10-K 1 h54051e10vk.htm FORM 10-K - ANNUAL REPORT e10vk
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UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
 
Form 10-K
 
     
(Mark One)
   
þ
  ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
    For the fiscal year ended December 31, 2007
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
(Address and zip code of principal executive offices)
  (713) 207-1111
(Registrant’s telephone number, including area code)
     
 
Securities registered pursuant to Section 12(b) of the Act:
 
     
Title of each class
 
Name of each exchange on which registered
 
Common Stock, $0.01 par value and associated
rights to purchase preferred stock
  New York Stock Exchange
Chicago Stock Exchange
 
Securities registered pursuant to Section 12(g) of the Act:
None
 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.  Yes þ     No o
 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.  Yes o     No þ
 
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 if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of each of the registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  þ
 
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
(Do not check if a smaller reporting company)
  Smaller reporting company o
 
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
 
The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (Company) was $5,552,435,108 as of June 30, 2007, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 15, 2008, the Company had 327,346,112 shares of Common Stock outstanding. Excluded from the number of shares of Common Stock outstanding are 166 shares held by the Company as treasury stock.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive proxy statement relating to the 2008 Annual Meeting of Shareholders of the Company, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2007, are incorporated by reference in Item 10, Item 11, Item 12, Item 13 and Item 14 of Part III of this Form 10-K.
 


 

 
TABLE OF CONTENTS
 
                 
        Page
 
      Business     1  
      Risk Factors     22  
      Unresolved Staff Comments     30  
      Properties     30  
      Legal Proceedings     31  
      Submission of Matters to a Vote of Security Holders     31  
 
PART II
      Market for Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities     31  
      Selected Financial Data     34  
      Management’s Discussion and Analysis of Financial Condition and Results of Operations     35  
      Quantitative and Qualitative Disclosures About Market Risk     61  
      Financial Statements and Supplementary Data     63  
      Changes in and Disagreements with Accountants on Accounting and Financial Disclosure     116  
      Controls and Procedures     116  
      Other Information     116  
 
PART III
      Directors, Executive Officers and Corporate Governance     116  
      Executive Compensation     116  
      Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters     116  
      Certain Relationships and Related Transactions, and Director Independence     117  
      Principal Accounting Fees and Services     117  
 
PART IV
      Exhibits and Financial Statement Schedules     118  
 HI 1995 Section 415 Benefit Restoration Plan
 Summary of Non-Employee Director Compensation
 Summary of Named Executive Officer Compensation
 Form of Executive Officer Change in Control Agreement
 Form of Corporate Officer Change in Control Agreement
 Computation of Ratio of Earnings to Fixed Charges
 Subsidiaries of CenterPoint Energy
 Consent of Deloitte & Touche LLP
 Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
 Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
 Section 1350 Certification of David M. McClanahan
 Section 1350 Certification of Gary L. Whitlock


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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.
 
Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements are described under “Risk Factors” in Item 1A of this report.
 
You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement.


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PART I
 
Item 1.   Business
 
OUR BUSINESS
 
Overview
 
We are a public utility holding company whose indirect wholly owned subsidiaries include:
 
  •  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 Corp. 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.
 
Our reportable business segments are Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The operations of Texas Genco Holdings, Inc. (Texas Genco), formerly our majority owned electric generating subsidiary, the sale of which was completed in April 2005, are presented as discontinued operations. From time to time, we consider the acquisition or the disposition of assets or businesses.
 
Our principal executive offices are located at 1111 Louisiana, Houston, Texas 77002 (telephone number: 713-207-1111).
 
We make available free of charge on our Internet website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such reports with, or furnish them to, the Securities and Exchange Commission (SEC). Additionally, we make available free of charge on our Internet website:
 
  •  our Code of Ethics for our Chief Executive Officer and Senior Financial Officers;
 
  •  our Ethics and Compliance Code;
 
  •  our Corporate Governance Guidelines; and
 
  •  the charters of our audit, compensation, finance and governance committees.
 
Any shareholder who so requests may obtain a printed copy of any of these documents from us. Changes in or waivers of our Code of Ethics for our Chief Executive Officer and Senior Financial Officers and waivers of our Ethics and Compliance Code for directors or executive officers will be posted on our Internet website within five business days of such change or waiver and maintained for at least 12 months or reported on Item 5.05 of Form 8-K. Our website address is www.centerpointenergy.com. Except to the extent explicitly stated herein, documents and information on our website are not incorporated by reference herein.
 
Electric Transmission & Distribution
 
In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law) that led to the restructuring of integrated electric utilities operating within Texas. Pursuant to that legislation, integrated electric utilities operating within the Electric Reliability Council of Texas, Inc. (ERCOT) were required to separate their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation also required that the prices for wholesale generation and retail electric sales be unregulated, but services by companies providing transmission and distribution service, such as CenterPoint Houston, would continue to be regulated by the Public Utility Commission of Texas (Texas Utility Commission). The legislation provided for a transition period to move to the new market structure and provided a true-up mechanism for the


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formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs are recoverable after approval by the Texas Utility Commission either through the issuance of securitization bonds or through the implementation of a competition transition charge (CTC) as a rider to the utility’s tariff.
 
CenterPoint Houston is the only business of CenterPoint Energy that continues to engage in electric utility operations. It is a transmission and distribution electric utility that operates wholly within the state of Texas. Neither CenterPoint Houston nor any other subsidiary of CenterPoint Energy makes sales of electric energy at retail or wholesale, or owns or operates any electric generating facilities.
 
Electric Transmission
 
On behalf of retail electric providers (REPs), CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers taking power at or above 69 kilovolts (kV) in locations throughout the control area managed by ERCOT. CenterPoint Houston provides transmission services under tariffs approved by the Texas Utility Commission.
 
Electric Distribution
 
In ERCOT, end users purchase their electricity directly from certificated REPs. CenterPoint Houston delivers electricity for REPs in its certificated service area by carrying lower-voltage power from the substation to the retail electric customer. CenterPoint Houston’s distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. CenterPoint Houston’s operations include construction and maintenance of electric transmission and distribution facilities, metering services, outage response services and call center operations. CenterPoint Houston provides distribution services under tariffs approved by the Texas Utility Commission. Texas Utility Commission rules and market protocols govern the commercial operations of distribution companies and other market participants. Rates for these existing services may be reviewed only through rate cases conducted before the Texas Utility Commission.
 
ERCOT Market Framework
 
CenterPoint Houston is a member of ERCOT. ERCOT serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally owned electric utilities, rural electric cooperatives, independent generators, power marketers and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, a portion of the eastern part of the state bordering Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market includes an aggregate net generating capacity of approximately 72,000 megawatts (MW). There are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.
 
The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council (NERC) and approved by the Federal Energy Regulatory Commission (FERC). These reliability standards are administered by the Texas Regional Entity, a Division of ERCOT (TRE). The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.
 
CenterPoint Houston’s electric transmission business, along with those of other owners of transmission facilities in Texas, supports the operation of the ERCOT ISO. The transmission business has planning, design,


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construction, operation and maintenance responsibility for the portion of the transmission grid and for the load-serving substations it owns, primarily within its certificated area. We participate with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.
 
Recovery of True-Up Balance
 
The Texas electric restructuring law substantially amended the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law required the Texas Utility Commission to conduct a “true-up” proceeding to determine CenterPoint Houston’s stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for its recovery of those costs.
 
In March 2004, CenterPoint Houston filed its 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 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 Reliant Energy, Inc. (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


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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 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, 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 Private Letter Ruling (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.
 
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 REPs 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. Effective September 13, 2005, the return on the CTC portion of the true-up balance is included in CenterPoint Houston’s tariff-based revenues.
 
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


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Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC 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 new rule discussed below. 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, we do not expect the disposition of this matter to have a material adverse effect on our or CenterPoint Houston’s financial condition, results of operations or cash flows.
 
In June 2006, the Texas Utility Commission adopted the revised rule governing the carrying charges on unrecovered CTC balances as recommended by its staff (Staff). The rule, which applies to CenterPoint Houston, reduced the allowed interest rate on the unrecovered CTC balance prospectively from 11.075% to a weighted average cost of capital of 8.06%. The annualized impact on operating income is a reduction of approximately $18 million per year for the first year with lesser impacts in subsequent years. In July 2006, CenterPoint Houston made a compliance filing necessary to implement the rule changes effective August 1, 2006.
 
During the years ended December 31, 2005, 2006 and 2007, CenterPoint Houston recognized approximately $19 million, $55 million and $42 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2005, 2006 and 2007, CenterPoint Houston recognized approximately $1 million, $13 million and $14 million, respectively, of the allowed equity return not previously recorded. As of December 31, 2007, we have not recorded an allowed equity return of $220 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates.
 
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, after taking into account the environmental refund and the fuel reconciliation settlement amounts discussed below. 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.
 
Refund of Environmental Retrofit Costs
 
The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to CenterPoint Houston’s generation assets. The True-Up Order required CenterPoint Houston to provide evidence by January 31, 2007 that the entire $699 million was actually spent by December 31, 2006 on environmental programs and provided for the Texas Utility Commission to determine the appropriate manner to return to customers any unused portion of these funds, including interest on the funds and on stranded costs attributable to the environmental costs portion of the stranded costs recovery. In January 2007, the successor in interest to CenterPoint Houston’s generation assets advised that, as of December 31, 2006, it had spent only approximately $664 million. On January 31, 2007, CenterPoint Houston made the required filing with the Texas Utility Commission, identifying approximately $35 million in unspent funds to be refunded to customers along with approximately $7 million of interest and requesting permission to refund these amounts through a reduction of the CTC. Such amounts were recorded as regulatory liabilities as of December 31, 2006. In July 2007, CenterPoint Houston, the Staff and the


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other parties filed a settlement agreement in which it was agreed that the total amount of the refund, including all principal and interest, was $45 million as of May 31, 2007, that interest would continue to accrue after May 31, 2007 on any unrefunded balance at a rate of 5.4519% per year and that the refund should be used to offset the principal amount proposed in CenterPoint Houston’s application to securitize the CTC and other amounts. The offset occurred in connection with the approximately $488 million of transition bonds issued in February 2008. In August 2007, the Texas Utility Commission issued a final order consistent with the terms of that settlement agreement. As of December 31, 2007, CenterPoint Houston had recorded a regulatory liability of $46 million related to this matter.
 
Final Fuel Reconciliation
 
The results of the Texas Utility Commission’s final decision related to CenterPoint Houston’s final fuel reconciliation were a component of the True-Up Order. CenterPoint Houston appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation in 2003 plus interest of $10 million. That decision was upheld by a Travis County district court and affirmed by the Texas Third Court of Appeals. Although it filed an appeal with the Texas Supreme Court, in February 2007 CenterPoint Houston asked the Texas Supreme Court to hold that appeal in abeyance pending consideration by the Texas Utility Commission of a tentative settlement reached by the parties. In October 2007, the Texas Utility Commission issued a final order consistent with the settlement, and the Texas Supreme Court ultimately vacated the lower court decisions. The settlement allows CenterPoint Houston recovery of $12.5 million plus interest from January 2002. As a result of the settlement, CenterPoint Houston recorded a regulatory asset of $17 million in 2007.
 
Customers
 
CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. CenterPoint Houston’s customers consist of 74 REPs, which sell electricity to approximately 2 million metered customers in CenterPoint Houston’s certificated service area, and municipalities, electric cooperatives and other distribution companies located outside CenterPoint Houston’s certificated service area. Each REP is licensed by, and must meet minimal creditworthiness criteria established by the Texas Utility Commission. Two of the REPs in CenterPoint Houston’s service area are subsidiaries of RRI. Sales to subsidiaries of RRI represented approximately 62%, 56% and 51% of CenterPoint Houston’s transmission and distribution revenues in 2005, 2006 and 2007, respectively. CenterPoint Houston’s billed receivables balance from REPs as of December 31, 2007 was $141 million. Approximately 48% of this amount was owed by subsidiaries of RRI. CenterPoint Houston does not have long-term contracts with any of its customers. It operates on a continuous billing cycle, with meter readings being conducted and invoices being distributed to REPs each business day.
 
Advanced Metering System and Distribution Automation (Intelligent Grid)
 
CenterPoint Houston is pursuing development and possible deployment of an advanced metering system (AMS) and electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” which would make use of CenterPoint Houston’s lines and other facilities to provide on-demand data and information about electricity usage and the status of facilities on our system. Although this technology is still in the developmental stage, CenterPoint Houston believes it has the potential to enable customers of the REPs to better monitor and control their usage of electricity as well as offer a significant improvement in metering, grid planning, operations and maintenance of the CenterPoint Houston distribution system. These improvements would be expected to contribute to fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. In May 2007, the Texas Utility Commission issued rules establishing minimum functionality requirements for an AMS and a surcharge mechanism to enable timely recovery of the costs of implementation. To date, CenterPoint Houston has deployed approximately 10,000 advanced meters and utilized broadband over power line technology as part of a limited deployment to help in proving the technology and in validating its potential benefits prior to a full-scale implementation. CenterPoint Houston would be required to file its deployment plan for approval by the Texas Utility Commission prior to full scale implementation of this technology.


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Competition
 
There are no other electric transmission and distribution utilities in CenterPoint Houston’s service area. In order for another provider of transmission and distribution services to provide such services in CenterPoint Houston’s territory, it would be required to obtain a certificate of convenience and necessity from the Texas Utility Commission and, depending on the location of the facilities, may also be required to obtain franchises from one or more municipalities. We know of no other party intending to enter this business in CenterPoint Houston’s service area at this time.
 
Seasonality
 
A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each REP based on the amount of electricity it distributes on behalf of such REP. 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.
 
Properties
 
All of CenterPoint Houston’s properties are located in Texas. Its properties consist primarily of high voltage electric transmission lines and poles, distribution lines, substations, service wires and meters. Most of CenterPoint Houston’s transmission and distribution lines have been constructed over lands of others pursuant to easements or along public highways and streets as permitted by law.
 
All real and tangible properties of CenterPoint Houston, subject to certain exclusions, are currently subject to:
 
  •  the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and
 
  •  the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.
 
As of December 31, 2007, CenterPoint Houston had outstanding $2.0 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is 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 under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which CenterPoint Energy is 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.
 
Electric Lines — Overhead.  As of December 31, 2007, CenterPoint Houston owned 27,421 pole miles of overhead distribution lines and 3,738 circuit miles of overhead transmission lines, including 424 circuit miles operated at 69,000 volts, 2,098 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.
 
Electric Lines — Underground.  As of December 31, 2007, CenterPoint Houston owned 18,955 circuit miles of underground distribution lines and 28.4 circuit miles of underground transmission lines, including 4.5 circuit miles operated at 69,000 volts and 23.9 circuit miles operated at 138,000 volts.
 
Substations.  As of December 31, 2007, CenterPoint Houston owned 229 major substation sites having total installed rated transformer capacity of 50,586 megavolt amperes.
 
Service Centers.  CenterPoint Houston operates 14 regional service centers located on a total of 291 acres of land. These service centers consist of office buildings, warehouses and repair facilities that are used in the business of transmitting and distributing electricity.


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Franchises
 
CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for the payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 50 years.
 
Natural Gas Distribution
 
CERC Corp.’s natural gas distribution business (Gas Operations) engages in regulated intrastate natural gas sales to, and natural gas transportation for, approximately 3.2 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. The largest metropolitan areas served in each state by Gas Operations are Houston, Texas; Minneapolis, Minnesota; Little Rock, Arkansas; Shreveport, Louisiana; Biloxi, Mississippi; and Lawton, Oklahoma. In 2007, approximately 43% of Gas Operations’ total throughput was attributable to residential customers and approximately 57% was attributable to commercial and industrial customers.
 
Gas Operations also provides unregulated services consisting of heating, ventilating and air conditioning (HVAC) equipment and appliance repair, and sales of HVAC, hearth and water heating equipment in Minnesota.
 
The demand for intrastate natural gas sales to, and natural gas transportation for, residential, commercial and industrial customers is seasonal. In 2007, approximately 71% of the total throughput of Gas Operations’ business occurred in the first and fourth quarters. These patterns reflect the higher demand for natural gas for heating purposes during those periods.
 
Supply and Transportation.  In 2007, Gas Operations purchased virtually all of its natural gas supply pursuant to contracts with remaining terms varying from a few months to four years. Major suppliers in 2007 included BP Canada Energy Marketing Corp. (21.0% of supply volumes), Oneok Energy Marketing (14.7%), Energy Transfer (10.3%), Coral Energy Resources (9.8%) and Tenaska Marketing Ventures (7.8%). Numerous other suppliers provided the remaining 36.4% of Gas Operations’ natural gas supply requirements. Gas Operations transports its natural gas supplies through various intrastate and interstate pipelines, including those owned by our other subsidiaries, under contracts with remaining terms, including extensions, varying from one to fifteen years. Gas Operations anticipates that these gas supply and transportation contracts will be renewed or replaced prior to their expiration.
 
We actively engage in commodity price stabilization pursuant to annual gas supply plans presented to and/or filed with each of our state regulatory authorities. These price stabilization activities include use of storage gas, contractually establishing fixed prices with our physical gas suppliers and utilizing financial derivative instruments to achieve a variety of pricing structures (e.g., fixed price, costless collars, and caps). Our gas supply plans generally call for 25-50% of winter supplies to be hedged in some fashion.
 
Generally, the regulations of the states in which Gas Operations operates allow it to pass through changes in the cost of natural gas, including gains and losses on financial derivatives associated with the index-priced physical supply, to its customers under purchased gas adjustment provisions in its tariffs. Depending upon the jurisdiction, the purchased gas adjustment factors are updated periodically, ranging from monthly to semi-annually, using estimated gas costs. The changes in the cost of gas billed to customers are subject to review by the applicable regulatory bodies.
 
Gas Operations uses various third-party storage services or owned natural gas storage facilities to meet peak-day requirements and to manage the daily changes in demand due to changes in weather and may also supplement contracted supplies and storage from time to time with stored liquefied natural gas and propane-air plant production.
 
Gas Operations owns and operates an underground natural gas storage facility with a capacity of 7.0 billion cubic feet (Bcf). It has a working capacity of 2.0 Bcf available for use during a normal heating season and a maximum daily withdrawal rate of 50 million cubic feet (MMcf). It also owns nine propane-air plants with a total


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production rate of 200 MMcf per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns liquefied natural gas plant facilities with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72 MMcf per day.
 
On an ongoing basis, Gas Operations enters into contracts to provide sufficient supplies and pipeline capacity to meet its customer requirements. However, it is possible for limited service disruptions to occur from time to time due to weather conditions, transportation constraints and other events. As a result of these factors, supplies of natural gas may become unavailable from time to time, or prices may increase rapidly in response to temporary supply constraints or other factors.
 
Assets
 
As of December 31, 2007, Gas Operations owned approximately 69,000 linear miles of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by Gas Operations, it owns the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which Gas Operations receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on the land owned by suppliers.
 
Competition
 
Gas Operations competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Gas Operations’ facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.
 
Competitive Natural Gas Sales and Services
 
CERC offers variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities through CenterPoint Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy Intrastate Pipeline LLC (CEIP).
 
In 2007, CES marketed approximately 522 Bcf of natural gas, transportation and related energy services to approximately 7,000 customers (including approximately 9 Bcf to affiliates). CES customers vary in size from small commercial customers to large utility companies in the central and eastern regions of the United States, and are served from offices located in Illinois, Indiana, Louisiana, Minnesota, Missouri, Pennsylvania, Texas and Wisconsin. The business has three operational functions: wholesale, retail and intrastate pipelines, which are further described below.
 
Wholesale Operations.  CES offers a portfolio of physical delivery services and financial products designed to meet wholesale customers’ supply and price risk management needs. These customers are served directly through interconnects with various inter- and intra-state pipeline companies, and include gas utilities, large industrial customers and electric generation customers.
 
Retail Operations.  CES offers a variety of natural gas management services to smaller commercial and industrial customers, municipalities, educational institutions and hospitals, whose facilities are located downstream of natural gas distribution utility city gate stations. These services include load forecasting, supply acquisition, daily swing volume management, invoice consolidation, storage asset management, firm and interruptible transportation administration and forward price management. CES manages transportation contracts and energy supply for retail customers in sixteen states.
 
Intrastate Pipeline Operations.  CEIP primarily provides transportation services to shippers and end-users and contracts out approximately 2 Bcf of storage at its Pierce Junction facility in Texas.


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CES currently transports natural gas on over 34 interstate and intrastate pipelines within states located throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.
 
As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers’ purchase commitments. These supply imbalances arise each month as customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES’ processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES’ exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate Value at Risk (VaR). In 2007, CES’ VaR averaged $1.2 million with a high of $2.6 million.
 
The CenterPoint Energy risk control policy, governed by our Risk Oversight Committee, defines authorized and prohibited trading instruments and trading limits. CES is a physical marketer of natural gas and uses a variety of tools, including pipeline and storage capacity, financial instruments and physical commodity purchase contracts to support its sales. The CES business optimizes its use of these various tools to minimize its supply costs and does not engage in proprietary or speculative commodity trading. The VaR limits within which CES operates are consistent with its operational objective of matching its aggregate sales obligations (including the swing associated with load following services) with its supply portfolio in a manner that minimizes its total cost of supply.
 
Assets
 
CEIP owns and operates approximately 217 miles of intrastate pipeline in Louisiana and Texas and holds storage facilities of approximately 2 Bcf in Texas under long-term leases. In addition, CES leases transportation capacity of approximately 725 MMcf per day on various inter- and intrastate pipelines and approximately 8.5 Bcf of storage to service its customer base.
 
Competition
 
CES competes with regional and national wholesale and retail gas marketers including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.
 
Interstate Pipelines
 
CERC’s pipelines business operates interstate natural gas pipelines with gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC’s interstate pipeline operations are primarily conducted by two wholly owned subsidiaries that provide gas transportation and storage services primarily to industrial customers and local distribution companies:
 
  •  CenterPoint Energy Gas Transmission Company (CEGT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas; and
 
  •  CenterPoint Energy-Mississippi River Transmission Corporation (MRT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas and Missouri.
 
The rates charged by CEGT and MRT for interstate transportation and storage services are regulated by the FERC. Our interstate pipelines business operations may be affected by changes in the demand for natural gas, the


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available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.
 
In 2007, approximately 20% of CEGT and MRT’s total operating revenue was attributable to services provided to Gas Operations and approximately 10% was attributable to services provided to Laclede Gas Company (Laclede), an unaffiliated distribution company that provides natural gas utility service to the greater St. Louis metropolitan area in Illinois and Missouri. Services to Gas Operations and Laclede are provided under several long-term firm storage and transportation agreements. Since October 31, 2006, MRT’s contract with Laclede has been terminable upon one year’s prior notice. MRT has not received a termination notice and is currently negotiating a long-term contract with Laclede. Agreements for firm transportation, “no notice” transportation service and storage service in certain of Gas Operations’ service areas (Arkansas, Louisiana and Oklahoma) expire in 2012.
 
Carthage to Perryville.  In April 2007, CEGT, a wholly owned subsidiary of CERC Corp., completed phase one construction of 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. On May 1, 2007, CEGT began service under its firm transportation agreements with shippers of approximately 960 MMcf per day. CEGT’s second phase of the project, which involved adding compression that increased the total capacity of the pipeline to approximately 1.25 Bcf per day, was placed into service in August 2007. CEGT has signed firm contracts for the full capacity of phases one and two.
 
In May 2007, CEGT received FERC approval for the third phase of the project to expand capacity of the pipeline to 1.5 Bcf per day by adding additional compression and operating at higher pressures, and 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, which CEGT expects to satisfy in the first quarter of 2008. CEGT has executed contracts for approximately 150 MMcf per day of the 250 MMcf per day phase three expansion. The third phase is projected to be in-service in the second quarter of 2008.
 
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. CEGT excavated and inspected certain welds at the request of the PHMSA, and in each case, CEGT found those welds to be structurally sound. Although its investigation has not been formally concluded, CEGT has worked closely with the appropriate regulatory authorities to determine and take all necessary actions. To date, CEGT has found no reason to modify the operation of its Carthage to Perryville line or take other significant action, and no such action has been directed or requested by any governmental authority. Absent new evidence, CEGT believes that no significant action by CEGT will be necessary and that the Carthage to Perryville line can be operated at expected operating pressures without threat to the public health or safety and does not plan to take any significant additional action.
 
Southeast Supply Header.  In June 2006, CenterPoint Energy Southeast Pipelines Holding, L.L.C., a wholly owned subsidiary of CERC Corp., and a subsidiary of Spectra Energy Corp. (Spectra) formed a joint venture (Southeast Supply Header or SESH) to construct, own and operate a 270-mile pipeline with a capacity of approximately 1 Bcf per day that will extend from CEGT’s Perryville hub in northeast Louisiana to an interconnection in southern Alabama with Gulfstream Natural Gas System, which is 50% owned by an affiliate of Spectra. We account for our 50% interest in SESH as an equity investment. In 2006, SESH signed agreements with shippers for firm transportation services, which subscribed capacity of 945 MMcf per day. Additionally, SESH and Southern Natural Gas (SNG) have executed a definitive agreement that provides for SNG to jointly own the first 115 miles of


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the pipeline. Under the agreement, SNG will own an undivided interest in the portion of the pipeline from Perryville, Louisiana to an interconnect with SNG in Mississippi. The pipe diameter was increased from 36 inches to 42 inches, thereby increasing the initial capacity of 1 Bcf per day by 140 MMcf per day to accommodate SNG. SESH will own assets providing approximately 1 Bcf per day of capacity as initially planned and will maintain economic expansion opportunities in the future. SNG will own assets providing 140 MMcf per day of capacity, and the agreement provides for a future compression expansion that will increase the jointly owned capacity up to 500 MMcf per day, subject to FERC approval.
 
An application to construct, own and operate the pipeline was filed with the FERC in December 2006. In September 2007, the FERC issued the certificate authorizing the construction of the pipeline. This FERC approval does not include the expansion capacity that would take SNG to 500 MMcf per day. SESH began construction in November 2007. SESH expects to complete construction of the pipeline as approved by the FERC in the second half of 2008. SESH’s net costs after SNG’s contribution are estimated to have increased to approximately $1 billion.
 
Assets
 
Our interstate pipelines business currently owns and operates approximately 8,100 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. It also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf per day and a combined working gas capacity of approximately 59.0 Bcf. It also owns a 10% interest in the Bistineau storage facility located in Bienville Parish, Louisiana, with the remaining interest owned and operated by Gulf South Pipeline Company, LP. This facility has a total working gas capacity of 85.7 Bcf and approximately 1.1 Bcf per day of deliverability. Storage capacity in the Bistineau facility is 8 Bcf of working gas with 100 MMcf per day of deliverability. Most storage operations are in north Louisiana and Oklahoma.
 
Competition
 
Our interstate pipelines business competes with other interstate and intrastate pipelines in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service, and flexibility and reliability of service. Our interstate pipelines business competes indirectly with other forms of energy available to our customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for transportation and storage services.
 
Field Services
 
CERC’s field services business operates gas gathering, treating, and processing facilities and also provides operating and technical services and remote data monitoring and communication services.
 
CERC’s field services operations are conducted by a wholly owned subsidiary, CenterPoint Energy Field Services, Inc. (CEFS). CEFS provides natural gas gathering and processing services for certain natural gas fields in the Mid-continent region of the United States that interconnect with CEGT’s and MRT’s pipelines, as well as other interstate and intrastate pipelines. CEFS gathers approximately 1.1 Bcf per day of natural gas and, either directly or through its 50% interest in the Waskom Joint Venture, processes in excess of 240 MMcf per day of natural gas along its gathering system. CEFS, through its ServiceStar operating division, provides remote data monitoring and communications services to affiliates and third parties. As of the end of 2007, ServiceStar provided monitoring activities at approximately 12,500 locations across Alabama, Arkansas, Colorado, Illinois, Kansas, Louisiana, Mississippi, Missouri, New Mexico, Oklahoma, Texas and Wyoming, but has reduced that total by approximately 2,300 units in 2008 as a result of an agreement reached between CEFS and ServiceStar’s largest customer to revise certain contractual arrangements between them, including termination of ServiceStar’s monitoring services for that customer.
 
Our field services business operations may be affected by changes in the demand for natural gas, the available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.


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Assets
 
Our field services business owns and operates approximately 3,500 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 151 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
 
Competition
 
Our field services business competes with other companies in the natural gas gathering, treating, and processing business. The principal elements of competition are rates, terms of service and reliability of services. Our field services business competes indirectly with other forms of energy available to our customers, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability of energy and pipeline capacity, the level of business activity, conservation and governmental regulations, the capability to convert to alternative fuels, and other factors, including weather, affect the demand for natural gas in areas we serve and the level of competition for gathering, treating, and processing services. In addition, competition for our gathering operations is impacted by commodity pricing levels because of their influence on the level of drilling activity.
 
Other Operations
 
Our Other Operations business segment includes office buildings and other real estate used in our business operations and other corporate operations that support all of our business operations.
 
Discontinued Operations
 
In July 2004, we announced our agreement to sell our majority owned subsidiary, Texas Genco, to Texas Genco LLC. In December 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed in April 2005.
 
We recorded an after-tax loss of $3 million for the year ended December 31, 2005, related to the operations of Texas Genco. The consolidated financial statements report these operations for all periods presented as discontinued operations in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.”
 
Financial Information About Segments
 
For financial information about our segments, see Note 14 to our consolidated financial statements, which note is incorporated herein by reference.
 
REGULATION
 
We are subject to regulation by various federal, state and local governmental agencies, including the regulations described below.
 
Federal Energy Regulatory Commission
 
The FERC has jurisdiction under the Natural Gas Act and the Natural Gas Policy Act of 1978, as amended, to regulate the transportation of natural gas in interstate commerce and natural gas sales for resale in intrastate commerce that are not first sales. The FERC regulates, among other things, the construction of pipeline and related facilities used in the transportation and storage of natural gas in interstate commerce, including the extension, expansion or abandonment of these facilities. The rates charged by interstate pipelines for interstate transportation and storage services are also regulated by the FERC. The Energy Policy Act of 2005 (Energy Act) expanded the FERC’s authority to prohibit market manipulation in connection with FERC-regulated transactions and gave the FERC additional authority to impose significant civil and criminal penalties for statutory violations and violations


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of the FERC’s rules or orders and also expanded criminal penalties for such violations. Our competitive natural gas sales and services subsidiary markets natural gas in interstate commerce pursuant to blanket authority granted by the FERC.
 
Our natural gas pipeline subsidiaries may periodically file applications with the FERC for changes in their generally available maximum rates and charges designed to allow them to recover their costs of providing service to customers (to the extent allowed by prevailing market conditions), including a reasonable rate of return. These rates are normally allowed to become effective after a suspension period and, in some cases, are subject to refund under applicable law until such time as the FERC issues an order on the allowable level of rates.
 
CenterPoint Houston is not a “public utility” under the Federal Power Act and therefore is not generally regulated by the FERC, although certain of its transactions are subject to limited FERC jurisdiction. The Energy Act conferred new jurisdiction and responsibilities on the FERC with respect to ensuring the reliability of electric transmission service, including transmission facilities owned by CenterPoint Houston and other utilities within ERCOT. Under this authority, the FERC has designated the NERC as the Electric Reliability Organization (ERO) to promulgate standards, under FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to impose fines and other sanctions on Electric Entities that fail to comply with the standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the Texas Regional Entity, a division of ERCOT. CenterPoint Houston does not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on its operations. To the extent that CenterPoint Houston is required to make additional expenditures to comply with these standards, it is anticipated that CenterPoint Houston will seek to recover those costs through the transmission charges that are imposed on all distribution service providers within ERCOT for electric transmission provided.
 
Under the Public Utility Holding Company Act of 2005 (PUHCA 2005), the FERC has authority to require holding companies and their subsidiaries to maintain certain books and records and make them available for review by the FERC and state regulatory authorities in certain circumstances. In December 2005, the FERC issued rules implementing PUHCA 2005. Pursuant to those rules, in June 2006, we filed with the FERC the required notification of our status as a public utility holding company. In October 2006, the FERC adopted additional rules regarding maintenance of books and records by utility holding companies and additional reporting and accounting requirements for centralized service companies that make allocations to public utilities regulated by the FERC under the Federal Power Act. Although we provide services to our subsidiaries through a service company, our service company is not subject to the FERC’s service company rules.
 
State and Local Regulation
 
Electric Transmission & Distribution
 
CenterPoint Houston conducts its operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers its present service area and facilities. The Texas Utility Commission and those municipalities that have retained original jurisdiction have the authority to set the rates and terms of service provided by CenterPoint Houston under cost of service rate regulation. CenterPoint Houston holds non-exclusive franchises from the incorporated municipalities in its service territory. In exchange for payment of fees, these franchises give CenterPoint Houston the right to use the streets and public rights-of-way of these municipalities to construct, operate and maintain its transmission and distribution system and to use that system to conduct its electric delivery business and for other purposes that the franchises permit. The terms of the franchises, with various expiration dates, typically range from 30 to 50 years.
 
CenterPoint Houston’s distribution rates charged to REPs for residential customers are based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are based on peak demand. All REPs in CenterPoint Houston’s service area pay the same rates and other charges for the same transmission and distribution services. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay CenterPoint Houston the same rates and other charges for transmission services. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a system benefit fund fee imposed by the Texas electric restructuring law, a


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nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, transition charges associated with securitization of regulatory assets and securitization of stranded costs, a competition transition charge for collection of the true-up balance not securitized and a rate case expense charge.
 
Recovery of True-Up Balance.  For a discussion of CenterPoint Houston’s true-up proceedings, see “— Our Business — Electric Transmission & Distribution — Recovery of True-Up Balance” above.
 
CenterPoint Houston Rate Agreement.  CenterPoint Houston’s transmission and distribution rates are subject to the terms of a Settlement Agreement effective in October 2006. The Settlement Agreement provides that until June 30, 2010 CenterPoint Houston will not seek to increase its base rates and the other parties will not petition to decrease those rates. The rate freeze is subject to adjustment for certain limited matters, including the results of the appeals of the True-Up Order and the implementation of charges associated with securitizations. CenterPoint Houston must make a new base rate filing not later than June 30, 2010, based on a test year ended December 31, 2009, unless the staff of the Texas Utility Commission and certain cities notify it that such a filing is unnecessary.
 
Natural Gas Distribution
 
In almost all communities in which Gas Operations provides natural gas distribution services, it operates under franchises, certificates or licenses obtained from state and local authorities. The original terms of the franchises, with various expiration dates, typically range from 10 to 30 years, although franchises in Arkansas are perpetual. Gas Operations expects to be able to renew expiring franchises. In most cases, franchises to provide natural gas utility services are not exclusive.
 
Substantially all of Gas Operations is subject to cost-of-service regulation by the relevant state public utility commissions and, in Texas, by the Railroad Commission of Texas (Railroad Commission) and those municipalities Gas Operations serves that have retained original jurisdiction.
 
Arkansas.  In January 2007, Gas Operations filed an application with the Arkansas Public Service Commission (APSC) to change its natural gas distribution rates in order to increase its annual base revenues by approximately $51 million. Gas Operations subsequently agreed to reduce its request to approximately $40 million. As part of its filing, Gas Operations also proposed a revenue stabilization tariff (also known as decoupling) that would help stabilize revenues and eliminate the potential conflict between its efforts to earn a reasonable return on invested capital while promoting energy efficiency initiatives.
 
In September 2007, the APSC staff and Gas Operations entered into and filed with the APSC a Stipulation and Settlement Agreement (Settlement Agreement) under which the annual base revenues of Gas Operations would increase by approximately $20 million, and a revenue stabilization tariff would be allowed to go into effect, with an authorized rate of return on equity of 9.65% (reflecting a 10 basis point reduction for the implementation of the revenue stabilization tariff). The other parties to the proceeding agreed not to oppose the Settlement Agreement. In October 2007, the APSC issued an order approving the Settlement Agreement, and the new rates became effective with bills rendered on and after November 1, 2007.
 
Texas.  In December 2006, Gas Operations filed a statement of intent with the Railroad Commission of Texas (Railroad Commission) seeking to implement an increase in miscellaneous service charges and to allow recovery of the costs of financial hedging transactions through its purchased gas cost adjustment in the environs of its Texas Coast service territory. After approval of the filing by the Railroad Commission, the new service charges were implemented in the second quarter of 2007.
 
In response to an explosion resulting from the failure of a certain type of compression coupling on another company’s natural gas distribution system in Texas, the Railroad Commission has begun a rulemaking focusing on leak surveys, leak grading and the replacement of specific types of compression couplings. In addition, the Railroad Commission issued a directive in November 2007 requiring the removal of service risers known to have compression fittings that do not meet certain performance specifications. After reviewing our records as required by the directive, Gas Operations has no indication that we have the type of coupling described in that directive.


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However, at this time we do not know what additional requirements may result from the pending Railroad Commission rulemaking or what impacts on our gas operations may result from any future regulatory initiatives adopted with respect to this issue.
 
In the first quarter of 2008, Gas Operations expects to file a request to change its rates with the Railroad Commission and the 47 cities in its Texas Coast service territory. The request will seek 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 2005, Gas Operations filed a request with the Minnesota Public Utilities Commission (MPUC) to increase annual base rates by approximately $41 million. In December 2005, the MPUC approved an interim rate increase of approximately $35 million that was implemented January 1, 2006. In January 2007, the MPUC issued a final order granting a rate increase of approximately $21 million and approving a $5 million affordability program to assist low-income customers, the actual cost of which will be recovered in rates in addition to the $21 million rate increase. Final rates were implemented beginning May 1, 2007, and Gas Operations completed refunding to customers the proportional share of the excess of the amounts collected in interim rates over the amount allowed by the final order in the second quarter of 2007.
 
In November 2006, the 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.
 
Department of Transportation
 
In December 2002, Congress enacted the Pipeline Safety Improvement Act of 2002 (2002 Act). This legislation applies to our interstate pipelines as well as our intrastate pipeline and local distribution companies. The legislation imposes several requirements related to ensuring pipeline safety and integrity. It requires pipeline and distribution companies to assess the integrity of their pipeline transmission facilities in areas of high population concentration or High Consequence Areas (HCA). The legislation further requires companies to perform remediation activities in accordance with the requirements of the legislation over a 10-year period.
 
In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006, which reauthorized the programs adopted under the 2002 Act, proposed enhancements for state programs to reduce excavation damage to pipelines, established increased federal enforcement of one-call excavation programs, and established a new program for review of pipeline security plans and critical facility inspections. In addition, beginning in October 2005, the PHMSA of the U.S. Department of Transportation (DOT) commenced a rulemaking proceeding to develop rules that would better distinguish onshore gathering lines from production facilities and transmission lines, and to develop safety requirements better tailored to gathering line risks. In March 2006, the DOT revised its regulations to define more clearly the categories of gathering facilities subject to DOT regulation, establish new safety rules for certain gathering lines in rural areas, revise the current regulations applicable to safety and inspection of gathering lines in non-rural areas, and adopt new compliance deadlines.
 
We anticipate that compliance with these regulations by our interstate and intrastate pipelines and our natural gas distribution companies will require increases in both capital and operating costs. The level of expenditures required to comply with these regulations will be dependent on several factors, including the age of the facility, the pressures at which the facility operates and the number of facilities deemed to be located in areas designated as HCA. Based on our interpretation of the rules and preliminary technical reviews, we believe compliance will require average annual expenditures of approximately $15 to $20 million during the initial 10-year period.


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ENVIRONMENTAL MATTERS
 
Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:
 
  •  restricting the way we can handle or dispose of 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.
 
The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.
 
Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position, results of operations or cash flows. In addition, we believe that our current environmental remediation activities will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.
 
Global Climate Change
 
In recent years, there has been increasing public debate regarding the potential impact on global climate change by various “greenhouse gases” such as carbon dioxide, a byproduct of burning fossil fuels, and methane, a component of the natural gas which we transport and deliver to customers. Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally


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and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries such as the utility industry to meet stringent new standards requiring substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. Some proposals would provide for credits to those who reduce emissions below certain levels and would allow those credits to be traded and/or sold to others. It is too early to determine whether, and in what form, a regulatory scheme regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory scheme might have on us and our subsidiaries. However, as a distributor and transporter of natural gas and consumer of natural gas in its pipeline and gathering businesses, CERC’s revenues, operating costs and capital requirements could be adversely affected as a result of any regulatory scheme which would reduce consumption of natural gas if ultimately adopted. Our electric transmission and distribution business, unlike most electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that are in the business of generating electricity. Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory scheme has the effect of reducing consumption of electricity by ultimate consumers within its service territory.
 
Air Emissions
 
Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, including our processing plants and compressor stations, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies.
 
Water Discharges
 
Our operations are subject to the Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws and regulations. These laws and regulations impose detailed requirements and strict controls regarding the discharge of pollutants into waters of the United States. The unpermitted discharge of pollutants, including discharges resulting from a spill or leak incident, is prohibited. The Clean Water Act and regulations implemented thereunder also prohibit discharges of dredged and fill material in wetlands and other waters of the United States unless authorized by an appropriately issued permit. Any unpermitted release of petroleum or other pollutants from our pipelines or facilities could result in fines or penalties as well as significant remedial obligations.
 
Hazardous Waste
 
Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (RCRA), and comparable state laws, which impose detailed requirements for the handling, storage, treatment and disposal of hazardous and solid waste. RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste waters produced and other wastes associated with the exploration, development, or production of crude oil and natural gas. However, these oil and gas exploration and production wastes are still regulated under state law and the less stringent non-hazardous waste requirements of RCRA. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste. The transportation of natural gas in pipelines may also generate some hazardous wastes that would be subject to RCRA or comparable state law requirements.


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Liability for Remediation
 
The Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (CERCLA), also known as “Superfund,” and comparable state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons responsible for the release of hazardous substances into the environment. Such classes of persons include the current and past owners or operators of sites where a hazardous substance was released and companies that disposed or arranged for the disposal of hazardous substances at offsite locations such as landfills. Although petroleum, as well as natural gas, is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations we generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the United States Environmental Protection Agency (EPA) and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.
 
Liability for Preexisting Conditions
 
Hydrocarbon Contamination.  CERC Corp. and certain of its subsidiaries were among the defendants in lawsuits filed beginning in August 2001 in Caddo Parish and Bossier Parish, Louisiana. The suits alleged that, at some unspecified date prior to 1985, the defendants allowed or caused hydrocarbon or chemical contamination of the Wilcox Aquifer, which lies beneath property owned or leased by certain of the defendants and which is the sole or primary drinking water aquifer in the area. The primary source of the contamination was alleged by the plaintiffs to be a gas processing facility in Haughton, Bossier Parish, Louisiana known as the “Sligo Facility,” which was formerly operated by a predecessor in interest of CERC Corp. This facility was purportedly used for gathering natural gas from surrounding wells, separating liquid hydrocarbons from the natural gas for marketing, and transmission of natural gas for distribution.
 
In July 2007, the parties implemented the terms of an agreed settlement and resolved this matter. Pursuant to the agreed terms, a CERC Corp. subsidiary entered into a cooperative agreement with the Louisiana Department of Environmental Quality (LDEQ), pursuant to which CERC Corp.’s subsidiary will work with the LDEQ to develop a remediation plan that could be implemented by the CERC Corp. subsidiary. As part of the settlement, CERC made a payment within the amounts previously reserved for this matter. We and CERC do not expect the costs associated with the resolution of this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.
 
Manufactured Gas Plant Sites.  CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.
 
At December 31, 2007, CERC had accrued $14 million for remediation of these Minnesota sites. At December 31, 2007, 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 December 31, 2007, 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 EPA 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


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responsible parties, including CERC, would have to contribute to that remediation. We are investigating details regarding this 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 CERCLA and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP.
 
Mercury Contamination.  Our pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. We have found this type of contamination at some sites in the past, and we have conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs is not known at this time, based on our experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, we believe that the costs of any remediation of these sites will not be material to our financial condition, results of operations or cash flows.
 
Asbestos.  Some of our facilities contain or have contained asbestos insulation and other asbestos-containing materials. We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by our subsidiaries. We anticipate that additional claims like those received may be asserted in the future. In 2004, we sold our 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 us and our sale of this business 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 we maintain, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, we intend to continue vigorously contesting claims that we do not consider to have merit and do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.
 
Other Environmental.  From time to time we have received notices from regulatory authorities or others regarding our status as a PRP in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, we have 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, we do not expect, based on our experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on our financial condition, results of operations or cash flows.
 
EMPLOYEES
 
As of December 31, 2007, we had 8,568 full-time employees. The following table sets forth the number of our employees by business segment:
 
                 
          Number
 
          Represented
 
          by Unions or
 
          Other Collective
 
Business Segment
  Number     Bargaining Groups  
 
Electric Transmission & Distribution
    2,746       1,194  
Natural Gas Distribution
    3,685       1,412  
Competitive Natural Gas Sales and Services
    117        
Interstate Pipelines
    611        
Field Services
    196        
Other Operations
    1,213        
                 
Total
    8,568       2,606  
                 


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As of December 31, 2007, approximately 30% of our employees are subject to collective bargaining agreements. We have four collective bargaining agreements, (1) United Steel Workers (USW) Local 13-227, (2) Office and Professional Employees International Union (OPEIU) Local 12 Metro, (3) OPEIU Local 12 Mankato, and (4) USW Local 13-1, that are scheduled to expire in 2008 that collectively cover approximately 8% of our employees. We have a good relationship with these bargaining units and expect to renegotiate new agreements in 2008.
 
EXECUTIVE OFFICERS
(as of February 28, 2008)
 
             
Name
 
Age
 
Title
 
David M. McClanahan
    58     President and Chief Executive Officer and Director
Scott E. Rozzell
    58     Executive Vice President, General Counsel and Corporate Secretary
Gary L. Whitlock
    58     Executive Vice President and Chief Financial Officer
Walter L. Fitzgerald
    50     Senior Vice President and Chief Accounting Officer
Byron R. Kelley
    60     Senior Vice President and Group President, CenterPoint Energy Pipelines and Field Services
Thomas R. Standish
    58     Senior Vice President and Group President — Regulated Operations
 
David M. McClanahan has been President and Chief Executive Officer and a director of CenterPoint Energy since September 2002. He served as Vice Chairman of Reliant Energy, Incorporated (Reliant Energy) from October 2000 to September 2002 and as President and Chief Operating Officer of Reliant Energy’s Delivery Group from April 1999 to September 2002. He has served in various executive capacities with CenterPoint Energy since 1986. He previously served as Chairman of the Board of Directors of ERCOT and Chairman of the Board of the University of St. Thomas in Houston. He currently serves on the board of the Edison Electric Institute and as the Chairman of the Board of Directors of the American Gas Association.
 
Scott E. Rozzell has served as Executive Vice President, General Counsel and Corporate Secretary of CenterPoint Energy since September 2002. He served as Executive Vice President and General Counsel of the Delivery Group of Reliant Energy from March 2001 to September 2002. Before joining CenterPoint Energy in 2001, Mr. Rozzell was a senior partner in the law firm of Baker Botts L.L.P. He currently serves on the Board of Directors of the Association of Electric Companies of Texas.
 
Gary L. Whitlock has served as Executive Vice President and Chief Financial Officer of CenterPoint Energy since September 2002. He served as Executive Vice President and Chief Financial Officer of the Delivery Group of Reliant Energy from July 2001 to September 2002. Mr. Whitlock served as the Vice President, Finance and Chief Financial Officer of Dow AgroSciences, a subsidiary of The Dow Chemical Company, from 1998 to 2001.
 
Walter L. Fitzgerald has served as Senior Vice President and Chief Accounting Officer of CenterPoint Energy since December 2007. He served as Vice President and Controller from October 2001 to December 2007. Before joining CenterPoint Energy in 2001, Mr. Fitzgerald was Controller of DuPont Dow Elastomers, from 1997 to 2001.
 
Byron R. Kelley has served as Senior Vice President and Group President of CenterPoint Energy Pipelines and Field Services since June 2004, having previously served as President and Chief Operating Officer of CenterPoint Energy Pipelines and Field Services from May 2003 to June 2004. Prior to joining CenterPoint Energy he served as President of El Paso International, a subsidiary of El Paso Corporation, from January 2001 to August 2002. He currently serves on the Board of Directors of the Interstate Natural Gas Association of America.
 
Thomas R. Standish has served as Senior Vice President and Group President-Regulated Operations of CenterPoint Energy since August 2005, having previously served as Senior Vice President and Group President and Chief Operating Officer of CenterPoint Houston from June 2004 to August 2005 and as President and Chief


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Operating Officer of CenterPoint Houston from August 2002 to June 2004. He served as President and Chief Operating Officer for both electricity and natural gas for Reliant Energy’s Houston area from 1999 to August 2002. Mr. Standish has served in various executive capacities with CenterPoint Energy since 1993.
 
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


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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.


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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


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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,


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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;


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  •  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.


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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.


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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


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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.
 
Item 1B.   Unresolved Staff Comments
 
Not applicable.
 
Item 2.   Properties
 
Character of Ownership
 
We own or lease our principal properties in fee, including our corporate office space and various real property. Most of our electric lines and gas mains are located, pursuant to easements and other rights, on public roads or on land owned by others.
 
Electric Transmission & Distribution
 
For information regarding the properties of our Electric Transmission & Distribution business segment, please read “Business — Our Business — Electric Transmission & Distribution — Properties” in Item 1 of this report, which information is incorporated herein by reference.


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Natural Gas Distribution
 
For information regarding the properties of our Natural Gas Distribution business segment, please read “Business — Our Business — Natural Gas Distribution — Assets” in Item 1 of this report, which information is incorporated herein by reference.
 
Competitive Natural Gas Sales and Services
 
For information regarding the properties of our Competitive Natural Gas Sales and Services business segment, please read “Business — Our Business — Competitive Natural Gas Sales and Services — Assets” in Item 1 of this report, which information is incorporated herein by reference.
 
Interstate Pipelines
 
For information regarding the properties of our Interstate Pipelines business segment, please read “Business — Our Business — Interstate Pipelines — Assets” in Item 1 of this report, which information is incorporated herein by reference.
 
Field Services
 
For information regarding the properties of our Field Services business segment, please read “Business — Our Business — Field Services — Assets” in Item 1 of this report, which information is incorporated herein by reference.
 
Other Operations
 
For information regarding the properties of our Other Operations business segment, please read “Business — Our Business — Other Operations” in Item 1 of this report, which information is incorporated herein by reference.
 
Item 3.   Legal Proceedings
 
For a discussion of material legal and regulatory proceedings affecting us, please read “Business — Regulation” and “Business — Environmental Matters” in Item 1 of this report and Notes 4 and 10(d) to our consolidated financial statements, which information is incorporated herein by reference.
 
Item 4.   Submission of Matters to a Vote of Security Holders
 
There were no matters submitted to the vote of our security holders during the fourth quarter of 2007.
 
PART II
 
Item 5.   Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
 
As of February 15, 2008, our common stock was held of record by approximately 49,092 shareholders. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol “CNP.”


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The following table sets forth the high and low closing prices of the common stock of CenterPoint Energy on the New York Stock Exchange composite tape during the periods indicated, as reported by Bloomberg, and the cash dividends declared in these periods.
 
                         
                Dividend
 
    Market Price     Declared
 
    High     Low     per Share  
 
2006
                       
First Quarter
                  $ 0.15  
January 19
  $ 13.28                  
March 27
          $ 11.92          
Second Quarter
                  $ 0.15  
April 12
          $ 11.73          
June 30
  $ 12.50                  
Third Quarter
                  $ 0.15  
July 3
          $ 12.55          
September 1
  $ 14.55                  
Fourth Quarter
                  $ 0.15  
October 2
          $ 14.22          
December 27
  $ 16.80                  
2007
                       
First Quarter
                  $ 0.17  
January 18
          $ 16.51          
February 26
  $ 18.37                  
Second Quarter
                  $ 0.17  
May 9
  $ 20.02                  
June 22
          $ 16.90          
Third Quarter
                  $ 0.17  
July 13
  $ 17.88                  
August 15
          $ 15.15          
Fourth Quarter
                  $ 0.17  
October 19
          $ 15.97          
November 8
  $ 18.51                  
 
The closing market price of our common stock on December 31, 2007 was $17.13 per share.
 
The amount of future cash dividends will be subject to determination based upon our results of operations and financial condition, our future business prospects, any applicable contractual restrictions and other factors that our board of directors considers relevant and will be declared at the discretion of the board of directors.
 
On January 24, 2008, we announced a regular quarterly cash dividend of $0.1825 per share, payable on March 10, 2008 to shareholders of record on February 15, 2008.
 
Repurchases of Equity Securities
 
During the quarter ended December 31, 2007, none of our equity securities registered pursuant to Section 12 of the Securities Exchange Act of 1934 were purchased by or on behalf of us or any of our “affiliated purchasers,” as defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934.


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Conversion of 3.75% Convertible Senior Notes due 2023
 
Since December 31, 2007, we have issued 4,145,377 shares of our common stock upon conversion of approximately $123 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  
 
January 2, 2008
  $ 89,056,000       3,005,043 (1)
January 3, 2008
    5,000,000       168,063 (1)
January 7, 2008
    4,000       357 (2)
January 8, 2008
    1,780,000       159,199 (2)
January 14, 2008
    10,000,000       311,086 (1)
January 17, 2008
    4,073,000       123,929 (1)
January 23, 2008
    247,000       7,330 (1)
January 24, 2008
    12,520,000       370,150 (1)
February 5, 2008
    4,000       105 (1)
February 19, 2008
    1,000       89 (2)
February 20, 2008
    1,000       26 (1)
                 
    $ 122,686,000       4,145,377  
                 
 
 
(1) 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.
 
(2) Based on terms of the notes, settled entirely through the issuance of shares except for a payment of cash in lieu of fractional shares.
 
As a result of a February 2008 conversion election by a holder of $10 million principal amount of our 3.75% Convertible Senior Notes due 2023, additional shares of our common stock are expected to be issued in March 2008 to settle the amount due to the converting holder in excess of the principal amount which must be settled in cash.
 
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.
 
Common Stock Award to Chairman
 
In May 2007, we awarded Milton Carroll 25,000 shares of our common stock pursuant to an agreement under which he serves as Chairman of our Board of Directors. We relied on the private placement exemption from registration under Section 4(2) of the Securities Act of 1933.


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Item 6.   Selected Financial Data
 
The following table presents selected financial data with respect to our consolidated financial condition and consolidated results of operations and should be read in conjunction with our consolidated financial statements and the related notes in Item 8 of this report.
 
                                         
    Year Ended December 31,  
    2003(1)     2004(2)     2005(3)     2006     2007  
    (In millions, except per share amounts)  
 
Revenues
  $ 7,790     $ 7,999     $ 9,722     $ 9,319     $ 9,623  
                                         
Income from continuing operations before extraordinary item
    409       205       225       432       399  
Discontinued operations, net of tax
    75       (133 )     (3 )            
Extraordinary item, net of tax
          (977 )     30              
                                         
Net income (loss)
  $ 484     $ (905 )   $ 252     $ 432     $ 399  
                                         
Basic earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 1.35     $ 0.67     $ 0.72     $ 1.39     $ 1.25  
Discontinued operations, net of tax
    0.24       (0.43 )     (0.01 )            
Extraordinary item, net of tax
          (3.18 )     0.10              
                                         
Basic earnings (loss) per common share
  $ 1.59     $ (2.94 )   $ 0.81     $ 1.39     $ 1.25  
                                         
Diluted earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 1.24     $ 0.61     $ 0.67     $ 1.33     $ 1.17  
Discontinued operations, net of tax
    0.22       (0.37 )     (0.01 )            
Extraordinary item, net of tax
          (2.72 )     0.09              
                                         
Diluted earnings (loss) per common share
  $ 1.46     $ (2.48 )   $ 0.75     $ 1.33     $ 1.17  
                                         
Cash dividends paid per common share
  $ 0.40     $ 0.40     $ 0.40     $ 0.60     $ 0.68  
Dividend payout ratio from continuing operations
    30%       60%       56%       43%       54%  
Return from continuing operations on average common equity
    25.7%       14.4%       18.7%       30.3%       23.7%  
Ratio of earnings from continuing operations to fixed charges
    1.81       1.43       1.51       1.77       1.86  
At year-end:
                                       
Book value per common share
  $ 5.77     $ 3.59     $ 4.18     $ 4.96     $ 5.61  
Market price per common share
    9.69       11.30       12.85       16.58       17.13  
Market price as a percent of book value
    168%       315%       307%       334%       305%  
Assets of discontinued operations
  $ 4,244     $ 1,565     $     $     $  
Total assets
    21,461       18,096       17,116       17,633       17,872  
Short-term borrowings(4)
    63                   187       232  
Transition bonds, including current maturities
    717       676       2,480       2,407       2,260  
Other long-term debt, including current maturities
    10,222       8,353       6,427       6,593       7,419  
Capitalization:
                                       
Common stock equity
    14%       11%       13%       15%       16%  
Long-term debt, including current maturities
    86%       89%       87%       85%       84%  
Capitalization, excluding transition bonds:
                                       
Common stock equity
    15%       12%       17%       19%       20%  
Long-term debt, excluding transition bonds, including current maturities
    85%       88%       83%       81%       80%  
Capital expenditures, excluding discontinued operations
  $ 497     $ 530     $ 719     $ 1,121     $ 1,011  


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(1) Net income for 2003 includes the cumulative effect of an accounting change resulting from the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, “Accounting for Asset Retirement Obligations” ($80 million after-tax gain, or $0.26 and $0.24 earnings per basic and diluted share, respectively), which is included in discontinued operations related to Texas Genco Holdings, Inc. (Texas Genco).
 
(2) Net income for 2004 includes an after-tax extraordinary loss of $977 million ($3.18 and $2.72 loss per basic and diluted share, respectively) based on our analysis of the Public Utility Commission of Texas’ (Texas Utility Commission) order in the 2004 True-Up Proceeding. Additionally, we recorded a net after-tax loss of approximately $133 million ($0.43 and $0.37 loss per basic and diluted share, respectively) in 2004 related to our interest in Texas Genco.
 
(3) Net income for 2005 includes an after-tax extraordinary gain of $30 million ($0.10 and $0.09 per basic and diluted share, respectively) recorded in the first quarter reflecting an adjustment to the extraordinary loss recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.
 
(4) In October 2006, CERC amended its receivables facility. Under the terms of the amended receivables facility, the provisions for sale accounting under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” were no longer met. Accordingly, advances received upon the sale of receivables are accounted for as short-term borrowings as of December 31, 2006 and 2007.
 
Item 7.   Management’s Discussion and Analysis of Financial Condition and Results of Operations
 
The following discussion and analysis should be read in combination with our consolidated financial statements included in Item 8 herein.
 
OVERVIEW
 
Background
 
We are a public utility holding company whose indirect wholly owned subsidiaries include:
 
  •  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 Corp. 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.
 
Business Segments
 
In this section, we discuss our results from continuing operations on a consolidated basis and individually for each of our business segments. We also discuss our liquidity, capital resources and critical accounting policies. We are first and foremost an energy delivery company and it is our intention to remain focused on this segment of the energy business. The results of our business operations are significantly impacted by weather, customer growth, cost management, rate proceedings before regulatory agencies and other actions of the various regulatory agencies to which we are subject. Our electric transmission and distribution services are subject to rate regulation and are reported in the Electric Transmission & Distribution business segment, as are impacts of generation-related stranded costs and other true-up balances recoverable by the regulated electric utility. Our natural gas distribution


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services are also subject to rate regulation and are reported in the Natural Gas Distribution business segment. A summary of our reportable business segments as of December 31, 2007 is set forth below:
 
Electric Transmission & Distribution
 
Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving approximately 2.0 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.5 million people and includes Houston.
 
On behalf of REPs, CenterPoint Houston delivers electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout the control area managed by the Electric Reliability Council of Texas (ERCOT), which serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally owned electric utilities, rural electric cooperatives, independent generators, power marketers and REPs. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Texas Utility Commission.
 
Natural Gas Distribution
 
CERC owns and operates our regulated natural gas distribution business, which engages in intrastate natural gas sales to, and natural gas transportation for, approximately 3.2 million residential, commercial and industrial customers in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas.
 
Competitive Natural Gas Sales and Services
 
CERC’s operations also include non-rate regulated retail and wholesale natural gas sales to, and transportation services for, commercial and industrial customers in the six states listed above as well as several other Midwestern and Eastern states.
 
Interstate Pipelines
 
CERC’s interstate pipelines business owns and operates approximately 8,100 miles of gas transmission lines primarily located in Arkansas, Louisiana, Missouri, Oklahoma and Texas. This business also owns and operates six natural gas storage fields with a combined daily deliverability of approximately 1.2 billion cubic feet (Bcf) per day and a combined working gas capacity of approximately 59.0 Bcf. Most storage operations are in north Louisiana and Oklahoma. This business has recently completed the first two phases of its Carthage to Perryville pipeline in 2007 adding over 1.2 Bcf per day, and is in the process of completing its third phase. In addition, construction has begun on the Southeast Supply Header (SESH) pipeline joint venture project.
 
Field Services
 
CERC’s field services business owns and operates approximately 3,500 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 151 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.
 
Other Operations
 
Our other operations business segment includes office buildings and other real estate used in our business operations and other corporate operations which support all of our business operations.


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EXECUTIVE SUMMARY
 
Significant Events in 2007 and 2008
 
Debt Financing Transactions
 
In December 2006, we called our 2.875% Convertible Senior Notes due 2024 (2.875% Convertible Notes) for redemption on January 22, 2007 at 100% of their principal amount plus accrued and unpaid interest to the redemption date. The 2.875% Convertible Notes became immediately convertible at the option of the holders upon our call for redemption and were convertible through the close of business on the redemption date. Substantially all the $255 million aggregate principal amount of the 2.875% Convertible Notes were converted and the remaining amount was redeemed. The $255 million principal amount of the 2.875% Convertible Notes was settled in cash and the excess value due converting holders of $97 million was settled by delivering approximately 5.6 million shares of our common stock.
 
In February 2007, we redeemed $103 million aggregate principal amount of 8.257% Junior Subordinated Deferrable Interest Debentures at 104.1285% of their aggregate principal amount and the related 8.257% capital securities issued by HL&P Capital Trust II were redeemed at 104.1285% of their $100 million aggregate liquidation value.
 
In February 2007, we issued $250 million aggregate principal amount of senior notes due in February 2017 with an interest rate of 5.95%. The proceeds from the sale of the senior notes were used to repay debt incurred in satisfying our $255 million cash payment obligation in connection with the conversion and redemption of our 2.875% Convertible Notes as discussed above.
 
In February 2007, CERC Corp. issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under CERC Corp.’s $375 million receivables facility. Such repayment provides increased liquidity and capital resources for CERC’s general corporate purposes.
 
In June 2007, we, CenterPoint Houston and CERC Corp. entered into amended and restated bank credit facilities. Our amended credit facility is a $1.2 billion five-year senior unsecured revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings, versus the previous rate of LIBOR plus 60 basis points. The amended facility at CenterPoint Houston is a $300 million five-year senior unsecured revolving credit facility. The facility’s first drawn cost remains at LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The amended facility at CERC Corp. is a $950 million five-year senior unsecured revolving credit facility versus a $550 million facility prior to the amendment. The facility’s first drawn cost remains at LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings.
 
In October 2007, CERC Corp. issued $250 million aggregate principal amount of 6.125% senior notes due in November 2017 and $250 million aggregate principal amount of 6.625% senior notes due in November 2037. The proceeds from the sale of the senior notes were used for general corporate purposes, including repayment or refinancing of debt, including $300 million of CERC Corp.’s 6.5% senior notes due February 1, 2008, capital expenditures, working capital and loans to or investments in affiliates. Pending application of the proceeds for these purposes, CERC Corp. repaid borrowings under its revolving credit and receivables facilities.
 
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 October 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.
 
In 2007, we issued 1.3 million shares of our common stock and paid cash of approximately $40 million upon conversion of approximately $40 million principal amount of our 3.75% convertible senior notes. Subsequent to December 31, 2007, we have issued 4.1 million shares of our common stock and paid cash of approximately $121 million upon conversion of approximately $123 million principal amount of our 3.75% convertible senior notes. A February 2008 conversion notice by a holder of $10 million principal amount of our 3.75% convertible


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senior notes is expected to result in a March 2008 conversion and settlement with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due the converting holder.
 
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 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) less an environmental refund as reduced by the fuel reconciliation settlement amount.
 
Recovery of True-Up Balance
 
In December 2007, the Texas Third Court of Appeals issued its decision in the appeal of the 2004 final order (True-Up Order) issued by the Texas Utility Commission to CenterPoint Houston. 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 excess mitigation credits (EMCs) paid to Reliant Energy, Inc. (RRI);
 
  •  ordered that the tax normalization issue 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.
 
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 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.
 
Interstate Pipeline Expansion
 
Carthage to Perryville. In April 2007, CenterPoint Energy Gas Transmission (CEGT), a wholly owned subsidiary of CERC Corp., completed phase one construction of 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. On May 1, 2007, CEGT began service under its firm transportation agreements with shippers of approximately 960 million cubic feet (MMcf) per day. CEGT’s second phase of the project, which involved adding compression that increased the total capacity of the pipeline to approximately 1.25 Bcf per day, was placed into service in August 2007. CEGT has signed firm contracts for the full capacity of phases one and two.
 
In May 2007, CEGT received Federal Energy Regulatory Commission (FERC) approval for the third phase of the project to expand capacity of the pipeline to 1.5 Bcf per day by adding additional compression and operating at


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higher pressures, and 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, which CEGT expects to satisfy in the first quarter of 2008. CEGT has executed contracts for approximately 150 MMcf per day of the 250 MMcf per day phase three expansion. The third phase is projected to be in-service in the second quarter of 2008.
 
SESH.  In June 2006, CenterPoint Energy Southeast Pipelines Holding, L.L.C., a wholly owned subsidiary of CERC Corp., and a subsidiary of Spectra Energy Corp. (Spectra) formed a joint venture, SESH, to construct, own and operate a 270-mile pipeline with a capacity of approximately 1 Bcf per day that will extend from CEGT’s Perryville hub in northeast Louisiana to an interconnection in southern Alabama with Gulfstream Natural Gas System, which is 50% owned by an affiliate of Spectra. We account for our 50% interest in SESH as an equity investment. In 2006, SESH signed agreements with shippers for firm transportation services, which subscribed capacity of 945 million cubic feet per day. Additionally, SESH and Southern Natural Gas (SNG) have executed a definitive agreement that provides for SNG to jointly own the first 115 miles of the pipeline. Under the agreement, SNG will own an undivided interest in the portion of the pipeline from Perryville, Louisiana to an interconnect with SNG in Mississippi. The pipe diameter was increased from 36 inches to 42 inches, thereby increasing the initial capacity of 1 Bcf per day by 140 MMcf per day to accommodate SNG. SESH will own assets providing approximately 1 Bcf per day of capacity as initially planned and will maintain economic expansion opportunities in the future. SNG will own assets providing 140 MMcf per day of capacity, and the agreement provides for a future compression expansion that will increase the jointly owned capacity up to 500 MMcf per day, subject to FERC approval.
 
An application to construct, own and operate the pipeline was filed with the FERC in December 2006. In September 2007, the FERC issued the certificate authorizing the construction of the pipeline. This FERC approval does not include the expansion capacity that would take SNG to 500 MMcf per day. SESH began construction in November 2007. SESH expects to complete construction of the pipeline as approved by the FERC in the second half of 2008. SESH’s net costs after SNG’s contribution are estimated to have increased to approximately $1 billion.
 
CERTAIN FACTORS AFFECTING FUTURE EARNINGS
 
Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including:
 
  •  the resolution of the true-up components, 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;


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  •  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;
 
  •  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 under “Risk Factors” in Item 1A of this report and in other reports we file from time to time with the Securities and Exchange Commission.


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CONSOLIDATED RESULTS OF OPERATIONS
 
All dollar amounts in the tables that follow are in millions, except for per share amounts.
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 9,722     $ 9,319     $ 9,623  
Expenses
    8,783       8,274       8,438  
                         
Operating Income
    939       1,045       1,185  
Gain (Loss) on Time Warner Investment
    (44 )     94       (114 )
Gain (Loss) on Indexed Debt Securities
    49       (80 )     111  
Interest and Other Finance Charges
    (670 )     (470 )     (503 )
Interest on Transition Bonds
    (40 )     (130 )     (123 )
Distribution from AOL Time Warner Litigation Settlement
                32  
Additional Distribution to ZENS Holders
                (27 )
Return on True-Up Balance
    121              
Other Income, net
    23       35       33  
                         
Income From Continuing Operations Before Income Taxes and Extraordinary Item
    378       494       594  
Income Tax Expense
    (153 )     (62 )     (195 )
                         
Income From Continuing Operations Before Extraordinary Item
    225       432       399  
Discontinued Operations, net of tax
    (3 )            
                         
Income Before Extraordinary Item
    222       432       399  
Extraordinary Item, net of tax
    30              
                         
Net Income
  $ 252     $ 432     $ 399  
                         
Basic Earnings (Loss) Per Share:
                       
Income From Continuing Operations Before Extraordinary Item
  $ 0.72     $ 1.39     $ 1.25  
Discontinued Operations, net of tax
    (0.01 )            
Extraordinary Item, net of tax
    0.10              
                         
Net Income
  $ 0.81     $ 1.39     $ 1.25  
                         
Diluted Earnings (Loss) Per Share:
                       
Income From Continuing Operations Before Extraordinary Item
  $ 0.67     $ 1.33     $ 1.17  
Discontinued Operations, net of tax
    (0.01 )            
Extraordinary Item, net of tax
    0.09              
                         
Net Income
  $ 0.75     $ 1.33     $ 1.17  
                         
 
2007 Compared to 2006
 
Income from Continuing Operations.  We reported income from continuing operations before extraordinary item of $399 million ($1.17 per diluted share) for 2007 as compared to $432 million ($1.33 per diluted share) for the same period in 2006. As discussed below, the decrease in income from continuing operations of $33 million was primarily due to a $33 million increase in interest expense, excluding transition bond-related interest expense, due to higher borrowing levels; a $133 million increase in income tax expense primarily as a result of the favorable tax settlement reached with the Internal Revenue Service (IRS) in 2006 related to our Zero Premium Exchangeable Subordinated Notes (ZENS) and Automatic Common Exchange Securities (ACES) and an $8 million decrease in operating income from our Electric Transmission & Distribution utility.


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These decreases in income from continuing operations were partially offset by a $94 million increase in operating income from our Natural Gas Distribution business segment, a $56 million increase in operating income from our Interstate Pipelines business segment and a $10 million increase in operating income from our Field Services business segment. Segment changes are discussed in detail below.
 
Income Tax Expense.  In 2007, our effective tax rate of 32.8% was lower than the expected statutory tax rate as a result of the revised Texas Franchise Tax Law (Texas Margin Tax) and a Texas state tax examination for tax years 2002 through 2004. Our 2007 effective tax rate differed from the 2006 effective tax rate of 12.6% primarily due to the favorable tax settlement reached with the IRS in 2006 as discussed above.
 
2006 Compared to 2005
 
Income from Continuing Operations.  We reported income from continuing operations before extraordinary item of $432 million ($1.33 per diluted share) for 2006 as compared to $225 million ($0.67 per diluted share) for the same period in 2005. As discussed below, the increase in income from continuing operations of $207 million was primarily due to a $200 million decrease in interest expense, excluding transition bond-related interest expense, due to lower borrowing costs and borrowing levels; a $91 million decrease in income tax expense primarily related to the tax settlement associated with ZENS and ACES; a $19 million increase in operating income from our Field Services business segment; a $17 million increase in operating income from our Competitive Natural Gas Sales and Services business segment; and a $16 million increase in operating income from our Interstate Pipelines business segment.
 
These increases in income from continuing operations were partially offset by a $121 million decrease in other income related to a reduction in the return on the true-up balance of our Electric Transmission & Distribution business segment recorded in 2005 and a $51 million decrease in operating income from our Natural Gas Distribution business segment. Segment changes are discussed in detail below.
 
Net income for 2005 included an after-tax extraordinary gain of $30 million ($0.09 per diluted share) reflecting an adjustment to the extraordinary loss recorded in 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.
 
Income Tax Expense.  The effective tax rate in 2006 was reduced to 12.6% primarily as a result of an agreement with the IRS related to the ZENS and ACES which reduced accrued tax and related interest reserves by approximately $107 million. The net reduction in the reserves related to ZENS and ACES in 2006 was $92 million. In addition, we reached tentative settlements with the IRS on a number of other tax matters which allowed us to reduce our total tax and related interest reserve for other tax items from $60 million at December 31, 2005 to $34 million at December 31, 2006.
 
Interest Expense and Other Finance Charges
 
Total interest expense incurred was $711 million, $600 million and $626 million in 2005, 2006 and 2007, respectively. During the fourth quarter of 2005, CenterPoint Houston retired at maturity its $1.341 billion term loan, which bore interest at LIBOR plus 975 basis points, subject to a minimum LIBOR rate of 3%. Borrowings under a CenterPoint Houston credit facility, which bore interest at LIBOR plus 75 basis points, were used for the payment of the term loan and then repaid with a portion of the proceeds of the December 2005 issuance of transition bonds.


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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 2005, 2006 and 2007. Included in revenues are intersegment sales. We account for intersegment sales as if the sales were to third parties, that is, at current market prices.
 
Operating Income (Loss) by Business Segment
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Electric Transmission & Distribution
  $ 487     $ 576     $ 561  
Natural Gas Distribution
    175       124       218  
Competitive Natural Gas Sales and Services
    60       77       75  
Interstate Pipelines
    165       181       237  
Field Services
    70       89       99  
Other Operations
    (18 )     (2 )     (5 )
                         
Total Consolidated Operating Income
  $ 939     $ 1,045     $ 1,185  
                         
 
Electric Transmission & Distribution
 
The following tables provide summary data of our Electric Transmission & Distribution business segment, CenterPoint Houston, for 2005, 2006 and 2007 (in millions, except throughput and customer data):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues:
                       
Electric transmission and distribution utility
  $ 1,538     $ 1,516     $ 1,560  
Transition bond companies
    106       265       277  
                         
Total revenues
    1,644       1,781       1,837  
                         
Expenses:
                       
Operation and maintenance, excluding transition bond companies
    618       611       652  
Depreciation and amortization, excluding transition bond companies
    258       243       243  
Taxes other than income taxes
    214       212       223  
Transition bond companies
    67       139       158  
                         
Total expenses
    1,157       1,205       1,276  
                         
Operating Income
  $ 487     $ 576     $ 561  
                         
Operating Income:
                       
Electric transmission and distribution operations
  $ 429     $ 395     $ 400  
Competition transition charge
    19       55       42  
Transition bond companies(1)
    39       126       119  
                         
Total segment operating income
  $ 487     $ 576     $ 561  
                         
Throughput (in gigawatt-hours (GWh)):
                       
Residential
    24,924       23,955       23,999  
Total
    74,189       75,877       76,291  
Average number of metered customers:
                       
Residential
    1,683,100       1,732,656       1,773,319  
Total
    1,912,346       1,968,114       2,012,636  
 
 
(1) Represents the amount necessary to pay interest on the transition bonds.


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2007 Compared to 2006.  Our Electric Transmission & Distribution business segment reported operating income of $561 million for 2007, consisting of $400 million from our regulated electric transmission and distribution utility operations (TDU), $42 million from the CTC, and $119 million related to transition bond companies. For 2006, operating income totaled $576 million, consisting of $395 million from the TDU, $55 million from the CTC, and $126 million related to transition bond companies. Revenues increased due to growth ($22 million), with over 53,000 metered customers added since December 2006, higher transmission-related revenues ($22 million), increased miscellaneous service charges ($15 million), increased demand ($7 million), interest on settlement of the final fuel reconciliation ($4 million) and a one-time charge in the second quarter of 2006 related to the resolution of the unbundled cost of service order ($32 million). These increases were partially offset by the rate reduction resulting from the 2006 rate case settlement that was implemented in October 2006 ($41 million) and lower CTC return resulting from the reduction in the allowed interest rate on the unrecovered CTC balance from 11.07% to 8.06% in 2006 ($13 million). Operation and maintenance expense increased primarily due to higher transmission costs ($25 million), the absence of a gain on the sale of property in 2006 ($13 million), and increased expenses primarily related to low income and energy efficiency programs as required by the 2006 rate case settlement ($8 million), partially offset by settlement of the final fuel reconciliation ($13 million).
 
2006 Compared to 2005.  Our Electric Transmission & Distribution business segment reported operating income of $576 million for 2006, consisting of $395 million from the TDU, $55 million from the CTC and $126 million related to the transition bond companies. For 2005, operating income totaled $487 million, consisting of $429 million for the TDU, $19 million from the CTC, and $39 million related to the transition bond companies. Increases in operating income from growth ($34 million), a higher CTC amount collected in 2006 ($36 million), revenues from ancillary services ($11 million) and proceeds from land sales ($13 million) were partially offset by milder weather and reduced demand ($49 million), and the implementation of reduced base rates ($13 million) and spending on low income assistance and energy efficiency programs ($5 million) resulting from the Settlement Agreement described in “Business — Our Business — Regulation — State and Local Regulation — Electric Transmission & Distribution — CenterPoint Houston Rate Agreement.” In addition, the TDU’s operating income for 2006 included the $32 million adverse impact of the resolution of the remand of the 2001 UCOS order.
 
In September 2005, CenterPoint Houston’s service area in Texas was adversely affected by Hurricane Rita. Although damage to CenterPoint Houston’s electric facilities was limited, over 700,000 customers lost power at the height of the storm. Power was restored to over a half million customers within 36 hours and all power was restored in less than five days. The Electric Transmission & Distribution business segment’s revenues lost as a result of the storm were more than offset by warmer than normal weather during the third quarter of 2005. CenterPoint Houston deferred $28 million of restoration costs which are being amortized over a seven-year period that began in October 2006.


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Natural Gas Distribution
 
The following table provides summary data of our Natural Gas Distribution business segment for 2005, 2006 and 2007 (in millions, except throughput and customer data):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 3,846     $ 3,593     $ 3,759  
                         
Expenses:
                       
Natural gas
    2,841       2,598       2,683  
Operation and maintenance
    551       594       579  
Depreciation and amortization
    152       152       155  
Taxes other than income taxes
    127       125       124  
                         
Total expenses
    3,671       3,469       3,541  
                         
Operating Income
  $ 175     $ 124     $ 218  
                         
Throughput (in billion cubic feet (Bcf)):
                       
Residential
    160       152       172  
Commercial and industrial
    215       224       232  
                         
Total Throughput
    375       376       404  
                         
Average number of customers:
                       
Residential
    2,839,947       2,883,927       2,931,523  
Commercial and industrial
    244,782       243,265       246,993  
                         
Total
    3,084,729       3,127,192       3,178,516  
                         
 
2007 Compared to 2006.  Our Natural Gas Distribution business segment reported operating income of $218 million for 2007 as compared to $124 million for 2006. Operating income improved as a result of increased usage primarily due to a return to more normal weather in 2007 compared to the unusually mild weather in 2006 ($33 million), growth from the addition of over 38,000 customers in 2007 ($9 million), the effect of the 2006 purchased gas cost write-off described below ($21 million), the effect of rate changes ($7 million) and reduced operation and maintenance expenses ($15 million). Operation and maintenance expenses declined primarily as a result of costs associated with staff reductions incurred in 2006 ($17 million) and settlement of certain rate case-related items ($9 million), partially offset by increases in bad debts and collection costs ($8 million) and other services ($5 million).
 
2006 Compared to 2005.  Our Natural Gas Distribution business segment reported operating income of $124 million for 2006 as compared to $175 million for 2005. Decreases in operating margins (revenues less natural gas costs) include a $21 million write-off in 2006 of purchased gas costs for periods prior to July 2004, the recovery of which was denied by the Minnesota Public Utilities Commission, and the impact of milder weather and decreased usage ($30 million). These decreases were partially offset by higher margins from rate and service charge increases and rate design changes ($35 million), along with the addition of over 42,000 customers in 2006 ($9 million). Operation and maintenance expenses increased primarily as a result of costs associated with staff reductions ($17 million), benefit costs increases ($6 million), higher costs of goods and services ($8 million) and higher bad debt expenses ($10 million), partially offset by higher litigation reserves recorded in 2005 ($11 million).
 
During the third quarter of 2005, our east Texas, Louisiana and Mississippi natural gas service areas were affected by Hurricanes Katrina and Rita. Damage to our facilities was limited, but approximately 10,000 homes and businesses were damaged to such an extent that they were not able to, and in some cases continue to be unable to, take service. The impact on the Natural Gas Distribution business segment’s operating income was not material.


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Competitive Natural Gas Sales and Services
 
The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2005, 2006 and 2007 (in millions, except throughput and customer data):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 4,129     $ 3,651     $ 3,579  
                         
Expenses:
                       
Natural gas
    4,033       3,540       3,467  
Operation and maintenance
    30       30       31  
Depreciation and amortization
    2       1       5  
Taxes other than income taxes
    4       3       1  
                         
Total expenses
    4,069       3,574       3,504  
                         
Operating Income
  $ 60     $ 77     $ 75  
                         
Throughput (in Bcf):
                       
Wholesale — third parties
    304       335       314  
Wholesale — affiliates
    27       36       9  
Retail
    156       149       192  
Pipeline
    51       35       7  
                         
Total Throughput
    538       555       522  
                         
Average number of customers:
                       
Wholesale
    138       140       235  
Retail
    6,328       6,452       6,789  
Pipeline
    142       138       12  
                         
Total
    6,608       6,730       7,036  
                         
 
2007 Compared to 2006.  Our Competitive Natural Gas Sales and Services business segment reported operating income of $75 million for 2007 compared to $77 million for 2006. The decrease in operating income of $2 million was primarily due to reduced opportunities for optimization of pipeline and storage assets resulting from lower locational and seasonal natural gas price differentials in the wholesale business ($10 million) offset by an increase in sales to commercial and industrial customers in the retail business ($3 million). In addition, 2007 included a charge to income from mark-to-market accounting for non-trading derivatives ($10 million) and a write-down of natural gas inventory to the lower of average cost or market ($11 million), compared to a gain from mark-to-market accounting ($37 million) and an inventory write-down ($66 million) for 2006.
 
2006 Compared to 2005.  Our Competitive Natural Gas Sales and Services business segment reported operating income of $77 million for 2006 as compared to $60 million for 2005. The increase in operating income of $17 million was primarily driven by improved operating margins (revenues less natural gas costs) resulting from seasonal price differentials and favorable basis differentials over the pipeline capacity that we control ($44 million) and a favorable change in unrealized gains resulting from mark-to-market accounting ($37 million), partially offset by write-downs of natural gas inventory to the lower of average cost or market ($66 million).


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Interstate Pipelines
 
The following table provides summary data of our Interstate Pipelines business segment for 2005, 2006 and 2007 (in millions, except throughput data):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 386     $ 388     $ 500  
                         
Expenses:
                       
Natural gas
    47       31       83  
Operation and maintenance
    121       120       125  
Depreciation and amortization
    36       37       44  
Taxes other than income taxes
    17       19       11  
                         
Total expenses
    221       207       263  
                         
Operating Income
  $ 165     $ 181     $ 237  
                         
Throughput (in Bcf):
                       
Transportation
    914       939       1,216  
Other
    2       1       5  
                         
Total Throughput
    916       940       1,221  
                         
 
2007 Compared to 2006.  Our Interstate Pipeline business segment reported operating income of $237 million for 2007 compared to $181 million for 2006. The increase in operating income of $56 million was driven primarily by the new Carthage to Perryville pipeline ($42 million), other transportation and ancillary services ($20 million), lower spending in 2007 on project development costs ($6 million) and a decrease in other taxes ($8 million) related to the settlement of certain state tax issues. These favorable variances to operating income were partially offset by lower sales in 2007 of excess gas associated with storage enhancement projects ($15 million) and increased operating expenses ($6 million).
 
2006 Compared to 2005.  Our Interstate Pipelines business segment reported operating income of $181 million for 2006 as compared to $165 million for 2005. Operating margins (natural gas sales less gas cost) increased by $18 million. This increase was driven primarily by increased demand for transportation services and ancillary services ($15 million). Operation and maintenance expenses decreased by $1 million primarily due to the gain on sale of excess gas during 2006 ($18 million) combined with lower litigation reserves ($6 million) in 2006 compared to 2005. These favorable variances were partially offset by a write-off of project development expenses associated with the Mid-Continent Crossing pipeline project which was discontinued in 2006 ($11 million) as well as increased operating expenses ($11 million) largely associated with staffing increases and costs associated with continued compliance with pipeline integrity regulations.


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Field Services
 
The following table provides summary data of our Field Services business segment for 2005, 2006 and 2007 (in millions, except throughput data):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 120     $ 150     $ 175  
                         
Expenses:
                       
Natural gas
    (10 )     (10 )     (4 )
Operation and maintenance
    49       59       66  
Depreciation and amortization
    9       10       11  
Taxes other than income taxes
    2       2       3  
                         
Total expenses
    50       61       76  
                         
Operating Income
  $ 70     $ 89     $ 99  
                         
Throughput (in Bcf):
                       
Gathering
    353       375       398  
 
2007 Compared to 2006.  Our Field Services business segment reported operating income of $99 million for 2007 compared to $89 million for 2006. Continued increased demand for gas gathering and ancillary services ($27 million) was partially offset by lower commodity prices ($10 million) and increased operation and maintenance expenses related to cost increases and expanded operations ($7 million).
 
2006 Compared to 2005.  Our Field Services business segment reported operating income of $89 million for 2006 as compared to $70 million for 2005. The increase of $19 million was driven by increased gas gathering and ancillary services, which reflects contributions from new facilities placed in service ($27 million) and higher commodity prices ($3 million), partially offset by higher operation and maintenance expenses ($10 million).
 
In addition, this business segment recorded equity income of $6 million, $6 million and $10 million for the years ended December 31, 2005, 2006 and 2007, respectively, from its 50% interest in the Waskom Joint Venture. These amounts are included in Other — net under the Other Income (Expense) caption.
 
Other Operations
 
The following table provides summary data for our Other Operations business segment for 2005, 2006 and 2007 (in millions):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Revenues
  $ 19     $ 15     $ 10  
Expenses
    37       17       15  
                         
Operating Loss
  $ (18 )   $ (2 )   $ (5 )
                         
 
2007 Compared to 2006.  Our Other Operations business segment’s operating loss in 2007 compared to 2006 increased by $3 million.
 
2006 Compared to 2005.  Our Other Operations business segment’s operating loss in 2006 compared to 2005 decreased $16 million primarily due to increased rental revenues ($2 million), decreased insurance costs ($4 million), and decreased state franchise taxes ($8 million).
 
Discontinued Operations
 
In December 2004, Texas Genco completed the sale of its fossil generation assets (coal, lignite and gas-fired plants) to Texas Genco LLC for $2.813 billion in cash. Following the sale, Texas Genco, whose principal remaining


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asset was its ownership interest in a nuclear generating facility, distributed $2.231 billion in cash to us. The final step of the transaction, the merger of Texas Genco with a subsidiary of Texas Genco LLC in exchange for an additional cash payment to us of $700 million, was completed in April 2005. We recorded an after-tax loss of $3 million for the year ended December 31, 2005 related to the operations of Texas Genco.
 
The consolidated financial statements report the businesses described above as discontinued operations for all periods presented in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144).
 
For further information regarding discontinued operations, please read Note 3 to our consolidated financial statements.
 
LIQUIDITY AND CAPITAL RESOURCES
 
Historical Cash Flow
 
The net cash provided by (used in) operating, investing and financing activities for 2005, 2006 and 2007 is as follows (in millions):
 
                         
    Year Ended December 31,  
    2005     2006     2007  
 
Cash provided by (used in):
                       
Operating activities
  $ 63     $ 991     $ 774  
Investing activities
    17       (1,056 )     (1,300 )
Financing activities
    (171 )     118       528  
 
Cash Provided by Operating Activities
 
Net cash provided by operating activities in 2007 decreased $217 million compared to 2006 primarily due to the timing of fuel recovery ($204 million), increased tax payments ($10 million), increased interest payments ($40 million), increased gas storage inventory ($36 million) and decreased net accounts receivable/payable ($178 million). These decreases were partially offset by decreased reductions in customer margin deposit requirements ($76 million) and decreases in our margin deposit requirements ($145 million).
 
Net cash provided by operating activities in 2006 increased $928 million compared to 2005 primarily due to decreased tax payments of $156 million, the majority of which related to the tax payment in the first quarter of 2005 associated with the sale of our former electric generation business (Texas Genco); increased fuel over-recovery ($240 million) primarily related to declining gas prices during 2006; decreases in net regulatory assets ($271 million), primarily due to the termination of excess mitigation credits effective April 2005 and recovery of regulatory assets through rates; increased net accounts receivable/payable ($128 million) primarily due to decreased gas prices as compared to 2005 partially offset by funding under CERC’s receivables facility being accounted for as short-term borrowings instead of sales of receivables beginning in October 2006 and decreased cash used in the operations of Texas Genco ($38 million). Additionally, customer margin deposit requirements decreased ($155 million) primarily due to the decline in natural gas prices from December 2005 and our margin deposits increased ($52 million).
 
Cash Provided by (Used in) Investing Activities
 
Net cash used in investing activities increased $244 million in 2007 as compared to 2006 due to increased capital expenditures of $107 million primarily related to pipeline projects for our Interstate Pipelines business segment, increased notes receivable from unconsolidated affiliates of $148 million and increased investment in unconsolidated affiliates of $26 million, primarily related to the SESH pipeline project.
 
Net cash used in investing activities increased $1.1 billion in 2006 as compared to 2005 primarily due to increased capital expenditures of $314 million primarily related to our Electric Transmission & Distribution, Interstate Pipelines, and Field Services business segments, increased restricted cash of transition bond companies of $36 million primarily related to the $1.85 billion of transition bonds issued in December 2005 and the absence of


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$700 million in proceeds received in the second quarter of 2005 from the sale of our remaining interest in Texas Genco and cash of Texas Genco of $24 million.
 
Cash Provided by (Used in) Financing Activities
 
Net cash provided by financing activities in 2007 increased $410 million compared to 2006 primarily due to increased borrowings under revolving credit facilities ($334 million) and increased proceeds from long-term debt ($576 million), which were partially offset by increased repayments of long-term debt ($319 million), increased dividend payments ($31 million) and decreased short-term borrowings ($142 million).
 
Net cash provided by financing activities in 2006 increased $289 million compared to 2005 primarily due to net proceeds from the issuance of long-term debt of $324 million, decreased repayments of borrowings under our revolving credit facility ($236 million) and funding under CERC’s receivables facility being accounted for as short-term borrowings ($187 million) in 2006, partially offset by the absence of borrowings under Texas Genco’s revolving credit facility ($75 million) due to the sale of Texas Genco, payments of long-term debt ($229 million) and increased dividend payments of $63 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 2008 include the following:
 
  •  approximately $995 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 $535 million at December 31, 2007;
 
  •  maturing long-term debt aggregating approximately $666 million, including $159 million of transition bonds;
 
  •  investment in and advances to SESH of approximately $294 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 issuance of $488 million of transition bonds in February 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.
 
The following table sets forth our capital expenditures for 2007 and estimates of our capital requirements for 2008 through 2012 (in millions):
 
                                                 
    2007     2008     2009     2010     2011     2012  
 
Electric Transmission & Distribution
  $ 401     $ 371     $ 358     $ 444     $ 415     $ 392  
Natural Gas Distribution
    191       209       192       193       196       203  
Competitive Natural Gas Sales and Services
    7       18       2       2       2       2  
Interstate Pipelines
    308       209       133       77       72       76  
Field Services
    74       154       83       93       94       85  
Other Operations
    30       34       29       38       22       20  
                                                 
Total
  $ 1,011     $ 995     $ 797     $ 847     $ 801     $ 778  
                                                 


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The following table sets forth estimates of our contractual obligations, including payments due by period (in millions):
 
                                         
                            2013 and
 
Contractual Obligations
  Total     2008     2009-2010     2011-2012     thereafter  
 
Transition bond debt
  $ 2,260     $ 159     $ 366     $ 432     $ 1,303  
Other long-term debt(1)
    7,419       1,156       212       986       5,065  
Interest payments — transition bond debt(2)
    745       117       207       166       255  
Interest payments — other long-term debt(2)
    4,215       420       793       688       2,314  
Short-term borrowings
    232       232                    
Capital leases
    1                         1  
Operating leases(3)
    68       19       22       13       14  
Benefit obligations(4)
                             
Purchase obligations(5)
    27       27                    
Non-trading derivative liabilities
    75       61       14              
Other commodity commitments(6)
    3,027       743       563       550       1,171  
Joint venture obligations(7)
    294       294                    
Income taxes(8)
    118       118                    
                                         
Total contractual cash obligations
  $ 18,481     $ 3,346     $ 2,177     $ 2,835     $ 10,123  
                                         
 
 
(1) 2008 maturities include $114 million of ZENS obligations as they are exchangeable for cash at any time at the option of the holders and $535 million principal amount of our 3.75% convertible senior notes as they meet the criteria that make them eligible for conversion at the option of the holders of these notes.
 
(2) We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2007. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.
 
(3) For a discussion of operating leases, please read Note 10(b) to our consolidated financial statements.
 
(4) Contributions to our qualified pension plan are not required in 2008. However, we expect to contribute approximately $8 million and $21 million, respectively, to our non-qualified pension and postretirement benefits plans in 2008.
 
(5) Represents capital commitments for material in connection with the construction of a new pipeline by our Interstate Pipelines business segment. This project has been included in the table of capital expenditures presented above.
 
(6) For a discussion of other commodity commitments, please read Note 10(a) to our consolidated financial statements.
 
(7) We anticipate SESH to be in-service mid-year 2008 and ultimately will be funded with approximately 50% debt.
 
(8) Represents estimated income tax liability for settled positions for tax years under examination. In addition, as of December 31, 2007, the liability for uncertain income tax positions was $82 million. However, due to the high degree of uncertainty regarding the timing of potential future cash flows associated with these liabilities, we are unable to make a reasonably reliable estimate of the amount and period in which these liabilities might be paid.
 
Transition Bonds.  During the 2007 legislative session, the Texas legislature amended certain statutes authorizing amounts that can be securitized by utilities. 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, as well as the fuel reconciliation settlement amount, provisions for deduction of the environmental refund and certain other matters. CenterPoint Houston reached substantial agreement with other parties to this proceeding,


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and a financing order was approved by the Texas Utility Commission in September 2007. The financing order allowed for the netting of the fuel reconciliation settlement amount against the environmental refund. In February 2008, approximately $488 million of transition bonds were issued by a new special purpose subsidiary of CenterPoint Houston pursuant to the financing order. 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.
 
Convertible Debt.  As of December 31, 2007, the 3.75% convertible senior notes discussed in Note 8(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 third 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 fourth quarter of 2007, 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 2007, we issued 1.3 million shares of our common stock and paid cash of approximately $40 million upon conversion of approximately $40 million principal amount of our 3.75% convertible senior notes. Subsequent to December 31, 2007, we have issued 4.1 million shares of our common stock and paid cash of approximately $121 million upon conversion of approximately $123 million principal amount of our 3.75% convertible senior notes. A February 2008 conversion notice by a holder of $10 million principal amount of our 3.75% convertible senior notes is expected to result in a March 2008 conversion and settlement with a cash payment for the principal amount and delivery of shares of our common stock for the excess value due the converting holder.
 
Arkansas Public Service Commission (APSC), Affiliate Transaction Rulemaking Proceeding.  In December 2006, the APSC adopted new rules governing affiliate transactions involving public utilities operating in Arkansas. In February 2007, in response to requests by CERC and other gas and electric utilities operating in Arkansas, the APSC granted reconsideration of the rules and stayed their operation in order to permit additional consideration. In May 2007, the APSC adopted revised rules, which incorporated many revisions proposed by the utilities, the Arkansas Attorney General and the APSC staff. The revised rules prohibit affiliated financing transactions for purposes not related to utility operations, but permit the continuation of existing money pool and multi-jurisdictional financing arrangements such as those currently in place at CERC. Non-financial affiliate transactions generally have to be priced under an asymmetrical pricing formula under which utilities would receive the better of cost or market pricing for goods and services provided to or from the utility operations. However, corporate services provided at fully-allocated cost such as those provided by service companies are exempt. The rules also restrict utilities from engaging in businesses other than utility and utility-related businesses if the total book value of non-utility businesses exceeds 10% of the book value of the utility and its affiliates. However, existing businesses are grandfathered under the revised rules. The revised rules also permit utilities to petition for waivers of financing and non-financial rules that would otherwise be applicable to their transactions.
 
The APSC’s revised rules impose record keeping, record access, employee training and reporting requirements related to affiliate transactions, including notification to the APSC of the formation of new affiliates that will engage in transactions with the utility and annual certification by the utility’s president or chief executive officer and its chief financial officer of compliance with the rules. In addition, the revised rules require a report to the APSC in the event the utility’s bond rating is downgraded in certain circumstances. Although the revised rules impose new requirements on CERC’s operations in Arkansas, at this time neither we nor CERC anticipate that the revised rules will have an adverse effect on existing operations in Arkansas. In September 2007, Gas Operations made a filing with the APSC in accordance with the revised rules to document existing practices that would be covered by grandfathering provisions of those rules.
 
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


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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.
 
Senior Notes.  In February 2007, we issued $250 million aggregate principal amount of senior notes due in February 2017 with an interest rate of 5.95%. The proceeds from the sale of the senior notes were used to repay debt incurred in satisfying our $255 million cash payment obligation in connection with the conversion and redemption of our 2.875% Convertible Notes.
 
In February 2007, CERC Corp. issued $150 million aggregate principal amount of senior notes due in February 2037 with an interest rate of 6.25%. The proceeds from the sale of the senior notes were used to repay advances for the purchase of receivables under CERC Corp.’s receivables facility. Such repayment provided increased liquidity and capital resources for CERC’s general corporate purposes.
 
In October 2007, CERC Corp. issued $250 million aggregate principal amount of 6.125% senior notes due in November 2017 and $250 million aggregate principal amount of 6.625% senior notes due in November 2037. The proceeds from the sale of the senior notes were used for general corporate purposes, including repayment or refinancing of debt, including $300 million of CERC Corp.’s 6.5% senior notes due February 1, 2008, capital expenditures, working capital and loans to or investments in affiliates. Pending application of the proceeds for these purposes, CERC Corp. repaid borrowings under its revolving credit and receivables facilities.
 
Credit and Receivables Facilities.  In June 2007, we, CenterPoint Houston and CERC Corp. entered into amended and restated bank credit facilities. Our amended credit facility is a $1.2 billion five-year senior unsecured revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings, versus the previous rate of LIBOR plus 60 basis points. The facility contains covenants, including a debt (excluding transition bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant.
 
The amended facility at CenterPoint Houston is a $300 million five-year senior unsecured revolving credit facility. The facility’ first drawn cost remains at LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The facility contains covenants, including a debt (excluding transition bonds) to total capitalization covenant.
 
The amended facility at CERC Corp. is a $950 million five-year senior unsecured revolving credit facility versus a $550 million facility prior to the amendment. The facility’s first drawn cost remains at LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains covenants, including a debt to total capitalization covenant.


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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.
 
CERC’s receivables facility terminates in October 2008. The facility size will range from $150 million to $375 million during the period from December 31, 2007 to the October 28, 2008 termination date of the facility. At December 31, 2007, $232 million was utilized under the facility.
 
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.
 
As of February 15, 2008, we had the following facilities (in millions):
 
                                         
                      Amount Utilized at
       
                      February 15,
       
Date Executed
  Company     Type of Facility     Size of Facility     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       87 (2)     June 29, 2012  
October 30, 2007
    CERC       Receivables       375       85       October 28, 2008  
 
 
(1) Represents outstanding letters of credit.
 
(2) Includes $74 million of borrowings under the credit facility and $13 million of outstanding letters of credit.
 
The $1.2 billion CenterPoint Energy credit facility backstops a $1.0 billion 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 December 31, 2007, there was no 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 December 31, 2007, 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 February 15, 2008, we had outstanding Treasury rate lock agreements with an aggregate notional amount of $300 million, expiration dates of June 2008 and a weighted-average locked Treasury rate on ten-year debt of 4.05%. These agreements were executed to hedge the ten-year Treasury rate expected to be used in pricing a 2008 issuance of ten-year notes.
 
Temporary Investments.  As of December 31, 2007, we had no external temporary investments.
 
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


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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.
 
Impact on Liquidity of a Downgrade in Credit Ratings.  As of February 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-   Positive   BBB-   Stable
CenterPoint Houston Senior Secured Debt
(First Mortgage Bonds)
  Baa2   Stable   BBB+   Positive   A-   Stable
CERC Corp. Senior Unsecured Debt
  Baa3   Stable   BBB   Positive   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 $153 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 December 31, 2007. 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 December 31, 2007, the amount posted as collateral amounted to approximately $47 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 December 31, 2007, unsecured credit limits extended to CES by counterparties aggregate $154 million; however, utilized credit capacity is significantly


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lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $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 December 31, 2007, subsidiaries of CERC Corp. have advanced approximately $198 million to SESH, of which $52 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 $1.4 billion in principal amount as of December 31, 2007, 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 this report.
 
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


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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.
 
CRITICAL ACCOUNTING POLICIES
 
A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors.
 
Accounting for Rate Regulation
 
SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. Our Electric Transmission & Distribution business applies SFAS No. 71, which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our former electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 with respect to our Electric Transmission & Distribution business segment relate to $281 million of recoverable electric generation-related regulatory assets as of December 31, 2007. These costs are recoverable under the provisions of the 1999 Texas Electric Choice Plan. Based on our analysis of the final order issued by the Texas Utility Commission, we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in 2005 related to the regulatory asset. Additionally, a district court in Travis County, Texas issued a judgment which would have had the effect of restoring approximately $650 million, plus interest, of disallowed costs. 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 be remanded to the Texas Utility Commission; and
 
  •  affirmed the district court’s judgment in all other respects.


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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.
 
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 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.
 
Impairment of Long-Lived Assets and Intangibles
 
We review the carrying value of our long-lived assets, including goodwill and identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable, and at least annually for goodwill as required by SFAS No. 142, “Goodwill and Other Intangible Assets.” No impairment of goodwill was indicated based on our annual analysis as of July 1, 2007. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, interest rates, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.
 
Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.
 
Asset Retirement Obligations
 
We account for our long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations — An Interpretation of SFAS No. 143” (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.
 
We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components:
 
  •  Inflation adjustment — The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;
 
  •  Discount rate — The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and
 
  •  Third-party markup adjustments — Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset.


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Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 3.0%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately the same percentage. At December 31, 2007, our estimated cost of retiring these assets is approximately $81 million.
 
Unbilled Energy Revenues
 
Revenues related to electricity delivery and natural gas sales and services are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, deliveries to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electricity delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. Unbilled natural gas sales are estimated based on estimated purchased gas volumes, estimated lost and unaccounted for gas and tariffed rates in effect. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
 
Pension and Other Retirement Plans
 
We sponsor pension and other retirement plans in various forms covering all employees who meet eligibility requirements. We use several statistical and other factors that attempt to anticipate future events in calculating the expense and liability related to our plans. These factors include assumptions about the discount rate, expected return on plan assets and rate of future compensation increases as estimated by management, within certain guidelines. In addition, our actuarial consultants use subjective factors such as withdrawal and mortality rates. The actuarial assumptions used may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of participants. These differences may result in a significant impact to the amount of pension expense recorded. Please read “— Other Significant Matters — Pension Plans” for further discussion.
 
NEW ACCOUNTING PRONOUNCEMENTS
 
See Note 2(o) to our consolidated financial statements for a discussion of new accounting pronouncements that affect us.
 
OTHER SIGNIFICANT MATTERS
 
Pension Plans.  As discussed in Note 2(p) to our consolidated financial statements, we maintain a non-contributory qualified pension plan covering substantially all employees. Employer contributions for the qualified plan are based on actuarial computations that establish the minimum contribution required under the Employee Retirement Income Security Act of 1974 (ERISA) and the maximum deductible contribution for income tax purposes.
 
Under the terms of our pension plan, we reserve the right to change, modify or terminate the plan. Our funding policy is to review amounts annually and contribute an amount at least equal to the minimum contribution required under ERISA and the Internal Revenue Code.
 
We made no contribution to the qualified pension plans in 2006 and 2007. The minimum funding requirements for these plans did not require contribution for the respective years.
 
Additionally, we maintain an unfunded non-qualified benefit restoration plan that allows participants to retain the benefits to which they would have been entitled under our non-contributory pension plan except for the federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. Employer contributions for the non-qualified benefit restoration plan represent benefit payments made to participants and totaled $7 million and $9 million in 2006 and 2007, respectively.


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In accordance with SFAS No. 87, “Employers’ Accounting for Pensions,” changes in pension obligations and assets may not be immediately recognized as pension expense in the income statement, but generally are recognized in future years over the remaining average service period of plan participants. As such, significant portions of pension expense recorded in any period may not reflect the actual level of benefit payments provided to plan participants.
 
In September 2006, the FASB issued 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)” (SFAS No. 158). SFAS No. 158 requires us, as the sponsor of a plan, to (a) recognize on our balance sheets as an asset a plan’s over-funded status or as a liability such plan’s under-funded status, (b) measure a plan’s assets and obligations as of the end of our fiscal year and (c) recognize changes in the funded status of our plans in the year that changes occur through adjustments to other comprehensive income.
 
As a result of the adoption of SFAS No. 158 as of December 31, 2006, we recorded a regulatory asset of $466 million and a charge to accumulated comprehensive income of $79 million, net of tax.
 
At December 31, 2007, the market value of plan assets exceeded the projected benefit obligation of our pension plans by $147 million. Changes in interest rates and the market values of the securities held by the plan during 2008 could materially, positively or negatively, change our funded status and affect the level of pension expense and required contributions.
 
Pension expense was $36 million, $46 million and $15 million for 2005, 2006 and 2007, respectively. In addition, included in the costs for 2005 is less than $1 million of expense related to Texas Genco participants. Pension expense for Texas Genco participants is reflected in our Statement of Consolidated Income as discontinued operations.
 
The calculation of pension expense and related liabilities requires the use of assumptions. Changes in these assumptions can result in different expense and liability amounts, and future actual experience can differ from the assumptions. Two of the most critical assumptions are the expected long-term rate of return on plan assets and the assumed discount rate.
 
As of December 31, 2007, our qualified pension plan had an expected long-term rate of return on plan assets of 8.5%, which was unchanged from the rate assumed as of December 31, 2006. We believe that our actual asset allocation, on average, will approximate the targeted allocation and the estimated return on net assets. We regularly review our actual asset allocation and periodically rebalance plan assets as appropriate.
 
As of December 31, 2007, the projected benefit obligation was calculated assuming a discount rate of 6.40%, which is a 0.55% increase from the 5.85% discount rate assumed in 2006. The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and the expected duration of pension obligations specific to the characteristics of our plan.
 
Pension expense for 2008, including the benefit restoration plan, is estimated to be $1 million based on an expected return on plan assets of 8.5% and a discount rate of 6.40% as of December 31, 2007. If the expected return assumption were lowered by 0.5% (from 8.5% to 8.0%), 2008 pension expense would increase by approximately $9 million.
 
As of December 31, 2007, pension plan assets exceed the projected benefit obligation (including the unfunded benefit restoration plan) by $147 million. However, if the discount rate was lowered by 0.5% (from 6.40% to 5.90%), the assumption change would increase our projected benefit obligation and 2008 pension expense by approximately $103 million and $10 million, respectively. In addition, the assumption change would impact our Consolidated Balance Sheet by increasing the regulatory asset recorded as of December 31, 2007 by $79 million and would result in a charge to comprehensive income in 2007 of $15 million, net of tax.
 
Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be.


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Item 7A.   Quantitative and Qualitative Disclosures About Market Risk
 
Impact of Changes in Interest Rates and Energy Commodity Prices
 
We are exposed to various market risks. These risks arise from transactions entered into in the normal course of business and are inherent in our consolidated financial statements. Most of the revenues and income from our business activities are impacted by market risks. Categories of market risk include exposure to commodity prices through non-trading activities, interest rates and equity prices. A description of each market risk is set forth below:
 
  •  Commodity price risk results from exposures to changes in spot prices, forward prices and price volatilities of commodities, such as natural gas and other energy commodities risk.
 
  •  Interest rate risk primarily results from exposures to changes in the level of borrowings and changes in interest rates.
 
  •  Equity price risk results from exposures to changes in prices of individual equity securities.
 
Management has established comprehensive risk management policies to monitor and manage these market risks. We manage these risk exposures through the implementation of our risk management policies and framework. We manage our exposures through the use of derivative financial instruments and derivative commodity instrument contracts. During the normal course of business, we review our hedging strategies and determine the hedging approach we deem appropriate based upon the circumstances of each situation.
 
Derivative instruments such as futures, forward contracts, swaps and options derive their value from underlying assets, indices, reference rates or a combination of these factors. These derivative instruments include negotiated contracts, which are referred to as over-the-counter derivatives, and instruments that are listed and traded on an exchange.
 
Derivative transactions are entered into in our non-trading operations to manage and hedge certain exposures, such as exposure to changes in natural gas prices. We believe that the associated market risk of these instruments can best be understood relative to the underlying assets or risk being hedged.
 
Interest Rate Risk
 
As of December 31, 2007, we had outstanding long-term debt, bank loans, lease obligations, treasury rate lock derivative instruments and our obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.
 
Our floating-rate obligations aggregated $187 million and $563 million at December 31, 2006 and 2007, respectively. If the floating interest rates were to increase by 10% from December 31, 2007 rates, our combined interest expense would increase by approximately $3 million annually.
 
At December 31, 2006 and 2007, we had outstanding fixed-rate debt (excluding indexed debt securities) and trust preferred securities aggregating $8.9 billion and $9.2 billion, respectively, in principal amount and having a fair value of $9.6 billion and $9.7 billion, respectively. 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 8 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $352 million if interest rates were to decline by 10% from their levels at December 31, 2007. 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 December 31, 2007, we had treasury rate lock derivative instruments with $150 million of notional value and expiration dates of June 2, 2008 to hedge the risk of changes in the 10-year U.S. treasury rate prior to the forecasted issuance of fixed-rate debt in 2008. As of December 31, 2007, the treasury lock derivative instruments could be terminated at a cost of $2 million. The treasury rate lock derivative instruments 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 income. A decrease of 10% in the December 31, 2007 level of interest rates on 10-year U.S. treasury notes would


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increase the cost of terminating the treasury rate locks outstanding at December 31, 2007 by approximately $5 million.
 
As discussed in Note 6 to our consolidated financial statements, 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 $114 million at December 31, 2007 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 $18 million if interest rates were to decline by 10% from levels at December 31, 2007. Changes in the fair value of the derivative component, a $261 million recorded liability at December 31, 2007, 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 December 31, 2007 levels, the fair value of the derivative component liability would increase by approximately $4 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. Please read Note 6 to our consolidated financial statements for a discussion of the effect of adoption of SFAS No. 133 on our ZENS obligation and our historical accounting treatment of our ZENS obligation. A decrease of 10% from the December 31, 2007 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.
 
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 December 31, 2007, the recorded fair value of our non-trading energy derivatives was a net liability of $25 million. The net liability consisted of an $8 million net liability associated with price stabilization activities of our Natural Gas Distribution business segment and a net liability of $17 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. An increase of 10% in the market prices of energy commodities from their December 31, 2007 levels would have increased the fair value of our non-trading energy derivatives net liability by $5 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.
 
We have a Risk Oversight Committee composed of corporate and business segment officers that oversees our commodity price, weather and credit risk activities, including our trading, marketing, risk management services and hedging activities. The committee’s duties are to establish commodity risk policies, allocate risk capital within limits established by our board of directors, approve trading of new products and commodities, monitor risk positions and ensure compliance with our risk management policies and procedures and trading limits established by our board of directors.
 
Our policies prohibit the use of leveraged financial instruments. A leveraged financial instrument, for this purpose, is a transaction involving a derivative whose financial impact will be based on an amount other than the notional amount or volume of the instrument.


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Item 8.   Financial Statements and Supplementary Data
 
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
 
We have audited the accompanying consolidated balance sheets of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2007 and 2006, and the related statements of consolidated income, comprehensive income, shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
 
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
 
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy, Inc. and subsidiaries at December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.
 
As discussed in Note 2 to the consolidated financial statements, the Company adopted Statement of Financial Accounting Standards No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R)”, effective December 31, 2006. Also, as discussed in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations”, effective December 31, 2005.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 28, 2008, expressed an unqualified opinion on the Company’s internal control over financial reporting.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
February 28, 2008


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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
 
To the Board of Directors and Shareholders of
CenterPoint Energy, Inc.
Houston, Texas
 
We have audited the internal control over financial reporting of CenterPoint Energy, Inc. and subsidiaries (the “Company”) as of December 31, 2007, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report of Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
 
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
 
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel 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. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
 
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
 
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 2007, of the Company and our report dated February 28, 2008, expressed an unqualified opinion on those financial statements.
 
DELOITTE & TOUCHE LLP
 
Houston, Texas
February 28, 2008


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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING
 
Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, 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 and includes those policies and procedures that:
 
  •  Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;
 
  •  Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and
 
  •  Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.
 
Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the financial statements.
 
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
 
Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management has concluded that our internal control over financial reporting was effective as of December 31, 2007.
 
Deloitte & Touche LLP, the Company’s independent registered public accounting firm, has issued an attestation report on the effectiveness of our internal control over financial reporting as of December 31, 2007 which is included herein on page 64.
 
   
/s/  DAVID M. MCCLANAHAN
President and Chief Executive Officer
 
   
/s/  GRAY L. WHITLOCK
Executive Vice President and Chief
Financial Officer
 
February 28, 2008


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
STATEMENTS OF CONSOLIDATED INCOME
 
                         
    Year Ended December 31,  
    2005     2006     2007  
    (In millions,
 
    except for share amounts)  
 
Revenues
  $ 9,722     $ 9,319     $ 9,623  
                         
Expenses:
                       
Natural gas
    6,509       5,909       5,995  
Operation and maintenance
    1,358       1,399       1,440  
Depreciation and amortization
    541       599       631  
Taxes other than income taxes
    375       367       372  
                         
Total
    8,783       8,274       8,438  
                         
Operating Income
    939       1,045       1,185  
                         
Other Income (Expense):
                       
Gain (loss) on Time Warner investment
    (44 )     94       (114 )
Gain (loss) on indexed debt securities
    49       (80 )     111  
Interest and other finance charges
    (670 )     (470 )     (503 )
Interest on transition bonds
    (40 )     (130 )     (123 )
Distribution from AOL Time Warner litigation settlement
                32  
Additional distribution to ZENS holders
                (27 )
Return on true-up balance
    121              
Other, net
    23       35       33  
                         
Total
    (561 )     (551 )     (591 )
                         
Income From Continuing Operations Before Income Taxes and Extraordinary Item
    378       494       594  
Income tax expense
    (153 )     (62 )     (195 )
                         
Income From Continuing Operations Before Extraordinary Item
    225       432       399  
Discontinued Operations:
                       
Income from Texas Genco, net of tax
    11              
Loss on disposal of Texas Genco, net of tax
    (14 )            
                         
Total
    (3 )            
                         
Income Before Extraordinary Item
    222       432       399  
Extraordinary item, net of tax
    30              
                         
Net Income
  $ 252     $ 432     $ 399  
                         
Basic Earnings (Loss) Per Share:
                       
Income From Continuing Operations Before Extraordinary Item
  $ 0.72     $ 1.39     $ 1.25  
Discontinued Operations, net of tax
    (0.01 )            
Extraordinary item, net of tax
    0.10              
                         
Net Income
  $ 0.81     $ 1.39     $ 1.25  
                         
Diluted Earnings (Loss) Per Share:
                       
Income From Continuing Operations Before Extraordinary Item
  $ 0.67     $ 1.33     $ 1.17  
Discontinued Operations, net of tax
    (0.01 )            
Extraordinary item, net of tax
    0.09              
                         
Net Income
  $ 0.75     $ 1.33     $ 1.17  
                         
 
See Notes to the Company’s Consolidated Financial Statements


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
STATEMENTS OF CONSOLIDATED COMPREHENSIVE INCOME
 
                         
    Year Ended December 31,  
    2005     2006     2007  
    (In millions)  
 
Net income
  $ 252     $ 432     $ 399  
                         
Other comprehensive income, net of tax:
                       
SFAS No. 158 adjustment (net of tax of $28)
                34  
Minimum pension liability adjustment (net of tax of ($5) and $6)
    (9 )     12        
Net deferred gain from cash flow hedges (net of tax of $9, $11, and $6)
    17       22       11  
Reclassification of deferred loss (gain) from cash flow hedges realized in net income (net of tax of $6, $8, and ($14))
    11       14       (20 )
Other comprehensive income from discontinued operations (net of tax of $2)
    3              
                         
Other comprehensive income
    22       48       25  
                         
Comprehensive income
  $ 274     $ 480     $ 424  
                         
 
See Notes to the Company’s Consolidated Financial Statements


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
CONSOLIDATED BALANCE SHEETS
 
                 
    December 31,
    December 31,
 
    2006     2007  
    (In millions)  
 
ASSETS
Current Assets:
               
Cash and cash equivalents
  $ 127     $ 129  
Investment in Time Warner common stock
    471       357  
Accounts receivable, net
    1,017       910  
Accrued unbilled revenues
    451       558  
Inventory
    399       490  
Non-trading derivative assets
    98       38  
Prepaid expense and other current assets
    432       306  
                 
Total current assets
    2,995       2,788  
                 
Property, Plant and Equipment, net
    9,204       9,740  
                 
Other Assets:
               
Goodwill
    1,705       1,696  
Regulatory assets
    3,290       2,993  
Non-trading derivative assets
    21       11  
Notes receivable from unconsolidated affiliates
          148  
Other
    418       496  
                 
Total other assets
    5,434       5,344  
                 
Total Assets
  $ 17,633     $ 17,872  
                 
 
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current Liabilities:
               
Short-term borrowings
  $ 187     $ 232  
Current portion of long-term debt
    1,198       1,315  
Indexed debt securities derivative
    372       261  
Accounts payable
    1,010       726  
Taxes accrued
    364       316  
Interest accrued
    159       170  
Non-trading derivative liabilities
    141       61  
Accumulated deferred income taxes, net
    316       350  
Other
    474       360  
                 
Total current liabilities
    4,221       3,791  
                 
Other Liabilities:
               
Accumulated deferred income taxes, net
    2,323       2,235  
Unamortized investment tax credits
    39       31  
Non-trading derivative liabilities
    80       14  
Benefit obligations
    545       499  
Regulatory liabilities
    792       828  
Other
    275       300  
                 
Total other liabilities
    4,054       3,907  
                 
Long-term Debt
    7,802       8,364  
                 
Commitments and Contingencies (Note 10)
               
Shareholders’ Equity
    1,556       1,810  
                 
Total Liabilities and Shareholders’ Equity
  $ 17,633     $ 17,872  
                 
 
See Notes to the Company’s Consolidated Financial Statements


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
STATEMENTS OF CONSOLIDATED CASH FLOWS
 
                         
    Year Ended December 31,  
    2005     2006     2007  
    (In millions)  
 
Cash Flows from Operating Activities:
                       
Net income
  $ 252     $ 432     $ 399  
Discontinued operations, net of tax
    3              
Extraordinary item, net of tax
    (30 )            
                         
Income from continuing operations and cumulative effect of accounting change
    225       432       399  
Adjustments to reconcile income from continuing operations to net cash provided by operating activities:
                       
Depreciation and amortization
    541       599       631  
Amortization of deferred financing costs
    77       56       65  
Deferred income taxes
    232       (234 )     8  
Tax and interest reserves reductions related to ZENS and ACES settlement
          (107 )      
Investment tax credit
    (8 )     (7 )     (8 )
Unrealized loss (gain) on Time Warner investment
    44       (94 )     114  
Unrealized loss (gain) on indexed debt securities
    (49 )     80       (111 )
Write-down of natural gas inventory
          66       11  
Changes in other assets and liabilities:
                       
Accounts receivable and unbilled revenues, net
    (456 )     262        
Inventory
    (115 )     (82 )     (102 )
Taxes receivable
    (53 )     53        
Accounts payable
    321       (269 )     (185 )
Fuel cost over (under) recovery/surcharge
    (129 )     111       (93 )
Non-trading derivatives, net
    (12 )     (18 )     11  
Margin deposits, net
    51       (156 )     65  
Interest and taxes accrued
    (471 )     230       (33 )
Net regulatory assets and liabilities
    (192 )     79       81  
Pension contribution
    (75 )            
Other current assets
    (14 )     (76 )     13  
Other current liabilities
    69       18       (20 )
Other assets
    30       43       (33 )
Other liabilities
    67       6       (51 )
Other, net
    18       (1 )     12  
                         
Net cash provided by operating activities of continuing operations
    101       991       774  
Net cash used in operating activities of discontinued operations
    (38 )            
                         
Net cash provided by operating activities
    63       991       774  
                         
Cash Flows from Investing Activities:
                       
Capital expenditures
    (693 )     (1,007 )     (1,114 )
Proceeds from sale of Texas Genco
    700              
Purchase of minority interest of Texas Genco
    (383 )            
Decrease in restricted cash for purchase of minority interest of Texas Genco
    383              
Increase in cash of Texas Genco
    24              
Increase in restricted cash of transition bond companies
    (12 )     (32 )     (1 )
Increase in notes receivable from unconsolidated affiliates
                (148 )
Investment in unconsolidated affiliates
          (13 )     (39 )
Other, net
    (2 )     (4 )     2  
                         
Net cash provided by (used in) investing activities
    17       (1,056 )     (1,300 )
                         
Cash Flows from Financing Activities:
                       
Increase in short-term borrowings, net
    75       187       45  
Long-term revolving credit facility, net
    (236 )     (3 )     331  
Proceeds from long-term debt
    3,161       324       900  
Payments of long-term debt
    (3,045 )     (229 )     (548 )
Debt issuance costs
    (21 )     (5 )     (9 )
Payment of common stock dividends
    (124 )     (187 )     (218 )
Proceeds from issuance of common stock, net
    17       27       22  
Other, net
    2       4       5  
                         
Net cash provided by (used in) financing activities
    (171 )     118       528  
                         
Net Increase (Decrease) in Cash and Cash Equivalents
    (91 )     53       2  
Cash and Cash Equivalents at Beginning of Year
    165       74       127  
                         
Cash and Cash Equivalents at End of Year
  $ 74     $ 127     $ 129  
                         
Supplemental Disclosure of Cash Flow Information:
                       
Cash Payments:
                       
Interest, net of capitalized interest
  $ 667     $ 532     $ 572  
Income taxes (refunds), net
    351       195       205  
Non-cash transactions:
                       
Increase in accounts payable related to capital expenditures
    35       113        
 
See Notes to the Company’s Consolidated Financial Statements


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
STATEMENTS OF CONSOLIDATED SHAREHOLDERS’ EQUITY
 
                                                 
    2005     2006     2007  
    Shares     Amount     Shares     Amount     Shares     Amount  
    (In millions of dollars and shares)  
 
Preference Stock, none outstanding
        $           $           $  
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares, none outstanding
                                   
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
                                               
Balance, beginning of year
    308       3       310       3       314       3  
Issuances related to benefit and investment plans
    2             4             2        
Issuances related to convertible debt conversions
                            7        
                                                 
Balance, end of year
    310       3       314       3       323       3  
                                                 
Additional Paid-in-Capital
                                               
Balance, beginning of year
          2,891             2,931             2,977  
Issuances related to benefit and investment plans
          40             46             46  
                                                 
Balance, end of year
          2,931             2,977             3,023  
                                                 
Accumulated Deficit
                                               
Balance, beginning of year
            (1,728 )             (1,600 )             (1,355 )
Net income
            252               432               399  
Cumulative effect of adopting FIN 48
                                        2  
Common stock dividends — $0.40 per share in 2005, $0.60 per share in 2006, and $0.68 per share in 2007
            (124 )             (187 )             (218 )
                                                 
Balance, end of year
            (1,600 )             (1,355 )             (1,172 )
                                                 
Accumulated Other Comprehensive Loss
                                               
Balance, end of year:
                                               
SFAS No. 158 incremental effect
                          (79 )             (45 )
Minimum pension liability adjustment
            (15 )             (3 )             (3 )
Net deferred gain (loss) from cash flow hedges
            (23 )             13               4  
                                                 
Total accumulated other comprehensive loss, end of year
            (38 )             (69 )             (44 )
                                                 
Total Shareholders’ Equity
          $ 1,296             $ 1,556             $ 1,810  
                                                 
 
See Notes to the Company’s Consolidated Financial Statements


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
 
(1)   Background and Basis of Presentation
 
(a)   Background
 
CenterPoint Energy, Inc. (the Company) 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 December 31, 2007, 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.
 
(b)   Basis of Presentation
 
The Company sold the fossil generation assets of Texas Genco Holdings, Inc. (Texas Genco) in December 2004 and completed the sale of Texas Genco, which had continued to own an interest in a nuclear generating facility, in April 2005.
 
The consolidated financial statements report the businesses described above as discontinued operations for all periods presented in accordance with Statement of Financial Accounting Standards (SFAS) No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144).
 
For a description of the Company’s reportable business segments, see Note 14.
 
(2)   Summary of Significant Accounting Policies
 
(a)   Use of Estimates
 
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.
 
(b)   Principles of Consolidation
 
The accounts of the Company and its wholly owned and majority owned subsidiaries are included in the consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation. The Company uses the equity method of accounting for investments in entities in which the Company has an ownership interest between 20% and 50% and exercises significant influence. Such investments were $32 million and $88 million as of December 31, 2006 and 2007, respectively, and are included as part of other noncurrent assets in the Company’s Consolidated Balance Sheets. Other investments, excluding marketable securities, are carried at cost.
 
(c)   Revenues
 
The Company records revenue for electricity delivery and natural gas sales and services under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on daily supply volumes, applicable rates and analyses reflecting significant historical trends


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
and experience. Natural gas sales not billed by month-end are accrued based upon estimated purchased gas volumes, estimated lost and unaccounted for gas and currently effective tariff rates. The Interstate Pipelines and Field Services business segments record revenues as transportation services are provided.
 
(d)   Long-lived Assets and Intangibles
 
The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:
 
                         
    Weighted Average
             
    Useful Lives
    December 31,  
    (Years)     2006     2007  
          (In millions)  
 
Electric Transmission & Distribution
    27     $ 6,823     $ 6,993  
Natural Gas Distribution
    31       2,875       3,065  
Competitive Natural Gas Sales and Services
    24       53       59  
Interstate Pipelines
    57       1,943       2,194  
Field Services
    51       429       493  
Other property
    30       444       446  
                         
Total
            12,567       13,250  
                         
Accumulated depreciation and amortization:
                       
Electric Transmission & Distribution
            2,566       2,602  
Natural Gas Distribution
            462       590  
Competitive Natural Gas Sales and Services
            9       9  
Interstate Pipelines
            176       160  
Field Services
            31       29  
Other property
            119       120  
                         
Total accumulated depreciation and amortization
            3,363       3,510  
                         
Property, plant and equipment, net
          $ 9,204     $ 9,740  
                         
 
Goodwill by reportable business segment as of December 31, 2006 and 2007 is as follows (in millions):
 
                 
    December 31,  
    2006     2007  
 
Natural Gas Distribution
  $ 746     $ 746  
Interstate Pipelines
    579       579  
Competitive Natural Gas Sales and Services
    335       335  
Field Services
    25       25  
Other Operations(1)
    20       11  
                 
Total
  $ 1,705     $ 1,696  
                 
 
 
(1) In December 2007, the Company determined that $9 million of tax benefits not previously established were associated with a prior year acquisition. In accordance with Emerging Issues Task Force (EITF) Issue No. 93-7, “Uncertainties Related to Income Taxes in a Purchase Business Combination,” the adjustment was applied to decrease the remaining goodwill attributable to that acquisition.


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
 
The Company performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.
 
The Company performed the test at July 1, 2007, the Company’s annual impairment testing date, and determined that no impairment charge for goodwill was required.
 
The Company periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.
 
(e)   Regulatory Assets and Liabilities
 
The Company applies the accounting policies established in SFAS No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), to the accounts of the Electric Transmission & Distribution business segment and the Natural Gas Distribution business segment and to some of the accounts of the Interstate Pipelines business segment.
 
The following is a list of regulatory assets/liabilities reflected on the Company’s Consolidated Balance Sheets as of December 31, 2006 and 2007:
 
                 
    December 31,  
    2006     2007  
    (In millions)  
 
Electric generation-related regulatory assets(1)
  $ 343     $ 325  
Securitized regulatory asset
    2,285       2,131  
Unamortized loss on reacquired debt
    85       79  
Pension and postretirement-related regulatory asset(2)
    483       360  
Other long-term regulatory assets
    94       98  
                 
Total regulatory assets
    3,290       2,993  
                 
Electric generation-related regulatory liabilities
    39       44  
Estimated removal costs
    697       734  
Other long-term regulatory liabilities
    56       50  
                 
Total regulatory liabilities
    792       828  
                 
Total regulatory assets and liabilities, net
  $ 2,498     $ 2,165  
                 
 
 
(1) Excludes $234 million and $220 million of allowed equity return on the true-up balance as of December 31, 2006 and 2007, respectively.
 
(2) Upon 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)” (SFAS No. 158), the


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Company recorded a regulatory asset for its unrecognized costs associated with operations that have historically recovered and currently recover pension and postretirement expenses in rates.
 
If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write off or write down these regulatory assets and liabilities. During 2004, the Company wrote-off net regulatory assets of $1.5 billion ($977 million after-tax) as an extraordinary loss in response to the Public Utility Commission of Texas’ (Texas Utility Commission) order on CenterPoint Houston’s final true-up application. Based on subsequent orders received from the Texas Utility Commission, the Company recorded an extraordinary gain of $47 million ($30 million after-tax) in the second quarter of 2005 related to these regulatory assets. For further discussion of regulatory assets, see Note 4.
 
The Company’s rate-regulated businesses recognize removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2006 and 2007, these removal costs of $697 million and $734 million, respectively, are classified as regulatory liabilities in the Company’s Consolidated Balance Sheets. A portion of the amount of removal costs that relate to asset retirement obligations have been reclassified from a regulatory liability to an asset retirement liability in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47).
 
(f)   Depreciation and Amortization Expense
 
Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Amortization expense includes amortization of regulatory assets and other intangibles. See Notes 2(e) and 4(a) for additional discussion of these items.
 
The following table presents depreciation and amortization expense for 2005, 2006 and 2007.
 
                         
    2005     2006     2007  
 
Depreciation expense
  $ 432     $ 440     $ 455  
Amortization expense
    109       159       176  
                         
Total depreciation and amortization expense
  $ 541     $ 599     $ 631  
                         
 
(g)   Capitalization of Interest and Allowance for Funds Used During Construction
 
Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates for subsidiaries that apply SFAS No. 71. Interest and AFUDC for subsidiaries that apply SFAS No. 71 are capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. During 2005, 2006 and 2007, the Company capitalized interest and AFUDC of $4 million, $10 million and $21 million, respectively.
 
(h)   Income Taxes
 
The Company files a consolidated federal income tax return and follows a policy of comprehensive interperiod tax allocation. The Company uses the asset and liability method of accounting for deferred income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Investment tax credits that were deferred are being amortized over the estimated lives of the related property. A valuation allowance is established against deferred tax assets for which management believes realization is not considered more likely than not.


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
Prior to 2007, the Company evaluated uncertain income tax positions and recorded a tax liability for those positions that management believed were probable of an unfavorable outcome and could be reasonably estimated. Effective January 1, 2007, the Company accounts for the tax effects of uncertain income tax positions in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109” (FIN 48). The Company recognizes interest and penalties as a component of income tax expense. For additional information regarding income taxes, see Note 9.
 
(i)   Accounts Receivable and Allowance for Doubtful Accounts
 
Accounts receivable are net of an allowance for doubtful accounts of $33 million and $38 million at December 31, 2006 and 2007, respectively. The provision for doubtful accounts in the Company’s Statements of Consolidated Income for 2005, 2006 and 2007 was $40 million, $35 million and $45 million, respectively.
 
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 December 31, 2007, the facility size was $300 million. Commencing with an October 2006 amendment to the receivables facility, the provisions for sale accounting under SFAS No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” were no longer met. Accordingly, advances received by CERC upon the sale of receivables are accounted for as short-term borrowings as of December 31, 2006 and 2007. As of December 31, 2006 and 2007, $187 million and $232 million, respectively, was advanced for the purchase of receivables under CERC’s receivables facility.
 
Funding under the receivables facility averaged $166 million and $79 million in 2005 and 2006, respectively. Sales of receivables were approximately $2.0 billion and $555 million in 2005 and 2006, respectively.
 
(j)   Inventory
 
Inventory consists principally of materials and supplies and natural gas. Materials and supplies are valued at the lower of average cost or market. Natural gas inventories of the Company’s Competitive Natural Gas Sales and Services business segment are also primarily valued at the lower of average cost or market. Natural gas inventories of the Company’s Natural Gas Distribution business segment are primarily valued at weighted average cost. During 2006 and 2007, the Company recorded $66 million and $11 million, respectively, in write-downs of natural gas inventory to the lower of average cost or market.
 
                 
    December 31,  
    2006     2007  
    (In millions)  
 
Materials and supplies
  $ 94     $ 95  
Natural gas
    305       395  
                 
Total inventory
  $ 399     $ 490  
                 
 
(k)   Derivative Instruments
 
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. Such contracts are recognized in the Company’s Consolidated Balance Sheets at their fair value unless the Company elects the normal purchase and sales exemption for qualified physical transactions. A derivative contract may be designated as a normal purchase or sale if the intent is to physically receive or deliver the product for use or sale in the normal course of business. If derivative contracts are designated as a cash flow hedge according to SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133), the effective portions of the


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CENTERPOINT ENERGY, INC. AND SUBSIDIARIES
 
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)
 
changes in their fair values are reflected initially as a separate component of shareholders’ equity and subsequently recognized in income at the same time the hedged item impacts earnings. The ineffective portions of changes in fair values of derivatives designated as hedges are immediately recognized in income. Changes in other derivatives not designated as normal or as a cash flow hedge are recognized in income as they occur. The Company does not enter into or hold derivative instruments for trading purposes.
 
The Company has a Risk Oversight Committee composed of corporate and business segment officers that oversee