CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-K, Received: 02/25/2009 08:02:55)
 
 


UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
________________
 
Form 10-K

(Mark One)
R
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the fiscal year ended December 31, 2008
or
£
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
   
 
For the transition period from                    to                       .

Commission File Number 1-31447
________________
 
CenterPoint Energy, Inc.
(Exact name of registrant as specified in its charter)

Texas
74-0694415
(State or other jurisdiction of incorporation or organization)
(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 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 $5,451,652,076 as of June 30, 2008, 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 13, 2009, the Company had 347,404,023 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 2009 Annual Meeting of Shareholders of the Company, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2008, 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
PART I
 
Item 1.
1
Item 1A.
21
Item 1B.
31
Item 2.
31
Item 3.
32
Item 4.
32
    PART II
 
Item 5.
33
Item 6.
34
Item 7.
35
Item 7A.
56
Item 8.
59
Item 9.
104
Item 9A.
104
    PART III
 
Item 10.
105
Item 11.
105
Item 12.
105
Item 13.
105
Item 14.
105
    PART IV
 
Item 15.
105
     
Ex. 4(e)(31)
Twenty-First Supplemental Indenture to Exhibit 4(e)(1), dated as of January 9, 2009  
Ex. 4(e)(32)
 
Ex. 10(h)(1)
HI 1995 Section 415 Benefit Restoration Plan effective August 1, 1995  
Ex. 10(h)(2)
First Amendment to Exhibit 10(h)(1) effective as of August 1, 1995  
Ex. 10(n)(3)
CenterPoint Energy Outside Director Benefits Plan, as amended and restated effective December 31, 2008  
Ex. 10(hh)(1)
Executive Benefits Agreement by and between HL&P and Thomas R. Standish effective August 20, 1993  
Ex. 10(hh)(2)
First Amendment to Exhibit 10(hh)(1) effective as of December 31, 2008  
Ex. 10(ii)(1)
Executive Benefits Agreement by and between HL&P and David M. McClanahan effective August 24, 1993  
Ex. 10(ii)(2)
First Amendment to Exhibit 10(ii)(1) effective as of December 31, 2008  
Ex. 10(jj)(1)
Executive Benefits Agreement by and between HL&P and Joseph B. McGoldrick effective August 30, 1993  
Ex. 10(jj)(2)
First Amendment to Exhibit 10(jj)(1) effective as of December 31, 2008  
Ex. 10(kk)
Summary of non-employee director compensation  
Ex. 10(ll)
Summary of named executive officer compensation  
Ex. 10(mm)
Form of Executive Officer Change in Control Agreement  
Ex. 10(nn)
Form of Corporate Officer Change in Control Agreement  
Ex. 12
Computation of Ratio of Earnings to Fixed Charges  
Ex. 21
Subsidiaries of CenterPoint Energy  
Ex. 23
 
Ex. 31.1
Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan  
Ex. 31.2
 
Ex. 32.1
Section 1350 Certification of David M. McClanahan  
Ex. 32.2
Section 1350 Certification of Gary L. Whitlock  


 

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.



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. 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 of the Board of Directors.

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 certain 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 unbundle 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 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 CenterPoint Houston’s certificated service territory. 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 are established pursuant to rate proceedings conducted before municipalities that have original jurisdiction and 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, portions 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 73,000 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 (TRE), a functionally independent division of ERCOT. 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, 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. CenterPoint Houston participates 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 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 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 certain other adjustments.

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 as requested by the Texas Utility Commission; and

 
affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i)

denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true up award.

Review by the Texas Supreme Court of the court of appeals decision is at the discretion of the court. In November 2008, the Texas Supreme Court requested the parties to the Petitions for Review to submit briefs on the merits of the issues raised. Briefing at the Texas Supreme Court should be completed in the second quarter of 2009. Although the Texas Supreme Court has not indicated whether it will grant review of the lower court’s decision, its request for full briefing on the merits allowed the parties to more fully explain their positions. There is no prescribed time in which the Texas Supreme Court must determine whether to grant review or, if review is granted, for a decision by that 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 appeal to the Texas Supreme Court, we can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, 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 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 $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008.

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 that would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, we received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require 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. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals, though the Texas Supreme Court, if it grants review, will have authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. 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 securitization or through implementation of a 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. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the revised rule discussed above. Second, the district court reversed the Texas Utility Commission’s ruling that allows CenterPoint Houston to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and CenterPoint Houston appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two of the appellants have requested further review from the Texas Supreme Court. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on our or CenterPoint Houston’s financial condition, results of operations or cash flows.

During the years ended December 31, 2006, 2007 and 2008, CenterPoint Houston recognized approximately $55 million, $42 million and $5 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2006, 2007 and 2008, CenterPoint Houston recognized approximately $13 million, $14 million and $13 million, respectively, of the allowed equity return not previously recognized. As of December 31, 2008, we have not recognized an allowed equity return of $207 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, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

Hurricane Ike

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast early Saturday, September 13, 2008.

The strong Category 2 storm initially left more than 90% of CenterPoint Houston’s more than 2 million metered customers without power, the largest outage in CenterPoint Houston’s 130-year history. Most of the widespread power outages were due to power lines damaged by downed trees and debris blown by Hurricane Ike’s winds. In addition, on Galveston Island and along the coastal areas of the Gulf of Mexico and Galveston Bay, the storm surge and flooding from rains accompanying the storm caused significant damage or destruction of houses and businesses served by CenterPoint Houston.

CenterPoint Houston estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Ike will be in the range of $600 million to $650 million. As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole mounted equipment that comprise CenterPoint Houston’s transmission and distribution system are not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $17 million.

In addition to storm restoration costs, CenterPoint Houston lost approximately $17 million in revenue through December 31, 2008. Within the first 18 days after the storm, CenterPoint Houston had restored power to all customers capable of receiving it.

CenterPoint Houston has deferred the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. As a result, storm restoration costs did not affect our or CenterPoint Houston’s reported net income for 2008. As of December 31, 2008, CenterPoint Houston recorded an increase of $145 million in construction work in progress and $435 million in regulatory assets for restoration costs incurred through December 31, 2008. Approximately $73 million of these costs are based on estimates and are included in accounts payable as of December 31, 2008. Additional restoration costs will continue to be incurred in 2009.

Assuming necessary enabling legislation is enacted by the Texas Legislature in the session that began in January 2009, CenterPoint Houston expects to seek a financing order from the Texas Utility Commission to obtain recovery of its storm restoration costs through the issuance of non-recourse securitization bonds similar to the storm recovery bonds issued by another Texas utility following the hurricanes that affected that utility’s service territories in 2005. Assuming those bonds are issued, CenterPoint Houston will recover the amount of storm restoration costs determined by the Texas Utility Commission to have been prudently incurred out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. Alternatively, if securitization is not available, recovery of those costs would be sought through traditional regulatory mechanisms. Under its 2006 rate case settlement, CenterPoint Houston is entitled to seek an adjustment to rates in this situation, even though in most instances its rates are frozen until 2010.
 
 
Customers

CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. CenterPoint Houston’s customers consist of 79 REPs, which sell electricity to over 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 56%, 51% and 48% of CenterPoint Houston’s transmission and distribution revenues in 2006, 2007 and 2008, respectively. CenterPoint Houston’s billed receivables balance from REPs as of December 31, 2008 was $141 million. Approximately 46% 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)

In December 2008, CenterPoint Houston received approval from the Texas Utility Commission to deploy an advanced metering system (AMS) across its service territory over the next five years. CenterPoint Houston plans to begin installing advanced meters in March 2009. This innovative technology should encourage greater energy conservation by giving Houston-area electric consumers the ability to better monitor and manage their electric use and its cost in near real time. CenterPoint Houston will recover the cost for the AMS through a monthly surcharge to all REPs over 12 years. The surcharge for each residential consumer for the first 24 months, beginning in February 2009, will be $3.24 per month; thereafter, the surcharge is scheduled to be reduced to $3.05 per month. These amounts are subject to upward or downward adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope. CenterPoint Houston projects capital expenditures of approximately $640 million for the installation of the advanced meters and corresponding communication and data management systems over the five-year deployment period.

CenterPoint Houston is also pursuing possible deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” which would make use of CenterPoint Houston’s facilities to provide on-demand data and information about the status of facilities on its system. Although this technology is still in the developmental stage, CenterPoint Houston believes it has the potential to provide a significant improvement in 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. Texas Utility Commission approval and appropriate rate treatment would be sought in connection with any actual deployment of this technology.

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 delivers 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, 2008, CenterPoint Houston had outstanding approximately $2.6 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, $600 million securing borrowings under a credit facility which was unutilized 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 $1.8 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, 2008. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. In January 2009, CenterPoint Houston issued $500 million aggregate principal amount of general mortgage bonds in a public offering.

   Electric Lines — Overhead.   As of December 31, 2008, CenterPoint Houston owned 27,603 pole miles of overhead distribution lines and 3,727 circuit miles of overhead transmission lines, including 423 circuit miles operated at 69,000 volts, 2,088 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.

   Electric Lines — Underground.   As of December 31, 2008, CenterPoint Houston owned 19,690 circuit miles of underground distribution lines and 26 circuit miles of underground transmission lines, including 2 circuit miles operated at 69,000 volts and 24 circuit miles operated at 138,000 volts.

    Substations.   As of December 31, 2008, CenterPoint Houston owned 229 major substation sites having a total installed rated transformer capacity of 51,400 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.
 
    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 2008, approximately 43% of Gas Operations’ total throughput was to residential customers and approximately 57% was 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 2008, 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.

Gas Operations also suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana as a result of Hurricane Ike. As of December 31, 2008, Gas Operations has deferred approximately $4 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

Supply and Transportation.   In 2008, 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 2008 included BP Canada Energy Marketing Corp. (13.4% of supply volumes), Tenaska Marketing Ventures (11.5%), Oneok Energy Marketing (10.2%), Coral Energy Resources (6.6%) and Cargill, Inc. (5.8%). Numerous other suppliers provided the remaining 52.5% 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 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, 2008, Gas Operations owned approximately 70,000 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
 
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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 Pipelines, LLC (CEIP).

In 2008, CES marketed approximately 528 Bcf of natural gas, transportation and related energy services to approximately 9,700 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 Arkansas, 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 2.3 Bcf of storage at its Pierce Junction facility in Texas.

CES currently transports natural gas on over 32 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
 
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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 2008, CES’ VaR averaged $1.5 million with a high of $2.8 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 227 miles of intrastate pipeline in Louisiana and Texas and holds storage facilities of approximately 2.3 Bcf in Texas under long-term leases. In addition, CES leases transportation capacity of approximately 1.1 Bcf per day on various inter- and intrastate pipelines and approximately 8.8 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 available supply and relative price of natural gas in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.

In 2008, approximately 15% of CEGT and MRT’s total operating revenue was attributable to services provided to Gas Operations, an affiliate, and approximately 7% 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. Effective April 1, 2008, MRT signed a 5-year extension of its firm transportation and storage contracts with Laclede. Agreements for firm transportation, “no notice” transportation service and storage services in certain of Gas Operations’ service areas (Arkansas, Louisiana, Oklahoma and Texas) will expire in 2012.

Carthage to Perryville.   In April 2008, CEGT completed the Phase III expansion of the Carthage to Perryville pipeline. This expansion included additional compression and authorization from the Pipeline and Hazardous Materials Safety Administration (PHMSA) to operate the line at higher pressures. The Carthage to Perryville pipeline can now operate at up to 1.5 Bcf per day. CEGT filed with FERC on December 5, 2008 to increase the Carthage to Perryville capacity to approximately 1.9 Bcf per day. The expansion includes a new compressor unit at two of CEGT’s existing stations and is currently projected to be placed in service in the second quarter of 2010.

Southeast Supply Header.   The Southeast Supply Header (SESH) pipeline project, a joint venture between CEGT and Spectra Energy Corp., was placed into commercial service on September 6, 2008. This new 270-mile pipeline, which extends from the Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of approximately one Bcf per day. The pipeline represents a new source of natural gas supply for the Southeast United States and offers greater supply diversity to this region. Our share of SESH’s net construction costs is approximately $625 million.
   
     Assets

Our interstate pipelines business currently owns and operates approximately 8,000 miles of natural gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. We also own and operate six natural gas storage fields with a combined daily deliverability of approximately 1.2 Bcf and a combined working gas capacity of approximately 59 Bcf. We also own 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. Our 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, 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 1.3 Bcf per day of natural gas and, either directly or through its 50% interest in a 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.

Our field services business operations may be affected by changes in the demand for natural gas and natural gas liquids (NGLs), the available supply and relative price of natural gas and NGLs in the Mid-continent and Gulf Coast natural gas supply regions and general economic conditions.
 
     Assets

Our field services business owns and operates approximately 3,600 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 150 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, 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 among forms of energy is impacted by commodity pricing levels and influences the level of drilling activity and demand for our gathering operations.

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.

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 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 TRE. 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 nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility and transition charges associated with securitization of regulatory assets and securitization of stranded costs.

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 Interim Transmission Costs of Service Update.   In September 2008, CenterPoint Houston filed an application with the Texas Utility Commission requesting an interim update to its wholesale transmission rate. The filing resulted in a revenue requirement increase of $22.5 million over rates then in effect. Approximately 74% will be paid by distribution companies other than CenterPoint Houston. The remaining 26% represents CenterPoint Houston’s share. That amount cannot be included in rates until 2010 under the terms of the rate freeze implemented in the settlement of CenterPoint Houston’s 2006 rate proceeding described below. In November 2008, the Texas Utility Commission approved CenterPoint Houston’s request. The interim rates became effective for service on and after November 5, 2008.
 
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, the implementation of charges associated with securitizations, the impact of severe
 
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weather such as hurricanes and certain other force majeure events. 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.

In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory. Of the 47 cities, 23 either affirmatively approved or allowed the filed rates to go into effect by operation of law. Nine other cities were represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities were represented by the Gulf Coast Coalition of Cities (GCCC). In July 2008, Gas Operations reached a settlement agreement with the GCCC. That settlement agreement, if implemented across the entire Texas Coast service territory, would allow Gas Operations a $3.4 million annual increase in revenues. The TCUC cities denied the rate change request and Gas Operations appealed the denial of rates to the Railroad Commission. The Railroad Commission issued an order in October 2008, which, if implemented across the entire Texas Coast service territory, would result in an annual revenue increase of $3.7 million. Both the Railroad Commission order and the settlement provide for an annual rate adjustment mechanism to reflect changes in operating expenses and revenues as well as changes in capital investment and associated changes in revenue-related taxes. In December 2008, the Railroad Commission issued an order on rehearing. Parties have filed second motions for rehearing on this order. However, in December 2008, Gas Operations implemented the approved rates for the nine TCUC cities and the environs, subject to refund. The impact of the Railroad Commission’s order on rehearing on the settled rates is still under review, and how rates will be conformed among all cities in the Texas Coast service territory is unknown at this time. A final decision from the Railroad Commission regarding the second motions for rehearing is expected no later than March 2009.

Minnesota.   In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision. In January 2009, the Minnesota Supreme Court heard oral arguments. While there is no deadline for a decision, a decision is expected by the end of the third quarter of 2009. While no prediction can be made as to the ultimate outcome, this matter will have no negative impact on our financial condition, results of operations or cash flows.

In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service. If approved by the MPUC, the proposed new rates would result in an overall increase in annual revenue of $59.8 million. The proposed increase would allow Gas Operations to recover increased operating costs, including higher bad debt and collection expenses, the cost of improved customer service and inflationary increases in other
 
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expenses. It also would allow recovery of increased costs related to conservation improvement programs and provide a return for the additional capital invested to serve its customers. In addition, Gas Operations is seeking an adjustment mechanism that would annually adjust rates to reflect changes in use per customer. In December 2008, the MPUC accepted the case and approved an interim rate increase of $51.2 million, which became effective on January 2, 2009, subject to refund. The MPUC is allowed ten months to issue a final decision; however, an extension of time can occur in certain circumstances.

Department of Transportation

In December 2006, Congress enacted the Pipeline Inspection, Protection, Enforcement and Safety Act of 2006 (2006 Act), which reauthorized the programs adopted under the Pipeline Safety Improvement Act of 2002 (2002 Act). These programs included several requirements related to ensuring pipeline safety, and a requirement to assess the integrity of pipeline transmission facilities in areas of high population concentration. Under the legislation, remediation activities are to be performed over a 10-year period. Our pipeline subsidiaries are on schedule to comply with the timeframe mandated for completion of integrity assessment and remediation.

Pursuant to the 2002 Act, and then the 2006 Act, the Pipeline and Hazardous Materials Safety Administration (PHMSA) of the U.S. Department of Transportation (DOT) has adopted a number of rules concerning, among other things, distinguishing between gathering lines and transmission facilities, requiring certain design and construction features in new and replaced lines to reduce corrosion and requiring pipeline operators to amend existing written operations and maintenance procedures and operator qualification programs.

We anticipate that compliance with these regulations and performance of the remediation activities by CERC’s interstate and intrastate pipelines, and natural gas distribution companies will require increases in both capital expenditures and operating costs. The level of expenditures will depend upon several factors, including age, location and operating pressures of the facilities. Based on our interpretation of the rules written to date and preliminary technical reviews, we believe compliance will require annual expenditures (capital and operating costs combined) of approximately $17 to 24 million during the initial 10-year period.

ENVIRONMENTAL MATTERS

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment. As an owner or operator of natural gas pipelines, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

 
restricting the way we can handle or dispose of 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, the principal component of the natural gas that 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 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. While there is growing consensus that some form of global climate change program will be adopted, it is too early to determine when, 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 that 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
 
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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.

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

Manufactured Gas Plant Sites.   CERC and its predecessors operated manufactured gas plants (MGPs) 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, 2008, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for
 
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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 (PRPs), 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, 2008, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the 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 responsible parties, including CERC, would have to contribute to that remediation. CERC is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of the site under 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 facilities owned by us 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. Under the terms of the arrangements regarding separation of the generating business from us and our sale to NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by NRG Texas LP, 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 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.

Groundwater Contamination Litigation.   Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al ., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In January 2009, CERC and the plaintiffs reached agreement on the terms of a settlement that, if ultimately approved by the Louisiana Department of Natural Resources and the court, is expected to finally resolve this litigation. We and CERC do not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either us or CERC.

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
 
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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, 2008, we had 8,801 full-time employees. The following table sets forth the number of our employees by business segment:

Business Segment
 
Number
   
Number Represented
by Unions or
Other Collective
Bargaining Groups
 
Electric Transmission & Distribution
    2,858       1,236  
Natural Gas Distribution
    3,652       1,405  
Competitive Natural Gas Sales and Services
    122        
Interstate Pipelines
    654        
Field Services
    215        
Other Operations
    1,300        
Total
    8,801       2,641  

As of December 31, 2008, approximately 30% of our employees are subject to collective bargaining agreements. One of the collective bargaining agreements covering approximately 5% of our employees, Gas Workers Union Local No. 340, is scheduled to expire in 2009. We have a good relationship with this bargaining unit and expect to negotiate a new agreement in 2009.

EXECUTIVE OFFICERS
(as of February 25, 2009)

Name
 
Age
 
Title
David M. McClanahan
 
 
59
 
President and Chief Executive Officer and Director
 
Scott E. Rozzell
 
 
59
 
Executive Vice President, General Counsel and Corporate Secretary
 
Gary L. Whitlock
 
 
59
 
Executive Vice President and Chief Financial Officer
 
C. Gregory Harper
 
 
44
 
Senior Vice President and Group President, CenterPoint Energy Pipelines and Field Services
 
Thomas R. Standish
 
 
59
 
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 previously served as Chairman of the Board of Directors of ERCOT, Chairman of the Board of the University of St. Thomas in Houston and the Chairman of the Board of the American Gas Association. He currently serves on the boards of the Edison Electric Institute and 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 Reliant 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.

C. Gregory Harper has served as Senior Vice President and Group President of CenterPoint Energy Pipelines and Field Services since December 2008. Before joining CenterPoint Energy in 2008, Mr. Harper served as President, Chief Executive Officer and as a Director of Spectra Energy Partners, LP from March 2007 to December 2008. From January 2007 to March 2007, Mr. Harper was Group Vice President of Spectra Energy Corp., and he was Group Vice President of Duke Energy from January 2004 to December 2006. Mr. Harper served as Senior Vice President of Energy Marketing for Duke Energy North America from January 2003 until January 2004 and Vice President of Business Development for Duke Energy Gas Transmission and Vice President of East Tennessee Natural Gas, LLC from March 2002 until January 2003. 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 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.

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 its 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 certain other adjustments.

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 as requested by the Texas Utility Commission; and

 
affirmed the district court’s judgment in all other respects.

In April 2008, the court of appeals denied all motions for rehearing and reissued substantially the same opinion as it had rendered in December 2007.

In June 2008, CenterPoint Houston petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, CenterPoint Houston seeks reversal of the parts of the court of appeals decision that (i) denied recovery of EMCs paid to RRI, (ii) denied recovery of the capacity auction true-up amounts allowed by the district court, (iii) affirmed the Texas Utility Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit CenterPoint Houston to utilize the partial stock valuation methodology for determining the market value of its former generation assets. Two other petitions for review were filed with the Texas Supreme Court by other parties to the appeal. In those petitions parties contend that (i) the Texas Utility Commission was without authority to fashion the methodology it used for valuing the former generation assets after it had determined that CenterPoint Houston could not use the partial stock valuation method, (ii) in fashioning the method it used for valuing the former generating assets, the Texas Utility Commission deprived parties of their due process rights and an opportunity to be heard, (iii) the net book value of the generating assets should have been adjusted downward due to the impact of a purchase option that had been granted to RRI, (iv) CenterPoint Houston should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true up award.

Review by the Texas Supreme Court of the court of appeals decision is at the discretion of the court. In November 2008, the Texas Supreme Court requested the parties to the Petitions for Review to submit briefs on the merits of the issues raised. Briefing at the Texas Supreme Court should be completed in the second quarter of 2009. Although the Texas Supreme Court has not indicated whether it will grant review of the lower court’s decision, its request for full briefing on the merits allowed the parties to more fully explain their positions. There is no prescribed time in which the Texas Supreme Court must determine whether to grant review or, if review is granted, for a decision by that 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 appeal to the Texas Supreme Court, we can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, 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 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 $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008.

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 that 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, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit utilities like CenterPoint Houston to
 
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pass the tax benefits back to customers without creating normalization violations. In addition, we received a PLR from the IRS in August 2007, prior to adoption of the final regulations that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require 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. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals, though the Texas Supreme Court, if it grants review, will have authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. 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 must seek recovery of significant restoration costs arising from Hurricane Ike.

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast on September 13, 2008. CenterPoint Houston estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Ike will be in the range of $600 million to $650 million.

CenterPoint Houston believes it is entitled to recover prudently incurred storm costs in accordance with applicable regulatory and legal principles. The Texas Legislature currently is considering  passage of legislation that would (i) authorize the Texas Utility Commission to determine the amount of storm restoration costs that CenterPoint Houston would be entitled to recover and (ii) permit the Texas Utility Commission to issue a financing order that would allow CenterPoint Houston to recover the amount of storm restoration costs determined in such a proceeding through issuance of dedicated securitization bonds, which would be repaid over time through a charge imposed on REPs. In proceedings to determine and seek recovery of storm restoration costs under the proposed legislation, CenterPoint Houston would be required to prove to the Texas Utility Commission’s satisfaction its prudently incurred costs as well as to demonstrate the cost benefit from using securitization to recover those costs instead of alternative means. Alternatively, CenterPoint Houston has the right to seek recovery of these costs under traditional rate making principles. CenterPoint Houston’s failure to recover costs incurred as a result of Hurricane Ike could adversely affect its liquidity, results of operations and financial condition. For more information about CenterPoint Houston’s recovery from Hurricane Ike, please read “Business — Electric Transmission & Distribution — Hurricane Ike” in Item 1 of this report.
 
CenterPoint Houston’s receivables are concentrated in a small number of retail electric providers, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.
 
CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. As of December 31, 2008, CenterPoint Houston did business with 79 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 REPs to pay for CenterPoint Houston’s services or could cause them to delay such payments. In 2008, seven REPs selling power within CenterPoint Houston’s service territory ceased to operate, and their customers were transferred to the provider of last resort or to other REPs. 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 REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston can demand credit protection from REPs for payments not made prior to the shift to the provider of last resort. However,
 
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the Texas Utility Commission is currently considering proposed revisions to those regulations that, as currently proposed, would (i) increase the credit protections that could be required from REPs, and (ii) allow utilities to defer the loss of  payments for recovery in a future rate case. Whether such revised regulations will ultimately be adopted and their terms cannot now be determined. RRI, through its subsidiaries, is CenterPoint Houston’s largest customer. Approximately 46% of CenterPoint Houston’s $141 million in billed receivables from REPs at December 31, 2008 was owed by subsidiaries of RRI. Any delay or default in payment by REPs such as RRI could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event RRI’s subsidiaries might seek to avoid honoring their obligations and claims might be made by creditors involving payments CenterPoint Houston has received from RRI’s subsidiaries.

Rate regulation of CenterPoint Houston’s business may delay or deny CenterPoint Houston’s ability to earn a reasonable return and fully recover its costs.

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. The regulatory process 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.

In this regard, pursuant to the Stipulation and Settlement Agreement approved by the Texas Utility Commission in September  2006, until June 30, 2010 CenterPoint Houston is limited in its ability to request retail rate relief. For more information on the Stipulation and Settlement Agreement, please read “Business — Regulation — State and Local Regulation — Electric Transmission & Distribution — CenterPoint Houston Rate Agreement” in Item 1 of this report.

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 could 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 REP based on the amount of electricity it delivers 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.
 
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 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 alternate 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 and reduced volumes, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other natural gas distributors and marketers also compete directly with CERC for natural gas sales to end-users. In addition, as a result of federal regulatory changes affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass CERC’s facilities and market, sell and/or transport natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

CERC’s two interstate pipelines and its gathering systems compete with other interstate and intrastate pipelines and gathering systems in the transportation and storage of natural gas. The principal elements of competition are rates, terms of service, and flexibility and reliability of service. They also compete indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price. The actions of CERC’s competitors could lead to lower prices, which may have an adverse impact on CERC’s results of operations, financial condition and cash flows. Additionally, any reduction in the volume of natural gas transported or stored 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 prices, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity and results of operations.

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 (i) apply downward demand pressure on natural gas consumption in the areas in which CERC operates thereby resulting in decreased sales volumes and revenues and (ii) 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.

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’s results of operations, financial condition and cash flows could 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 and price 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. The level of drilling and production activity in these regions is dependent on economic and business factors beyond our control. The primary factor affecting both the level of drilling activity and production volumes is natural gas pricing. A sustained decline in natural gas prices could result in a decrease in exploration and development activities in the regions served by our gathering and pipeline transportation systems and our natural gas treating and processing activities. A sustained decline could also lead producers to shut in production from their existing wells. Other factors that impact production decisions include the level of production costs relative to other available production, producers’ access to needed capital and the cost of that capital, the ability of producers to obtain necessary drilling and other governmental permits, access to drilling rigs and regulatory changes. Because of these factors, even if new natural gas reserves are discovered in areas served by our assets, producers may choose not to develop those reserves or to shut in production from
 
25

existing reserves. 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 from these businesses are also affected by the prices of natural gas and natural gas liquids (NGL). NGL prices generally fluctuate on a basis that correlates to fluctuations in crude oil prices. In the past, the prices of natural gas and crude oil have been extremely volatile, and we expect this volatility to continue. The markets and prices for natural gas, NGLs and crude oil depend upon factors beyond our control. These factors include supply of and demand for these commodities, which fluctuate with changes in market and economic conditions and other factors.

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 had planned.

Subsidiaries of CERC Corp. have been recently involved in significant pipeline construction projects and, depending on available opportunities, may, from time to time, be involved in additional significant pipeline construction projects in the future. 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 planned cost, on schedule or at all. The construction of new pipeline or compression facilities is subject to construction cost overruns due to labor costs, costs of equipment and materials such as steel and nickel, labor shortages or delays, weather delays, inflation or other factors, which could be material. In addition, the construction of these facilities is typically subject to the receipt of approvals and permits from various regulatory agencies. Those agencies may not approve the projects in a timely manner or may impose restrictions or conditions on the projects that could potentially prevent a project from proceeding, lengthen its expected completion schedule and/or increase its anticipated cost. As a result, there is the risk that the new facilities may not be able to achieve CERC’s expected investment return, which could adversely affect CERC’s financial condition, results of operations or cash flows.

The states in which CERC provides regulated local gas distribution may, either through legislation or rules, adopt restrictions similar to or broader than those under the Public Utility Holding Company Act of 1935 regarding organization, financing and affiliate transactions that could have significant adverse impacts on CERC’s ability to operate.

The Public Utility Holding Company Act of 1935, to which we and our subsidiaries were 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, 2008, we had $10.7 billion of outstanding indebtedness on a consolidated basis, which includes $2.6 billion of non-recourse transition bonds. As of December 31, 2008, approximately $953 million principal amount of this debt is required to be paid through 2011. This amount excludes principal repayments of approximately $669 million on transition bonds, for which a dedicated revenue stream exists. Our future financing activities may be significantly affected by, among other things:

 
the resolution of the true-up components, including, in particular, the results of appeals to the courts regarding rulings obtained to date;

 
CenterPoint Houston’s recovery of costs arising from Hurricane Ike;

 
general economic and capital market conditions;

 
credit availability from financial institutions and other lenders;

 
investor confidence in us and the markets in which we operate;

 
maintenance of acceptable credit ratings;

 
market expectations regarding our future earnings and cash flows;

 
market perceptions of our ability to access capital markets on reasonable terms;

 
our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; and

 
provisions of relevant tax and securities laws.

As of December 31, 2008, CenterPoint Houston had outstanding approximately $2.6 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, $600 million securing borrowings under a credit facility which was unutilized 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 $1.8 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, 2008. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions. In January 2009, CenterPoint Houston issued $500 million aggregate principal amount of general mortgage bonds in a public offering.
 
Our current credit ratings are discussed in “Management’s Discussion and Analysis of Financial Condition and Results of Operations of CenterPoint Energy, Inc. and Subsidiaries — Liquidity and Capital Resources — Future Sources and Uses of Cash — Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

As a holding company with no operations of our own, we will depend on distributions from our subsidiaries to meet our payment obligations, and provisions of applicable law or contractual restrictions could limit the amount of those distributions.

We derive all our operating income from, and hold all our assets through, our subsidiaries. As a result, we will depend on distributions from our subsidiaries in order to meet our payment obligations. In general, these subsidiaries are separate and distinct legal entities and have no obligation to provide us with funds for our payment obligations, whether by dividends, distributions, loans or otherwise. In addition, provisions of applicable law, such as those limiting the legal sources of dividends, limit our subsidiaries’ ability to make payments or other distributions to us, and our subsidiaries could agree to contractual restrictions on their ability to make distributions.

Our right to receive any assets of any subsidiary, and therefore the right of our creditors to participate in those assets, will be effectively subordinated to the claims of that subsidiary’s creditors, including trade creditors. In addition, even if we were a creditor of any subsidiary, our rights as a creditor would be subordinated to any security interest in the assets of that subsidiary and any indebtedness of the subsidiary senior to that held by us.

The use of derivative contracts by us and our subsidiaries in the normal course of business could result in financial losses that could negatively impact our results of operations and those of our subsidiaries.

We and our subsidiaries use derivative instruments, such as swaps, options, futures and forwards, to manage our commodity, weather and financial market risks. We and our subsidiaries could recognize financial losses as a result of volatility in the market values of these contracts, or should a counterparty fail to perform. In the absence of actively quoted market prices and pricing information from external sources, the valuation of these financial instruments can involve management’s judgment or use of estimates. As a result, changes in the underlying assumptions or use of alternative valuation methods could affect the reported fair value of these contracts.

Risks Common to Our Businesses and Other Risks

We are subject to operational and financial risks and liabilities arising from environmental laws and regulations.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment as described in “Business — Environmental Matters” in Item 1 of this Form 10-K. 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. CenterPoint Houston may not be able to recover the costs incurred in restoring its transmission and distribution properties following Hurricane Ike, or any such costs sustained in the future, through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

We, CenterPoint Houston and CERC could incur liabilities associated with businesses and assets that we have transferred to others.

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), a predecessor of CenterPoint Houston, directly or through subsidiaries and include:

 
merchant energy, energy trading and REP businesses transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and

 
Texas electric generating facilities transferred to Texas Genco Holdings, Inc. (Texas Genco) in 2004 and early 2005.
 
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
 
29

in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement, RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the revised agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

The potential exposure to CERC under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $108 million as of December 31, 2008. RRI continues to meet its obligations under the contracts, and on the basis of market conditions, we and CERC have not required additional security. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain our exposure to the counterparty under the guaranty.

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, CenterPoint Houston or CERC could incur liability if claims in one or more of these lawsuits were successfully asserted against us, CenterPoint Houston or CERC 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 NRG Texas LP (previously named 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 NRG Texas LP. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and we have assumed and agreed to indemnify NRG Texas LP 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 NRG Texas LP 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 number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by us, but most existing claims relate to facilities previously owned by us or our subsidiaries but currently owned by 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 NRG Texas LP, ultimate financial responsibility for uninsured losses from claims relating to
 
30

the generating business has been assumed by NRG Texas LP, 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 NRG Texas LP.

The global financial crisis may have impacts on our business, liquidity and financial condition that we currently cannot predict.

The continued credit crisis and related turmoil in the global financial system may have an impact on our business, liquidity and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. With respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which had an approximately four percent participation in our credit facility and each of the then-existing credit facilities of our subsidiaries, stopped funding its commitments following the bankruptcy filing of its parent in September 2008 and was subsequently terminated as a lender in our facility and the facility of CenterPoint Houston. Defaults of other lenders should they occur could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of our pension plan. These reductions are expected to result in increased non-cash pension expense in 2009, which will impact 2009 results of operations.

In addition to the credit and financial market issues, the national and local recessionary conditions may impact our business in a variety of ways. These include, among other things, reduced customer usage, increased customer default rates and wide swings in commodity prices.

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.
 
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 3 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 2008.
 
 
PART II

Item 5.               Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

As of February 13, 2009, our common stock was held of record by approximately 47,327 shareholders. Our common stock is listed on the New York and Chicago Stock Exchanges and is traded under the symbol “CNP.”

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.
 
   
Market Price
   
Dividend
 
         
Declared
 
   
High
   
Low
   
Per Share
 
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                  
                         
2008
                       
First Quarter
                  $ 0.1825  
January 9
  $ 16.98                  
March 17
          $ 13.84          
Second Quarter
                  $ 0.1825  
April 1
          $ 14.66          
May 29
  $ 17.16                  
Third Quarter
                  $ 0.1825  
August 11
  $ 16.59                  
September 18
          $ 13.98          
Fourth Quarter
                  $ 0.1825  
October 1
  $ 14.40                  
October 10
          $ 9.08          

The closing market price of our common stock on December 31, 2008 was $12.62 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 22, 2009, we announced a regular quarterly cash dividend of $0.19 per share, payable on March 10, 2009 to shareholders of record on February 16, 2009.

Repurchases of Equity Securities

During the quarter ended December 31, 2008, 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.
 
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,
 
   
2004(1)
   
2005(2)
   
2006
   
2007
   
2008
 
   
(In millions, except per share amounts)
 
       
Revenues
  $ 7,999     $ 9,722     $ 9,319     $ 9,623     $ 11,322  
Income from continuing operations before extraordinary item
    205       225       432       399       447  
Discontinued operations, net of tax
    (133 )     (3 )                  
Extraordinary item, net of tax
    (977 )     30                    
Net income (loss)
  $ (905 )   $ 252     $ 432     $ 399     $ 447  
Basic earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 0.67     $ 0.72     $ 1.39     $ 1.25     $ 1.33  
Discontinued operations, net of tax
    (0.43 )     (0.01 )                  
Extraordinary item, net of tax
    (3.18 )     0.10                    
Basic earnings (loss) per common share
  $ (2.94 )   $ 0.81     $ 1.39     $ 1.25     $ 1.33  
Diluted earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 0.61     $ 0.67     $ 1.33     $ 1.17     $ 1.30  
Discontinued operations, net of tax
    (0.37 )     (0.01 )                  
Extraordinary item, net of tax
    (2.72 )     0.09                    
Diluted earnings (loss) per common share
  $ (2.48 )   $ 0.75     $ 1.33     $ 1.17     $ 1.30  
                                         
Cash dividends paid per common share
  $ 0.40     $ 0.40     $ 0.60     $ 0.68     $ 0.73  
Dividend payout ratio from continuing operations
    60 %     56 %     43 %     54 %     55 %
Return from continuing operations on average common equity
    14.4 %     18.7 %     30.3 %     23.7 %     23.2 %
Ratio of earnings from continuing operations to fixed charges
    1.43       1.51       1.77       1.86       2.09  
At year-end:
                                       
Book value per common share
  $ 3.59     $ 4.18     $ 4.96     $ 5.61     $ 5.89  
Market price per common share
    11.30       12.85       16.58       17.13       12.62  
Market price as a percent of book value
    315 %     307 %     334 %     305 %     214 %
Assets of discontinued operations
  $ 1,565     $     $     $     $  
Total assets
    18,096       17,116       17,633       17,872       19,676  
Short-term borrowings (3)
                187       232       153  
Transition bonds, including current maturities
    676       2,480       2,407       2,260       2,589  
Other long-term debt, including current maturities
    8,353       6,427       6,593       7,419       7,925  
Capitalization:
                                       
Common stock equity
    11 %     13 %     15 %     16 %     16 %
Long-term debt, including current maturities
    89 %     87 %     85 %     84 %     84 %
Capitalization, excluding transition bonds:
                                       
Common stock equity
    12 %     17 %     19 %     20 %     20 %
Long-term debt, excluding transition bonds, including current maturities
    88 %     83 %     81 %     80 %     80 %
Capital expenditures, excluding discontinued operations
  $ 530     $ 719     $ 1,121     $ 1,011     $ 1,053  
__________
(1)
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 as discontinued operations 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.

(2)
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.

(3)
Under the terms of the receivables facilities in place since October 2006, the provisions for sale accounting under Statement of Financial Accounting Standards No. 140, “Accounting for Transfers and Servicing of Financial Assets and Extinguishments of Liabilities,” have not been met. Accordingly, advances received upon the sale of receivables are accounted for as short-term borrowings as of December 31, 2006, 2007 and 2008. As of December 31, 2008, short-term borrowings included a $75 million inventory financing obligation related to an asset management agreement. For more information regarding this transaction, see Note 8(a).
 


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 Management’s Discussion, 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 certain 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, economic conditions, 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 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, 2008 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 over 2 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.6 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 CenterPoint Houston’s certificated service territory. The Electric Reliability Council of Texas, Inc. (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 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 (Gas Operations), 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 8,000 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 billion cubic feet (Bcf) and a combined working gas capacity of approximately 59 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. Its storage capacity in the Bistineau facility is 8 Bcf of working gas with 100 million cubic feet per day of deliverability. Most storage operations are in north Louisiana and Oklahoma.

Field Services

CERC’s field services business owns and operates approximately 3,600 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 150 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.

EXECUTIVE SUMMARY

Significant Events in 2008 and 2009

Hurricane Ike

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast early Saturday, September 13, 2008.

The strong Category 2 storm initially left more than 90% of CenterPoint Houston’s more than 2 million metered customers without power, the largest outage in CenterPoint Houston’s 130-year history. Most of the widespread power outages were due to power lines damaged by downed trees and debris blown by Hurricane Ike’s winds. In addition, on Galveston Island and along the coastal areas of the Gulf of Mexico and Galveston Bay, the storm surge and flooding from rains accompanying the storm caused significant damage or destruction of houses and businesses served by CenterPoint Houston.

CenterPoint Houston estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Ike will be in the range of $600 million to $650 million. As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole mounted equipment that comprise CenterPoint Houston’s transmission and distribution system are not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $17 million.

In addition to storm restoration costs, CenterPoint Houston lost approximately $17 million in revenue through December 31, 2008. Within the first 18 days after the storm, CenterPoint Houston had restored power to all customers capable of receiving it.

 
CenterPoint Houston has deferred the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. As a result, storm restoration costs did not affect our or CenterPoint Houston’s reported net income for 2008. As of December 31, 2008, CenterPoint Houston recorded an increase of $145 million in construction work in progress and $435 million in regulatory assets for restoration costs incurred through December 31, 2008. Approximately $73 million of these costs are based on estimates and are included in accounts payable as of December 31, 2008. Additional restoration costs will continue to be incurred in 2009.

Assuming necessary enabling legislation is enacted by the Texas Legislature in the session that began in January 2009, CenterPoint Houston expects to seek a financing order from the Texas Utility Commission to obtain recovery of its storm restoration costs through the issuance of non-recourse securitization bonds similar to the storm recovery bonds issued by another Texas utility following the hurricanes that affected that utility’s service territories in 2005. Assuming those bonds are issued, CenterPoint Houston will recover the amount of storm restoration costs determined by the Texas Utility Commission to have been prudently incurred out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. Alternatively, if securitization is not available, recovery of those costs would be sought through traditional regulatory mechanisms. Under its 2006 rate case settlement, CenterPoint Houston is entitled to seek an adjustment to rates in this situation, even though in most instances its rates are frozen until 2010.

Gas Operations also suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana. As of December 31, 2008, Gas Operations has deferred approximately $4 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

Debt Financing Transactions

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) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement.

In April 2008, we purchased $175 million principal amount of pollution control bonds issued on our behalf at 102% of their principal amount. Prior to the purchase, $100 million principal amount of such bonds had a fixed rate of interest of 7.75% and $75 million principal amount of such bonds had a fixed rate of interest of 8%. Depending on market conditions, we may remarket both series of bonds, at 100% of their principal amounts, in 2009.

In April 2008, we called our 3.75% convertible senior notes for redemption on May 30, 2008. At the time of the announcement, the notes were convertible at the option of the holders, and substantially all of the notes were submitted for conversion on or prior to the May 30, 2008 redemption date. During the year ended December 31, 2008, we issued 16.9 million shares of our common stock and paid cash of approximately $532 million to settle conversions of approximately $535 million principal amount of our 3.75% convertible senior notes.

In May 2008, we issued $300 million aggregate principal amount of senior notes due in May 2018 with an interest rate of 6.50%. The proceeds from the sale of the senior notes were used for general corporate purposes, including the satisfaction of cash payment obligations in connection with conversions of our 3.75% convertible senior notes as discussed above.

In May 2008, CERC Corp. issued $300 million aggregate principal amount of senior notes due in May 2018 with an interest rate of 6.00%. The proceeds from the sale of the senior notes were used for general corporate purposes, including capital expenditures, working capital and loans to or investments in affiliates.
 
In November 2008, CERC replaced a receivables facility that had expired in October 2008 with a new receivables facility that expires in November 2009. Availability under the new facility ranges from $128 million to $375 million, reflecting seasonal changes in receivables balances.
 
In November 2008, CenterPoint Houston entered into a $600 million 364-day credit facility. The credit facility will terminate if bonds are issued to securitize the costs incurred as a result of Hurricane Ike and if those bonds are issued prior to the November 24, 2009 expiration of the facility. CenterPoint Houston expects to seek legislative and regulatory approval for the issuance of such bonds during 2009.

In December 2008, CERC entered into an asset management agreement whereby it sold $110 million of its natural gas in storage and agreed to repurchase an equivalent amount of natural gas during the 2008-2009 winter heating season for payments totaling $114 million. This transaction was accounted for as a financing and, as of December 31, 2008, the consolidated financial statements reflect natural gas inventory of $75 million and a financing obligation of $75 million related to this transaction.

In January 2009, CenterPoint Houston issued $500 million aggregate principal amount of general mortgage bonds due in March 2014 with an interest rate of 7.00%. The proceeds from the sale of the bonds were used for general corporate purposes, including the repayment of outstanding borrowings under its revolving credit facility and the money pool, capital expenditures and storm restoration costs associated with Hurricane Ike.

Equity Financing Transactions

In 2008, we received proceeds of approximately $65 million from the sale of approximately 4.9 million common shares to our defined contribution plan and proceeds of approximately $13 million from the sale of approximately 0.9 million common shares to participants in our enhanced dividend reinvestment plan.

Interstate Pipeline Expansion

The Southeast Supply Header (SESH) pipeline project, a joint venture between CenterPoint Energy Gas Transmission, a wholly owned subsidiary of CERC Corp., and Spectra Energy Corp., was placed into commercial service on September 6, 2008. This new 270-mile pipeline, which extends from the Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of approximately one Bcf per day. The pipeline represents a new source of natural gas supply for the Southeast United States and offers greater supply diversity to this region. Our share of SESH’s net construction costs is approximately $625 million.

Outlook

During 2008, economic conditions in the United States declined significantly, with several large bank failures and consolidations, large declines in the values of securities, disruptions in the capital markets, which made it difficult to raise debt and equity, and increased costs for capital when it was available. Many of the factors that led to the economic decline are continuing into 2009, but it is impossible to predict the impacts such events may have in the future. Although our businesses and the areas in which we serve have, to date, not been as significantly affected as some others, in 2008, we experienced substantial declines in the value of our pension plan assets as a result of the stock market declines. Disruptions in the bank and capital markets during the last two quarters of 2008 have led to higher borrowing costs and greater uncertainty regarding the ability to execute transactions in these markets.

Although we cannot predict future performance, the decline in the value of our pension plan assets that occurred during 2008 will result in increased non-cash charges to pension plan expense in 2009, which will adversely impact earnings, and may also result in the need for us to make significant cash contributions to our pension plan subsequent to 2009. We also expect to experience higher borrowing costs and greater uncertainty in executing capital markets transactions if conditions in financial markets do not improve from their current state.

To the extent the adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer. The current low commodity prices for natural gas and other energy products may cause energy producers to scale back projects such as drilling new gas wells or constructing new facilities. Reduced demand and lower energy prices could lead to financial pressure on some of our customers who operate within the energy industry. Also, adverse economic conditions, coupled with concerns for protecting the environment, may cause consumers to use less energy or avoid expansions of their facilities, resulting in less demand for our services.
 
These factors may lead to reduced earnings during 2009, compared to 2008, if they continue significantly into 2009 or if the magnitude of the economic downturn increases beyond the impacts experienced in 2008.

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 legislative and regulatory actions allowing securitization or other recovery of costs associated with Hurricane Ike;

 
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 and natural gas liquids;

 
the timing and extent of changes in the supply of natural gas;

 
the timing and extent of changes in natural gas basis differentials;

 
weather variations and other natural phenomena;

 
changes in interest rates or rates of inflation;

 
commercial bank and financial market conditions, our access to capital, the cost of such capital, and the results of our financing and refinancing efforts, including availability of funds in the debt capital markets;

 
actions by rating agencies;

 
effectiveness of our risk management activities;

 
inability of various counterparties to meet their obligations to us;

 
non-payment for our services due to financial distress of our customers, including Reliant Energy, Inc. (RRI);

 
the ability of RRI and its subsidiaries to satisfy their other obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

 
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.
 
CONSOLIDATED RESULTS OF OPERATIONS

All dollar amounts in the tables that follow are in millions, except for per share amounts.

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
                   
Revenues
  $ 9,319     $ 9,623     $ 11,322  
Expenses
    8,274       8,438       10,049  
Operating Income
    1,045       1,185       1,273  
Gain (Loss) on Time Warner Investment
    94       (114 )     (139 )
Gain (Loss) on Indexed Debt Securities
    (80 )     111       128  
Interest and Other Finance Charges
    (470 )     (503 )     (466 )
Interest on Transition Bonds
    (130 )     (123 )     (136 )
Distribution from AOL Time Warner Litigation Settlement
          32        
Additional Distribution to ZENS Holders
          (27 )      
Equity in Earnings of Unconsolidated Affiliates
    6       16       51  
Other Income, net
    29       17       14  
Income Before Income Taxes
    494       594       725  
Income Tax Expense
    (62 )     (195 )     (278 )
Net Income
  $ 432     $ 399     $ 447  
                         
Basic Earnings Per Share
  $ 1.39     $ 1.25     $ 1.33  
                         
Diluted Earnings Per Share
  $ 1.33     $ 1.17     $ 1.30  

2008 Compared to 2007

Net Income. We reported net income of $447 million ($1.30 per diluted share) for 2008 compared to $399 million ($1.17 per diluted share) for the same period in 2007. The increase in net income of $48 million was primarily due to an $88 million increase in operating income, a $37 million decrease in interest expense, excluding transition bond-related interest expense, a $35 million increase in equity in earnings of unconsolidated affiliates related primarily to SESH and a $17 million increase in the gain on our indexed debt securities. These increases in net income were partially offset by an $83 million increase in income tax expense, a $25 million increase in the loss on our Time Warner investment and a $13 million increase in interest expense on transition bonds.

Income Tax Expense. Our 2008 effective tax rate of 38.4% differed from the 2007 effective tax rate of 32.8% primarily as a result of revisions to the Texas State Franchise Tax Law (Texas margin tax) which was reported as an operating expense prior to 2008 and is now being reported as an income tax for CenterPoint Houston and a Texas state tax examination in 2007.

2007 Compared to 2006

Net Income. We reported net income of $399 million ($1.17 per diluted share) for 2007 compared to $432 million ($1.33 per diluted share) for the same period in 2006. The decrease in net income of $33 million was primarily due to a $208 million increase in the loss on our Time Warner investment, 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 2.0% Zero Premium Exchangeable Subordinated Notes due 2029 (ZENS) and Automatic Common Exchange Securities (ACES) and a $33 million increase in interest expense, excluding transition bond-related interest expense, due to higher borrowing levels. These decreases in net income were partially offset by a $191 million increase in the gain on our indexed debt securities, a $140 million increase in operating income and a $10 million increase in equity in earnings of unconsolidated affiliates.

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 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.
 
RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for 2006, 2007 and 2008. 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,
 
   
2006
   
2007
   
2008
 
Electric Transmission & Distribution
  $ 576     $ 561     $ 545  
Natural Gas Distribution
    124       218       215  
Competitive Natural Gas Sales and Services
    77       75       62  
Interstate Pipelines
    181       237       293  
Field Services
    89       99       147  
Other Operations
    (2 )     (5 )     11  
Total Consolidated Operating Income
  $ 1,045     $ 1,185     $ 1,273  
 
Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment, CenterPoint Houston, for 2006, 2007 and 2008 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
Revenues:
                 
Electric transmission and distribution utility
  $ 1,516     $ 1,560     $ 1,593  
Transition bond companies
    265       277       323  
Total revenues
    1,781       1,837       1,916  
Expenses:
                       
Operation and maintenance, excluding transition bond companies
    611       652       703  
Depreciation and amortization, excluding transition bond companies
    243       243       277  
Taxes other than income taxes
    212       223       201  
Transition bond companies
    139       158       190  
Total expenses
    1,205       1,276       1,371  
Operating Income
  $ 576     $ 561     $ 545  
                         
Operating Income:
                       
Electric transmission and distribution operations
  $ 395     $ 400     $ 407  
Competition transition charge
    55       42       5  
Transition bond companies (1)
    126       119       133  
Total segment operating income
  $ 576     $ 561     $ 545  
Throughput (in gigawatt-hours (GWh)):
                       
Residential
    23,955       23,999       24,258  
Total
    75,877       76,291       74,840  
Number of metered customers at period end:
                       
Residential
    1,743,963       1,793,600       1,821,267  
Total
    1,980,960       2,034,074       2,064,854  

 
__________
(1)
Represents the amount necessary to pay interest on the transition bonds.

 
2008 Compared to 2007. Our Electric Transmission & Distribution business segment reported operating income of $545 million for 2008, consisting of $407 million from our regulated electric transmission and distribution utility operations (TDU), exclusive of an additional $5 million from the competition transition charge (CTC), and $133 million related to transition bond companies. For 2007, operating income totaled $561 million, consisting of $400 million from the TDU, exclusive of an additional $42 million from the CTC, and $119 million related to transition bond companies. Revenues for the TDU increased due to customer growth, with over 30,000 metered customers added in 2008 ($23 million), increased usage ($15 million) in part caused by favorable weather experienced in 2008, increased transmission-related revenues ($21 million) and increased revenues from ancillary services ($5 million), partially offset by reduced revenues due to Hurricane Ike ($17 million) and the settlement of the final fuel reconciliation in 2007 ($5 million). Operation and maintenance expense increased primarily due to higher transmission costs ($43 million), the settlement of the final fuel reconciliation in 2007 ($13 million) and increased support services ($13 million), partially offset by a gain on sale of land ($9 million) and normal operating and maintenance expenses that were postponed as a result of Hurricane Ike restoration efforts ($10 million). Depreciation and amortization increased $34 million primarily due to amounts related to the CTC ($30 million), which were offset by similar amounts in revenues. Taxes other than income taxes declined $21 million primarily as a result of the Texas margin tax being classified as an income tax for financial reporting purposes in 2008 ($19 million) and a refund of prior years’ state franchise taxes ($5 million).

2007 Compared to 2006. Our Electric Transmission & Distribution business segment reported operating income of $561 million for 2007, consisting of $400 million from the TDU, exclusive of an additional $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, exclusive of an additional $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 in 2007, 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).

Natural Gas Distribution

The following table provides summary data of our Natural Gas Distribution business segment for 2006, 2007 and 2008 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
      2006
   
      2007
   
      2008
 
                   
Revenues
  $ 3,593     $ 3,759     $ 4,226  
Expenses:
                       
Natural gas
    2,598       2,683       3,124  
Operation and maintenance
    594       579       589  
Depreciation and amortization
    152       155       157  
Taxes other than income taxes
    125       124       141  
Total expenses
    3,469       3,541       4,011  
Operating Income
  $ 124     $ 218     $ 215  
Throughput (in Bcf):
                       
Residential
    152       172       175  
Commercial and industrial
    224       232       236  
Total Throughput
    376       404       411  
Number of customers at period end:
                       
Residential
    2,926,483       2,961,110       2,987,222  
Commercial and industrial
    246,351       249,877       248,476  
Total
    3,172,834       3,210,987       3,235,698  

2008 Compared to 2007. Our Natural Gas Distribution business segment reported operating income of $215 million for 2008 compared to $218 million for 2007. Operating income declined due to a combination of non-weather-related usage ($13 million), due in part to higher gas prices, higher customer-related and support services costs ($9 million), higher bad debts and collection costs ($4 million), increased costs of materials and supplies ($4 million), and an increase in depreciation and amortization and taxes other than income taxes ($3 million) resulting from increased investment in property, plant and equipment. The adverse impacts on operating income were partially offset by the net impact of rate increases ($11 million), lower labor and benefits costs ($14 million), and customer growth from the addition of approximately 25,000 customers in 2008 ($6 million).
 
2007 Compared to 2006. Our Natural Gas Distribution business segment reported operating income of $218 million for 2007 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 ($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).

Competitive Natural Gas Sales and Services

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2006, 2007 and 2008 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
                   
Revenues
  $ 3,651     $ 3,579     $ 4,528  
Expenses:
                       
Natural gas
    3,540       3,467       4,423  
Operation and maintenance
    30       31       39  
Depreciation and amortization
    1       5       3  
Taxes other than income taxes
    3       1       1  
Total expenses
    3,574       3,504       4,466  
Operating Income
  $ 77     $ 75     $ 62  
                         
Throughput (in Bcf)
    555       522       528  
                         
Number of customers at period end
    7,024       7,139       9,771  

2008 Compared to 2007. Our Competitive Natural Gas Sales and Services business segment reported operating income of $62 million for the year ended December 31, 2008 compared to $75 million for the year ended December 31, 2007. The decrease in operating income of $13 million primarily resulted from lower gains on sales of gas from previously written down inventory ($24 million) and higher operation and maintenance costs ($6 million), which were partially offset by improved margin as basis and summer/winter spreads increased ($12 million). In addition, 2008 included a gain from mark-to-market accounting ($13 million) and a write-down of natural gas inventory to the lower of average cost or market ($30 million), compared to 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) for 2007. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales.

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
 
43

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.
 
Interstate Pipelines

The following table provides summary data of our Interstate Pipelines business segment for 2006, 2007 and 2008 (in millions, except throughput data):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
                   
Revenues
  $ 388     $ 500     $ 650  
Expenses:
                       
Natural gas
    31       83       155  
Operation and maintenance
    120       125       133  
Depreciation and amortization
    37       44       46  
Taxes other than income taxes
    19       11       23  
Total expenses
    207       263       357  
Operating Income
  $ 181     $ 237     $ 293  
                         
Transportation throughput (in Bcf)
    939       1,216       1,538  

2008 Compared to 2007. Our Interstate Pipeline business segment reported operating income of $293 million for 2008 compared to $237 million for 2007. The increase in operating income was primarily driven by increased margins (revenues less natural gas costs) on the Carthage to Perryville pipeline that went into service in May 2007 ($51 million), increased transportation and ancillary services ($27 million), and a gain on the sale of two storage development projects ($18 million). These increases are partially offset by higher operation and maintenance expenses ($19 million), a write-down associated with pipeline assets removed from service ($7 million), increased depreciation expense ($2 million), and higher taxes other than income taxes ($12 million), largely due to tax refunds in 2007.

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).

Equity Earnings. In addition, this business segment recorded equity income of $6 million and $36 million (including $6 million and $33 million of pre-operating allowance for funds used during construction) in the years ended December 31, 2007 and 2008, respectively, from its 50 percent interest in SESH, a jointly-owned pipeline. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption.
 
 
Field Services

The following table provides summary data of our Field Services business segment for 2006, 2007 and 2008 (in millions, except throughput data):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
                   
Revenues
  $ 150     $ 175     $ 252  
Expenses:
                       
Natural gas
    (10 )     (4 )     21  
Operation and maintenance
    59       66       69  
Depreciation and amortization
    10       11       12  
Taxes other than income taxes
    2       3       3  
Total expenses
    61       76       105  
Operating Income
  $ 89     $ 99     $ 147  
                         
Gathering throughput (in Bcf)
    375       398       421  

2008 Compared to 2007. Our Field Services business segment reported operating income of $147 million for 2008 compared to $99 million for 2007. The increase in operating income of $48 million resulted from higher margins (revenue less natural gas costs) from gas gathering, ancillary services and higher commodity prices ($34 million) and a one-time gain related to a settlement and contract buyout of one of our customers ($11 million). Operating expenses increased from 2007 to 2008 due to higher expenses associated with new assets and general cost increases, partially offset by a gain related to the sale of assets in 2008 ($7 million).

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).

Equity Earnings. In addition, this business segment recorded equity income of $6 million, $10 million and $15 million for the years ended December 31, 2006, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Equity in earnings of unconsolidated affiliates under the Other Income (Expense) caption.

Other Operations

The following table provides summary data for our Other Operations business segment for 2006, 2007 and 2008 (in millions):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
                   
Revenues
  $ 15     $ 10     $ 11  
Expenses
    17       15        
Operating Income (Loss)
  $ (2 )   $ (5 )   $ 11  

2008 Compared to 2007. Our Other Operations business segment’s operating income in 2008 compared to 2007 increased by $16 million primarily as a result of a decrease in franchise taxes ($7 million) and a decrease in benefits accruals ($4 million).

2007 Compared to 2006. Our Other Operations business segment’s operating loss in 2007 compared to 2006 increased by $3 million.
 
 
LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flow

The net cash provided by (used in) operating, investing and financing activities for 2006, 2007 and 2008 is as follows (in millions):

   
Year Ended December 31,
 
   
2006
   
2007
   
2008
 
Cash provided by (used in):
                 
Operating activities
  $ 991     $ 774     $ 851  
Investing activities
    (1,056 )     (1,300 )     (1,368 )
Financing activities
    118       528       555  

Cash Provided by Operating Activities

Net cash provided by operating activities in 2008 increased $77 million compared to 2007 primarily due to decreased tax payments/increased tax refunds ($289 million), increased net accounts receivable/payable ($190 million), increased fuel cost recovery ($138 million) and increased pre-tax income ($131 million). These increases were partially offset by increased net regulatory assets and liabilities ($447 million) and increased net margin deposits ($247 million).

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).

Cash Used in Investing Activities

Net cash used in investing activities increased $68 million in 2008 compared to 2007 due to increased investment in unconsolidated affiliates of $167 million, primarily related to the SESH pipeline project, which was partially offset by decreased capital expenditures of $94 million.

Net cash used in investing activities increased $244 million in 2007 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.

Cash Provided by Financing Activities

Net cash provided by financing activities in 2008 increased $27 million compared to 2007 primarily due to increased borrowings under revolving credit facilities ($779 million) and increased proceeds from long-term debt ($188 million), which were partially offset by increased repayments of long-term debt ($825 million) and decreased short-term borrowings ($124 million).

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).

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 anticipated cash requirements for 2009 include the following:

 

 
approximately $1.1 billion of capital expenditures;

 
maturing long-term debt aggregating approximately $216 million, including $208 million of transition bonds; and

 
dividend payments on CenterPoint Energy common stock and interest payments on debt.

We expect that borrowings under our credit facilities and anticipated cash flows from operations will be sufficient to meet our anticipated cash needs in 2009. Cash needs or discretionary financing or refinancing may result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

The following table sets forth our capital expenditures for 2008 and estimates of our capital requirements for 2009 through 2013 (in millions):

   
2008
   
2009
   
2010
   
2011
   
2012
   
2013
 
Electric Transmission & Distribution
  $ 481     $ 422     $ 591     $ 579     $ 504     $ 506  
Natural Gas Distribution
    214       155       234       241       243       249  
Competitive Natural Gas Sales and Services
    8       3       3       3       3       3  
Interstate Pipelines
    189       202       151       87       67       70  
Field Services
    122       277       142       82       93       85  
Other Operations
    39       39       38       39       31       27  
Total
  $ 1,053     $ 1,098     $ 1,159     $ 1,031     $ 941     $ 940  

The following table sets forth estimates of our contractual obligations, including payments due by period (in millions):

Contractual Obligations
 
Total
   
2009
      2010-2011       2012-2013    
2014 and
thereafter
 
Transition bond debt
  $ 2,589     $ 208     $ 461     $ 546     $ 1,374  
Other long-term debt(1)
    8,624       8       792       2,732       5,092  
Interest payments — transition bond debt(2)
    794       140       227       177       250  
Interest payments — other long-term debt(2)
    4,812       481       948       794       2,589  
Short-term borrowings
    153       153                    
Capital leases
    1