORATED AND SUBSIDIARIES
COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
(Millions of Dollars)
                 
    Three Months Ended
March 31,
 
    2007     2008  
Income from continuing operations
  $ 130     $ 123  
Income taxes for continuing operations
    72       74  
Capitalized interest
    (9 )     (3 )
 
           
 
    193       194  
 
           
Fixed charges, as defined:
               
 
Interest
    154       149  
Capitalized interest
    9       3  
Interest component of rentals charged to operating expense
    4       4  
 
           
Total fixed charges
    167       156  
 
           
 
Earnings, as defined
  $ 360     $ 350  
 
           
 
Ratio of earnings to fixed charges
    2.16       2.25  
 
           

 

Exhibit 31.1
CERTIFICATIONS
I, David M. McClanahan, certify that:
     1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2008
     
 
  /s/ David M. McClanahan 
 
   
 
  David M. McClanahan
President and Chief Executive Officer

 

 

Exhibit 31.2
CERTIFICATIONS
I, Gary L. Whitlock, certify that:
     1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;
     2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
     3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
     4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:
  (a)   Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
 
  (b)   Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
 
  (c)   Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
 
  (d)   Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and
     5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):
  (a)   All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
 
  (b)   Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.
Date: April 30, 2008
     
 
  /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 quarter ended March 31, 2008 (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
   
April 30, 2008
   

 

 

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 quarter ended March 31, 2008 (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
   
April 30, 2008
   

 

 

 
Item 1A.    Risk Factors
 
We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries:
 
Risk Factors Affecting Our Electric Transmission & Distribution Business
 
CenterPoint Houston may not be successful in ultimately recovering the full value of its true-up components, which could result in the elimination of certain tax benefits and could have an adverse impact on CenterPoint Houston’s results of operations, financial condition and cash flows.
 
In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued the True-Up Order allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional EMCs returned to customers after August 31, 2004 and in certain other respects.
 
CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:
 
  •  reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;
 
  •  reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to REPs; and
 
  •  affirmed the True-Up Order in all other respects.
 
The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.
 
CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:
 
  •  reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;
 
  •  reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to RRI;
 
  •  ordered that the tax normalization issue described below be remanded to the Texas Utility Commission; and
 
  •  affirmed the district court’s judgment in all other respects.
 
CenterPoint Houston and two other parties filed motions for rehearing with the court of appeals. In the event that the motions for rehearing are not resolved in a manner favorable to it, CenterPoint Houston intends to seek further review by the Texas Supreme Court. Although we and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and accordingly that it is reasonably possible that it will be successful in its further appeals, we can provide no assurance as to the ultimate rulings by the courts on the issues to be considered in the various appeals or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.
 
To reflect the impact of the True-Up Order, in 2004 and 2005 we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been



 

recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of the pending motions for rehearing or on further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $130 million to $350 million, plus interest subsequent to December 31, 2007.
 
In the True-Up Order the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. We believe that the Texas Utility Commission based its order on proposed regulations issued by the IRS in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of ADITC and EDFIT back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. We subsequently requested a PLR asking the IRS whether the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations. In that ruling, which was received in August 2007, the IRS concluded that such reductions would cause normalization violations with respect to the ADITC and EDFIT. As in a similar PLR issued in May 2006 to another Texas utility, the IRS did not reference its proposed regulations.
 
The district court affirmed the Texas Utility Commission’s ruling on the tax normalization issue, but in response to a request from the Texas Utility Commission, the court of appeals ordered that the tax normalization issue be remanded for further consideration. If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require us to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. However, we and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.
 
CenterPoint Houston’s receivables are concentrated in a small number of REPs, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.
 
CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with 74 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs 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 REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. Applicable Texas Utility Commission regulations limit the extent to which CenterPoint Houston can demand security from REPs for payment of its delivery charges. RRI, through its subsidiaries, is CenterPoint Houston’s largest customer. Approximately 48% of CenterPoint Houston’s $141 million in billed receivables from REPs at December 31, 2007 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.



 

Rate regulation of CenterPoint Houston’s business may delay or deny CenterPoint Houston’s ability to earn a reasonable return and fully recover its costs.
 
CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. In this connection, pursuant to the Settlement Agreement, discussed in “Business — Regulation — State and Local Regulation — Electric Transmission & Distribution — CenterPoint Houston Rate Agreement” in Item 1 of this report, until June 30, 2010 CenterPoint Houston is limited in its ability to request rate relief. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.
 
Disruptions at power generation facilities owned by third parties could interrupt CenterPoint Houston’s sales of transmission and distribution services.
 
CenterPoint Houston transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. 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 sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows may be adversely affected.
 
CenterPoint Houston’s revenues and results of operations are seasonal.
 
A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.
 
Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses
 
Rate regulation of CERC’s business may delay or deny CERC’s ability to earn a reasonable return and fully recover its costs.
 
CERC’s rates for its Gas Operations are regulated by certain municipalities and state commissions, and for its interstate pipelines by the FERC, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC’s costs and enable CERC to earn a reasonable return on its invested capital.
 
CERC’s businesses must compete with alternative energy sources, which could result in CERC marketing less natural gas, and its interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.
 
CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.
 
CERC’s two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of



 

competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of CERC’s competitors could lead to lower prices, which may have an adverse impact on CERC’s results of operations, financial condition and cash flows.
 
CERC’s natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas pricing levels, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity.
 
CERC is subject to risk associated with increases in the price of natural gas. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which CERC operates and increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. Additionally, increasing natural gas prices could create the need for CERC to provide collateral in order to purchase natural gas.
 
If CERC were to fail to renegotiate a contract with one of its significant pipeline customers or if CERC renegotiates the contract on less favorable terms, there could be an adverse impact on its operations.
 
Since October 31, 2006, CERC’s contract with Laclede, one of its pipeline customers, has been terminable upon one year’s prior notice. CERC has not received a termination notice and is currently negotiating a long-term contract with Laclede. If Laclede were to terminate this contract or if CERC were to renegotiate this contract at rates substantially lower than the rates provided in the current contract, there could be an adverse effect on CERC’s results of operations, financial condition and cash flows.
 
A decline in CERC’s credit rating could result in CERC’s having to provide collateral in order to purchase gas.
 
If CERC’s credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC might be unable to obtain the necessary natural gas to meet its obligations to customers, and its results of operations, financial condition and cash flows would be adversely affected.
 
The revenues and results of operations of CERC’s interstate pipelines and field services businesses are subject to fluctuations in the supply of natural gas.
 
CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC’s results of operations, financial condition and cash flows.
 
CERC’s revenues and results of operations are seasonal.
 
A substantial portion of CERC’s revenues is derived from natural gas sales and transportation. Thus, CERC’s revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.
 
The actual cost of pipelines under construction and related compression facilities may be significantly higher than CERC’s current estimates.
 
Subsidiaries of CERC Corp. are involved in significant pipeline construction projects. The construction of new pipelines and related compression facilities requires the expenditure of significant amounts of capital, which may exceed CERC’s estimates. These projects may not be completed at the budgeted cost, on schedule or at all. The construction of new pipeline or compression facilities is subject to construction cost overruns due to labor costs,



 

costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve CERC’s expected investment return, which could adversely affect CERC’s financial condition, results of operations or cash flows.
 
The states in which CERC provides regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on CERC’s ability to operate.
 
The Public Utility Holding Company Act of 1935, to which the Company was subject prior to its repeal in the Energy Act, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states in which CERC does business have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility businesses that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.
 
These regulatory frameworks could have adverse effects on CERC’s ability to operate its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions over similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.
 
Risk Factors Associated with Our Consolidated Financial Condition
 
If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.
 
As of December 31, 2007, we had $9.7 billion of outstanding indebtedness on a consolidated basis, which includes $2.3 billion of non-recourse transition bonds. As of December 31, 2007, approximately $842 million principal amount of this debt is required to be paid through 2010. This amount excludes principal repayments of approximately $525 million on transition bonds, for which a dedicated revenue stream exists. In addition, as of December 31, 2007, we had $535 million of outstanding 3.75% convertible notes on which holders could exercise their conversion rights during the first quarter of 2008 and in subsequent quarters in which our common stock price causes such notes to be convertible. In January and February 2008, holders of our 3.75% convertible senior notes converted approximately $123 million principal amount of such notes. In February 2008, we issued approximately $488 million of additional non-recourse transition bonds. Our future financing activities may depend, at least in part, on:
 
  •  the resolution of the true-up components, including, in particular, the results of appeals to the courts regarding rulings obtained to date;
 
  •  general economic and capital market conditions;
 
  •  credit availability from financial institutions and other lenders;
 
  •  investor confidence in us and the markets in which we operate;
 
  •  maintenance of acceptable credit ratings;
 
  •  market expectations regarding our future earnings and cash flows;



 

 
  •  market perceptions of our ability to access capital markets on reasonable terms;
 
  •  our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; and
 
  •  provisions of relevant tax and securities laws.
 
As of December 31, 2007, CenterPoint Houston had outstanding $2.0 billion aggregate principal amount of general mortgage bonds, including approximately $527 million held in trust to secure pollution control bonds for which we are obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2007. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.
 
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 this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.
 
As a holding company with no operations of our own, we will depend on distributions from our subsidiaries to meet our payment obligations, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.
 
We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries 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.
 
The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and those of our subsidiaries.
 
We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.



 

Risks Common to Our Businesses and Other Risks
 
We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.
 
Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment, as discussed in “Business — Environmental Matters” in Item 1 of this report. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
  •  restricting the way we can handle or dispose of wastes;
 
  •  limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;
 
  •  requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and
 
  •  enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.
 
In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:
 
  •  construct or acquire new equipment;
 
  •  acquire permits for facility operations;
 
  •  modify or replace existing and proposed equipment; and
 
  •  clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.
 
Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.
 
Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.
 
We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.
 
In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to, its transmission and distribution properties, it may not be able to recover such loss or damage through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.



 

We, CenterPoint Houston and CERC could incur liabilities associated with businesses and assets that we have transferred to others.
 
Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, a predecessor of CenterPoint Houston, directly or through subsidiaries and include:
 
  •  those transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and
 
  •  those transferred to Texas Genco in connection with its organization and capitalization.
 
In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.
 
Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for the benefit of CERC, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In February 2007, we and CERC made a formal demand on RRI in connection with one of the two remaining guaranties under procedures provided by the Master Separation Agreement, dated December 31, 2000, between Reliant Energy and RRI. That demand sought to resolve a disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In December 2007, we, CERC and RRI amended the agreement relating to the security to be provided by RRI for these guaranties, pursuant to which CERC released the $29.3 million in letters of credit RRI had provided as security, and RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.
 
The remaining exposure to CERC under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under those transportation contracts, which will be effective until 2018, was approximately $135 million as of December 31, 2007. RRI continues to meet its obligations under the contracts, and we believe current market conditions make those contracts valuable in the near term and that additional security is not needed at this time. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the contracts or if RRI should fail to provide security in the event market conditions change adversely, our exposure to the counterparty under the guaranty could exceed the security provided by RRI.
 
RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI’s creditors might be made against us as its former owner.
 
Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of energy sales in California and other markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include the effect of RRI’s financial results on Reliant Energy’s historical financial statements and liability of Reliant Energy as a controlling shareholder of RRI. We or CenterPoint Houston could incur liability if claims in one or more of these lawsuits were



 

successfully asserted against us or CenterPoint Houston and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.
 
In connection with the organization and capitalization of Texas Genco, Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy 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 obligations of CenterPoint Houston and CenterPoint Houston was not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. In connection with the sale of Texas Genco’s fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC, the separation agreement we entered into with Texas Genco in connection with the organization and capitalization of Texas Genco was amended to provide that all of Texas Genco’s rights and obligations under the separation agreement relating to its fossil generation assets, including Texas Genco’s obligation to indemnify us with respect to liabilities associated with the fossil generation assets and related business, were assigned to and assumed by Texas Genco LLC. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and we have assumed and agreed to indemnify Texas Genco LLC against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by us. If Texas Genco or Texas Genco LLC were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.
 
We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations we own, but most existing claims relate to facilities previously owned by our subsidiaries but currently owned by Texas Genco LLC, which is now known as NRG Texas LP. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from us and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by Texas Genco LLC.