CenterPoint Energy, Inc.
CENTERPOINT ENERGY INC (Form: 10-K, Received: 02/26/2010 08:02:06)


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, 2009
 
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 whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes þ No 
 
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
Smaller reporting company  o
   
(Do not check if a smaller reporting company)
 
 
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  o  No  þ
 
The aggregate market value of the voting stock held by non-affiliates of CenterPoint Energy, Inc. (CenterPoint Energy) was $4,008,560,260 as of June 30, 2009, using the definition of beneficial ownership contained in Rule 13d-3 promulgated pursuant to the Securities Exchange Act of 1934 and excluding shares held by directors and executive officers. As of February 15, 2010, CenterPoint Energy had 392,717,790 shares of Common Stock outstanding. Excluded from the number of shares of Common Stock outstanding are 166 shares held by CenterPoint Energy as treasury stock.
 
DOCUMENTS INCORPORATED BY REFERENCE
 
Portions of the definitive proxy statement relating to the 2010 Annual Meeting of Shareholders of CenterPoint Energy, which will be filed with the Securities and Exchange Commission within 120 days of December 31, 2009, 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.
23
Item 1B.
34
Item 2.
34
Item 3.
35
Item 4.
35
PART II
 
Item 5.
36
Item 6.
37
Item 7.
38
Item 7A.
62
Item 8.
64
Item 9.
113
Item 9A.
113
Item 9B.
114
PART III
 
Item 10.
114
Item 11.
114
Item 12.
114
Item 13.
114
Item 14.
114
PART IV
 
Item 15.
114
     
     Ex. 10(kk)(2) Form of Qualified Performance Award Agreement for 20XX - 20XX Performance Cycle under Exhibit 10(kk)(1)   
     Ex. 10(kk)(3) Form of Restricted Stock Unit Award Agreement (With Performance Goal) under Exhibit 10(kk)(1)  
     Ex. 10(ll)  
     Ex. 10(mm)  
     Ex. 12   
     Ex. 21   
     Ex. 23   
     Ex. 31.1   
     Ex. 31.2  
     Ex. 32.1   
     Ex. 32.2   
     
     



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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

From time to time we make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, future events or performance and underlying assumptions and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of the Private Securities Litigation Reform Act of 1995. Actual results may differ materially from those expressed or implied by these statements. You can generally identify our forward-looking statements by the words "anticipate," "believe," "continue," "could," "estimate," "expect," "forecast," "goal," "intend," "may," "objective," "plan," "potential," "predict," "projection," "should," "will" or other similar words.

We have based our forward-looking statements on our management’s beliefs and assumptions based on information available to our management at the time the statements are made. We caution you that assumptions, beliefs, expectations, intentions and projections about future events may and often do vary materially from actual results. Therefore, we cannot assure you that actual results will not differ materially from those expressed or implied by our forward-looking statements.

Some of the factors that could cause actual results to differ from those expressed or implied by our forward-looking statements are described under "Risk Factors" in Item 1A of this report.

You should not place undue reliance on forward-looking statements. Each forward-looking statement speaks only as of the date of the particular statement.


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PART I

Item 1.               Business

OUR BUSINESS

Overview

    We are a public utility holding company whose indirect wholly owned subsidiaries include:

 
CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes the city of 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 the audit, compensation, finance, governance and strategic planning committees of our 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
 
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services by companies providing transmission and distribution service, such as CenterPoint Houston, would remain 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 were 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 our only business 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 retail or wholesale sales of electric energy, 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 constructs and maintains transmission facilities and 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 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 Arkansas and 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 76,000 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 Corporation (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
 
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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 revised 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 RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.);

 
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.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision.  Oral argument before the court was held in October 2009.  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 $180 million to $410 million (pre-tax) plus interest subsequent to December 31, 2009.

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 has challenged that order by the court of appeals although the Texas Supreme Court has the authority to
 
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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 and 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 new special purpose 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 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 parties appealed the court of appeals decision to the Texas Supreme Court, which heard oral argument in October 2009. The ultimate outcome of this matter cannot be predicted at this time. However, we do not expect the disposition of this matter to have a material adverse effect on our or CenterPoint Houston’s financial condition, results of operations or cash flows.

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
 
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was implemented. During the years ended December 31, 2007 and 2008, CenterPoint Houston recognized approximately $42 million and $5 million, respectively, in operating income from the CTC.

As of December 31, 2009, we have not recognized an allowed equity return of $193 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates. Additionally, during the years ended December 31, 2007, 2008 and 2009, CenterPoint Houston recognized approximately $14 million, $13 million and $13 million, respectively, of the allowed equity return not previously recognized.

Hurricane Ike

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

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 $30 million.

CenterPoint Houston deferred the uninsured system restoration costs as management believed it was probable that such costs would be recovered through the regulatory process. As a result, system restoration costs did not affect CenterPoint Energy’s or CenterPoint Houston’s reported operating income for 2008 or 2009.

Legislation enacted by the Texas Legislature in April 2009 authorized the Texas Utility Commission to conduct proceedings to determine the amount of system restoration costs and related costs associated with hurricanes or other major storms that utilities are entitled to recover, and to issue financing orders that would permit a utility like CenterPoint Houston to recover the distribution portion of those costs and related carrying costs through the issuance of non-recourse system restoration bonds similar to the securitization bonds issued previously.  The legislation also allowed such a utility to recover, or defer for future recovery, the transmission portion of its system restoration costs through the existing mechanisms established to recover transmission costs.

Pursuant to such legislation, CenterPoint Houston filed with the Texas Utility Commission an application for review and approval for recovery of approximately $678 million, including approximately $608 million in system restoration costs identified as of the end of February 2009, plus $2 million in regulatory expenses, $13 million in certain debt issuance costs and $55 million in incurred and projected carrying costs calculated through August 2009. In July 2009, CenterPoint Houston announced a settlement agreement with the parties to the proceeding.  Under that settlement agreement, CenterPoint Houston was entitled to recover a total of $663 million in costs relating to Hurricane Ike, along with carrying   costs from September 1, 2009 until system restoration bonds were issued. The Texas Utility Commission issued an order in August 2009 approving CenterPoint Houston’s application and the settlement agreement and authorizing recovery of $663 million, of which $643 million was attributable to distribution service and eligible for securitization and the remaining $20 million was attributable to transmission service and eligible for recovery through the existing mechanisms established to recover transmission costs.

In July 2009, CenterPoint Houston filed with the Texas Utility Commission its application for a financing order to recover the portion of approved costs related to distribution service through the issuance of system restoration bonds.   In August 2009, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize $643 million in distribution service costs plus carrying charges from September 1, 2009 through the date the system restoration bonds were issued, as well as certain up-front qualified costs capped at approximately $6 million.  In November 2009, CenterPoint Houston issued approximately $665 million of system restoration bonds through its CenterPoint Energy Restoration Bond Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final maturity dates ranging from February 2016 to August 2023.  The bonds will be repaid over time through a charge imposed on customers.

In accordance with the financing order, CenterPoint Houston also placed a separate customer credit in effect when the storm restoration bonds were issued.  That credit (ADFIT Credit) is applied to customers’ bills while the bonds are outstanding to reflect the benefit of accumulated deferred federal income taxes (ADFIT) associated with
 
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the storm restoration costs (including a carrying charge of 11.075%). The beginning balance of the ADFIT related to storm restoration costs was approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit will reduce operating income in 2010 by approximately $24 million.

In accordance with the orders discussed above, as of December 31, 2009, CenterPoint Houston has recorded $651 million associated with distribution-related storm restoration costs as a net regulatory asset and $20 million associated with transmission-related storm restoration costs, of which $18 million is recorded in property, plant and equipment and $2 million of related carrying costs is recorded in regulatory assets.  These amounts reflect carrying costs of $60 million related to distribution and $2 million related to transmission through December 31, 2009, based on the 11.075% cost of capital approved by the Texas Utility Commission.  The carrying costs have been bifurcated into two components: (i) return of borrowing costs and (ii) an allowance for earnings on shareholders’ investment.  During the year ended December 31, 2009, the component representing a return of borrowing costs of $23 million has been recognized and is included in other income in our Statements of Consolidated Income.  The component representing an allowance for earnings on shareholders’ investment of $39 million is being deferred and will be recognized as it is collected through rates.

Customers

CenterPoint Houston serves nearly all of the Houston/Galveston metropolitan area. CenterPoint Houston’s customers consist of approximately 80 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 minimum creditworthiness criteria established by, the Texas Utility Commission. Sales to REPs that are subsidiaries of NRG Retail LLC (formerly subsidiaries of RRI) represented approximately 51%, 48% and 44% of CenterPoint Houston’s transmission and distribution revenues in 2007, 2008 and 2009, respectively. CenterPoint Houston’s billed receivables balance from REPs as of December 31, 2009 was $139 million. Approximately 41% of this amount was owed by subsidiaries of NRG Retail LLC. 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 began 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, which began in February 2009, is $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 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, maintenance and customer service for the CenterPoint Houston distribution system. These improvements are expected to contribute to fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. We expect to include the costs of the deployment in future rate proceedings before the Texas Utility Commission.

In October 2009, the U.S. Department of Energy (DOE) notified CenterPoint Houston that it had been selected for a $200 million grant for its advanced metering system and intelligent grid projects.  The award is contingent on
 
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successful completion of negotiations with the DOE. CenterPoint Houston applied for the grant in August 2009 to obtain $150 million in funding to accelerate completion of CenterPoint Houston’s current deployment of advanced meters by 2012, instead of 2014 as originally scheduled.  In addition, the grant request included $50 million to begin building the intelligent grid.  At this time, CenterPoint Houston cannot predict the schedule for completion of negotiations with the DOE or the final terms of any grant it ultimately receives.

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, 2009, CenterPoint Houston had outstanding approximately $2.5 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds under the Mortgage, including approximately $151 million held in trust to secure certain pollution control bonds for which CenterPoint Energy is obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.1 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, 2009. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Electric Lines - Overhead.   As of December 31, 2009, CenterPoint Houston owned 27,726 pole miles of overhead distribution lines and 3,729 circuit miles of overhead transmission lines, including 423 circuit miles operated at 69,000 volts, 2,090 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.

Electric Lines - Underground.   As of December 31, 2009, CenterPoint Houston owned 20,080 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, 2009, CenterPoint Houston owned 230 major substation sites having a total installed rated transformer capacity of 51,557 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 2009, 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 2009, approximately 70% 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, 2009, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

Supply and Transportation.   In 2009, 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 2009 included BP Canada Energy Marketing Corp. (20.5% of supply volumes), Coral Energy Resources (8.3%), Tenaska Marketing Ventures (8.2%), Kinder Morgan (8.0%), ConocoPhillips Company (7.4%), and Cargill, Inc. (5.7%).  Numerous other suppliers provided the remaining 41.9% 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,
 
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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 Dekatherms (DTH) per day and on-site storage facilities for 12 million gallons of propane (1.0 Bcf natural gas equivalent). It owns a liquefied natural gas plant facility with a 12 million-gallon liquefied natural gas storage tank (1.0 Bcf natural gas equivalent) and a production rate of 72 DTH 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.

Gas Operations has entered into various asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas.  Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization.  Gas Operations has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreement proceeds, although the percentage of payments to be retained by Gas Operations varies based on the jurisdiction, with the majority of the payments to benefit customers. The agreements have varying terms, the longest of which expires in 2016.

Assets

As of December 31, 2009, Gas Operations owned approximately 70,700 linear miles of natural gas distribution mains, varying in size from one-half inch to 24 inches in diameter. Generally, in each of the cities, towns and rural areas served by Gas Operations, it owns the underground gas mains and service lines, metering and regulating equipment located on customers’ premises and the district regulating equipment necessary for pressure maintenance. With a few exceptions, the measuring stations at which Gas Operations receives gas are owned, operated and maintained by others, and its distribution facilities begin at the outlet of the measuring equipment. These facilities, including odorizing equipment, are usually located on the land owned by suppliers.

Competition

Gas Operations competes primarily with alternate energy sources such as electricity and other fuel sources. In some areas, intrastate pipelines, other gas distributors and marketers also compete directly for gas sales to end-users. In addition, as a result of federal regulations affecting interstate pipelines, natural gas marketers operating on these pipelines may be able to bypass Gas Operations’ facilities and market and sell and/or transport natural gas directly to commercial and industrial customers.


Competitive Natural Gas Sales and Services

CERC offers variable and fixed-priced physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities through CenterPoint Energy Services, Inc. (CES) and its subsidiary, CenterPoint Energy Intrastate Pipelines, LLC (CEIP).

In 2009, CES marketed approximately 504 Bcf of natural gas, related energy services and transportation to approximately 11,100 customers (including approximately 3 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. The business has three operational divisions: wholesale, retail and intrastate pipelines, which are further described below.

Wholesale Division.   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 interstate and intrastate pipeline companies, and include gas utilities, large industrial customers and electric generation customers. This division includes the supply function for the procurement of natural gas and the management and optimization of transportation and storage assets for CES.

Retail Division.   CES offers a variety of natural gas management services to smaller commercial and industrial customers, municipalities, educational institutions and hospitals, whose facilities are typically 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 18 states.

Intrastate Pipeline Division.   CEIP 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 41 interstate and intrastate pipelines within states located throughout the central and eastern United States. CES maintains a portfolio of natural gas supply contracts and firm transportation and storage agreements to meet the natural gas requirements of its customers. CES aggregates supply from various producing regions and offers contracts to buy natural gas with terms ranging from one month to over five years. In addition, CES actively participates in the spot natural gas markets in an effort to balance daily and monthly purchases and sales obligations. Natural gas supply and transportation capabilities are leveraged through contracts for ancillary services including physical storage and other balancing arrangements.

As described above, CES offers its customers a variety of load following services. In providing these services, CES uses its customers’ purchase commitments to forecast and arrange its own supply purchases, storage and transportation services to serve customers’ natural gas requirements. As a result of the variance between this forecast activity and the actual monthly activity, CES will either have too much supply or too little supply relative to its customers’ purchase commitments. These supply imbalances arise each month as customers’ natural gas requirements are scheduled and corresponding natural gas supplies are nominated by CES for delivery to those customers. CES’ processes and risk control environment are designed to measure and value imbalances on a real-time basis to ensure that CES’ exposure to commodity price risk is kept to a minimum. The value assigned to these imbalances is calculated daily and is known as the aggregate Value at Risk (VaR). In 2009, CES’ VaR averaged $0.6 million with a high of $1.6 million.

Our 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, $4 million maximum, 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 230 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 0.8 Bcf per day on various interstate and intrastate pipelines and approximately 12.5 Bcf of storage to service its customer base.

Competition

CES competes with regional and national wholesale and retail gas marketers including the marketing divisions of natural gas producers and utilities. In addition, CES competes with intrastate pipelines for customers and services in its market areas.

Interstate Pipelines

CERC’s pipelines business operates interstate natural gas pipelines with gas transmission lines primarily located in Arkansas, Illinois, Louisiana, Missouri, Oklahoma and Texas. CERC’s interstate pipeline operations are primarily conducted by two wholly owned subsidiaries that provide gas transportation and storage services primarily to industrial customers and local distribution companies:

 
CenterPoint Energy Gas Transmission Company (CEGT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas, Louisiana, Oklahoma and Texas; and

 
CenterPoint Energy-Mississippi River Transmission Corporation (MRT) is an interstate pipeline that provides natural gas transportation, natural gas storage and pipeline services to customers principally in Arkansas and Missouri.

The rates charged by CEGT and MRT for interstate transportation and storage services are regulated by the FERC. CERC's 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 2009, approximately 16% 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.  The primary term of MRT’s firm transportation and storage contracts with Laclede will expire in 2013.  The primary term of CEGT’s 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 February 2010, CEGT completed the expansion of the capacity of its Carthage to Perryville pipeline to approximately 1.9 Bcf per day.  The expansion includes new compressor units at two of CEGT’s existing stations.

Southeast Supply Header, LLC. CenterPoint Southeastern Pipelines Holding, LLC, a wholly-owned subsidiary of CERC, owns a 50% interest in Southeast Supply Header, LLC (SESH). SESH owns a 1.0 Bcf per day, 274-mile interstate pipeline that runs from the Perryville Hub in Louisiana to Coden, Alabama. The pipeline was placed into service in September 2008. The rates charged by SESH for interstate transportation services are regulated by the FERC. A wholly-owned, indirect subsidiary of Spectra Energy Corp. owns the remaining 50% interest in SESH.

Assets

CERC's 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. CERC's
 
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interstate pipeline business also owns and operates 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. CERC's interstate pipeline business 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. CERC's interstate pipeline business' 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

CERC's 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. CERC's interstate pipelines business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. 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 1.4 Bcf per day of natural gas and, either directly or through its 50% interest in a joint venture, processes in excess of 250 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.

CERC's 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.

Long-Term Gas Gathering and Treating Agreements. In September 2009, CEFS entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana.  Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and EnCana’s natural gas production from the dedicated areas.

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 MMcf per day of natural gas. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.  The construction necessary to reach the contractual capacity of 700 MMcf per day includes more than 200 miles of gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction are being provided from anticipated cash flows from operations, lines of credit or proceeds from the sale of debt or equity securities.  As of December 31, 2009, approximately $176 million has been spent on this project, including the purchase of existing facilities.
 
Waskom Gas Processing Company. CenterPoint Energy Gas Processing Company, a wholly-owned, indirect subsidiary of CERC (CEGP), owns a 50% general partnership interest in Waskom Gas Processing Company (Waskom). Waskom owns a gas processing plant located in East Texas. The plant is capable of processing approximately 285 MMcf per day of natural gas.

Assets

CERC’s field services business owns and operates approximately 3,700 miles of gathering lines and processing plants that collect, treat and process natural gas from approximately 140 separate systems located in major producing fields in Arkansas, Louisiana, Oklahoma and Texas.

Competition

CERC's 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. CERC's field services business competes indirectly with other forms of energy, including electricity, coal and fuel oils. The primary competitive factor is price, but recently, environmental considerations have grown in importance when consumers consider other forms of energy. 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 affected 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 interstate 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.
 
CERC's 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
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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 approved standards and audit compliance with approved 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 and December 2009, 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 provide non-power goods and services to public utilities, natural gas companies or both, in the same holding company system.

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 primarily based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are primarily 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. 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, a surcharge related to the implementation of AMS and charges associated with securitization of regulatory assets, stranded costs and restoration costs relating to Hurricane Ike. 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.
 
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.
 
 
Rate Proceedings. In May 2009, CenterPoint Houston filed an application at the Texas Utility Commission seeking approval of certain estimated 2010 energy efficiency program costs, an energy efficiency performance bonus for 2008 programs and carrying costs, totaling approximately $10 million. The application sought to begin recovery of these costs through a surcharge effective July 1, 2010. In October 2009, the Texas Utility Commission issued its order approving recovery of the 2010 energy efficiency program costs and a partial performance bonus, plus carrying costs, but refused to permit CenterPoint Houston to recover a performance bonus of $2 million on approximately $10 million in 2008 energy efficiency costs expended pursuant to the terms of a settlement agreement reached in CenterPoint Houston’s 2006 rate proceeding.  CenterPoint Houston has appealed the denial of the full 2008 performance bonus to the district court in Travis County, Texas, where the case remains pending.

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 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 served by Gas Operations that have retained original jurisdiction.

Texas. 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. In 2008, Gas Operations implemented rates increasing annual revenues by approximately $3.5 million.  The implemented rates were contested by 9 cities in an appeal to the 353rd District Court in Travis County, Texas. In January 2010, that court reversed the Railroad Commission’s order in part and remanded the matter to the Railroad Commission.  The court concluded that the Railroad Commission did not have statutory authority to impose on the complaining cities the cost of service adjustment mechanism which the Railroad Commission had approved in its order.  Certain parties filed a motion to modify the district court’s judgment and a final decision is not expected until April 2010.  We and CERC do not expect the outcome of this matter to have a material adverse impact on our financial condition, results of operations or cash flows or those of CERC.

        In July 2009, Gas Operations filed a request to change its rates with the Railroad Commission and the 29 cities in its Houston service territory, consisting of approximately 940,000 customers in and around Houston. The request seeks to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Houston service territory. As finally submitted to the Railroad Commission and the cities, the proposed new rates would result in an overall increase in annual revenue of $20.4 million, excluding carrying costs on gas inventory of approximately $2 million. In January 2010, Gas Operations withdrew its request for an annual cost of service adjustment mechanism due to the uncertainty caused by the court’s ruling in the above-mentioned Texas Coast appeal. In February 2010, the Railroad Commission issued its decision authorizing a revenue increase of $5.1 million annually, reflecting reduced depreciation rates of $1.2 million.  The hearing examiner also recommended a surcharge of $0.9 million per year to recover Hurricane Ike costs over three years.
 
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
 
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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 MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court.  In July 2009, the Minnesota Supreme Court reversed the decision of the Minnesota Court of Appeals and upheld the MPUC’s decision to deny the requested variance. The court’s decision had no negative impact on our financial condition, results of operations or cash flows, as the costs at issue were written off at the time they were disallowed.

In November 2008, Gas Operations filed a request with the MPUC to increase its rates for utility distribution service by $59.8 million annually. In addition, Gas Operations sought 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. In January 2010, the MPUC issued its decision authorizing a revenue increase of $41 million per year, with an overall rate of return of 8.09% (10.24% return on equity). The difference between the rates approved by the MPUC and amounts collected under the interim rates, $10 million as of December 31, 2009, is recorded in other current liabilities and will be refunded to customers. The MPUC also authorized Gas Operations to implement a pilot program for residential and small volume commercial customers that is intended to decouple gas revenues from customers’ natural gas usage. In February 2010, CERC filed a request for rehearing of the order by the MPUC.  No other party to the case filed such a request.  CERC and CenterPoint Energy do not expect a final order to be issued in this proceeding until spring 2010.

Mississippi.   In July 2009, Gas Operations filed a request to increase its rates for utility distribution service with the Mississippi Public Service Commission (MPSC). In November 2009, as part of a settlement agreement in which the MPSC approved Gas Operations’ retention of the compensation paid under the terms of an asset management agreement, Gas Operations withdrew its rate request.

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 $16 million to $18 million during the next three years.
 

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 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.

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 that would require 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.  In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009.  Also, the U.S. Environmental Protection Agency (EPA) has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions.

It is too early to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action 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 action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas. Our electric transmission and distribution business, in contrast to some 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 burn fossil fuels to generate electricity.  Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.  Conversely, regulatory actions that effectively promote the consumption of natural gas because of its lower emission characteristics, would be expected to beneficially affect CERC and its natural gas-related businesses.  At this point in time, however, it would be speculative to try to quantify the magnitude of the impacts from possible new regulatory actions related to greenhouse gas emissions, either positive or negative, on our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity.  To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues.  On the other hand, warmer temperatures in our electric service territory may increase our revenues from transmission and distribution through increased demand for electricity for cooling.  Another possible climate change that has been widely discussed in recent years is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes.  Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers.  When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs.  To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

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
 
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permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions.  In recent years the EPA has adopted amendments to its regulations regarding maximum achievable control technology for stationary internal combustion engines (sometimes referred to as the RICE MACT rule) and continues to consider additional amendments.  Compressors used by our Pipelines and Field Services segments are affected by these rules.  While the final structure and effective dates of these revised rules are still uncertain, we currently believe the rules, if adopted in their current form and on the anticipated schedule, could require expenditures over the next 3 years of less than $100 million in order to ensure our compliance with the revised rules.  We believe, however, that our operations will not be materially adversely affected by such requirements.

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 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, 2009, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (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, 2009, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.  In January 2010, as part of its Minnesota rate case decision, the MPUC eliminated the environmental expense tracker mechanism and ordered amounts previously collected from ratepayers and related carrying costs refunded to customers.  As of December 31, 2009, the balance in the environmental expense tracker account was $8.7 million.  The MPUC provided for the inclusion in rates of approximately $285,000 annually to fund normal on-going remediation costs.  CERC was not required to refund to customers the amount collected from insurance companies, $4.6 million at December 31, 2009, to be used to mitigate future environmental costs.  The MPUC further gave assurance that any reasonable and prudent environmental clean-up costs CERC incurs in the future will be rate-recoverable under normal regulatory principles and procedures.  This provision had no effect on earnings.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing would be required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. In September 2009, the federal district court granted CERC’s motion for summary judgment in the proceeding.  Although it is likely that the plaintiff will pursue an appeal from that dismissal, further action will not be taken until the district court disposes of claims against other defendants in the case. 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.  We and CERC do not expect the ultimate outcome to have a material adverse impact on the financial condition, results of operations or cash flows of either us or CERC.

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
 
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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 NRG Texas LP. 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, is expected to 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 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, 2009, we had 8,810 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
    2,843       1,249  
Natural Gas Distribution
    3,618       1,384  
Competitive Natural Gas Sales and Services
    130       -  
Interstate Pipelines
    689       -  
Field Services
    241       -  
Other Operations
    1,289       -  
Total
    8,810       2,633  

As of December 31, 2009, approximately 30% of our employees are subject to collective bargaining agreements. One of the collective bargaining agreements covering approximately 14% of our employees, International Brotherhood of Electrical Workers Union Local No. 66, is scheduled to expire in May 2010. We have a good relationship with this bargaining unit and expect to negotiate a new agreement in 2010.




EXECUTIVE OFFICERS
(as of February 15, 2010)

Name
 
Age
 
Title
David M. McClanahan
 
60
 
President and Chief Executive Officer and Director
Scott E. Rozzell
 
60
 
Executive Vice President, General Counsel and Corporate Secretary
Gary L. Whitlock
 
60
 
Executive Vice President and Chief Financial Officer
C. Gregory Harper
 
45
 
Senior Vice President and Group President, CenterPoint Energy Pipelines and Field Services
Thomas R. Standish
 
60
 
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 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 and Management 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
 
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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.

In June 2009, the Texas Supreme Court granted the petitions for review of the court of appeals decision.  Oral argument before the court was held in October 2009.  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 $180 million to $410 million (pre-tax) plus interest subsequent to December 31, 2009.

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 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 has challenged that order by the court of appeals although the Texas Supreme Court has the 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 and administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

CenterPoint Houston’s receivables are concentrated in a small number of REPs, and any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. As of December 31, 2009, CenterPoint Houston did business with approximately 80 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. 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
 
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last resort if a REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which CenterPoint Houston can apply normal commercial terms or otherwise seek credit protection from firms desiring to provide retail electric service in its service territory, and thus remains at risk for payments not made prior to the shift to the provider of last resort. Although the Texas Utility Commission revised its regulations in 2009 to (i) increase the financial qualifications from REPs that began selling power after January 1, 2009, and (ii) authorize utilities to defer bad debts resulting from defaults by REPs for recovery in a future rate case, significant bad debts may be realized and unpaid amounts may not be timely recovered. A subsidiary of NRG Energy, Inc., NRG Retail LLC, acquired the Texas retail business of RRI, and its subsidiaries are together considered the largest REP in CenterPoint Houston’s service territory. Approximately 41% of CenterPoint Houston’s $139 million in billed receivables from REPs at December 31, 2009 was owed by subsidiaries of NRG Retail LLC. NRG Energy, Inc.’s credit ratings are currently below investment grade.  Any delay or default in payment by REPs could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.  If any of these REPs were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event any such REP might seek to avoid honoring its obligations and claims might be made by creditors involving payments CenterPoint Houston had received from such REP.

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 Form 10-K.

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
 
26

 
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 changes 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. An increase in natural gas prices would also increase CERC’s working capital requirements by increasing the investment that must be made in order to maintain natural gas inventory levels.  Additionally, a decrease in natural gas prices could increase the amount of collateral that CERC must provide under its hedging arrangements.

A decline in CERC’s credit rating could result in CERC’s having to provide collateral in order to purchase natural gas or under its shipping or hedging arrangements.

If CERC’s credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas or under its shipping or hedging arrangements. 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 and natural gas liquids.

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
 
27

 
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 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, future pipeline, gathering and treating systems 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 and gathering and treating system projects in the future. The construction of new pipelines, gathering and treating systems and related compression facilities may require 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, gathering, treating 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 Policy Act of 2005, 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 business 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 conduct its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions on similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.
 
The revenues and results of operations of CERC’s interstate pipelines and field services businesses could be adversely impacted by new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and the protection of water supplies in the areas in and around shale fields.

CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States.  To extract natural gas from the shale fields in this area, producers have historically used a process called hydraulic fracturing. Recently, new environmental regulations governing the withdrawal, storage and use of surface water or groundwater necessary for hydraulic fracturing of wells and the protection of water supplies in the areas in and around the shale fields have been considered by the federal government.  If enacted, such regulations could increase operating costs of the producers in these regions or cause delays, interruptions or termination of drilling operations, all of which could result in a decrease in demand for the services provided by CERC’s interstate pipelines and field services businesses in the shale fields, which could have an adverse effect on CERC’s results of operations, financial condition and cash flows.

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, 2009, we had $10.1 billion of outstanding indebtedness on a consolidated basis, which includes $3.0 billion of non-recourse transition and system restoration bonds. As of December 31, 2009, approximately $1.2 billion principal amount of this debt is required to be paid through 2012. This amount excludes principal repayments of approximately $831 million on transition and system restoration bonds, for which a dedicated revenue stream exists, but includes $290 million of pollution control bonds issued on our behalf which we purchased in January 2010 (and which may be remarketed) and $45 million of debentures redeemed in January 2010. Our future financing activities may be significantly affected by, among other things:

 
the resolution of the true-up proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;
 
 
general economic and capital market conditions;
 
 
credit availability from financial institutions and other lenders;
 
 
investor confidence in us and the markets in which we operate;
 
 
maintenance of acceptable credit ratings;
 
 
market expectations regarding our future earnings and cash flows;
 
 
market perceptions of our ability to access capital markets on reasonable terms;
 
 
our exposure to RRI in connection with its indemnification obligations arising in connection with its separation from us; and
 
 
provisions of relevant tax and securities laws.

As of December 31, 2009, CenterPoint Houston had outstanding approximately $2.5 billion aggregate principal amount of general mortgage bonds, including approximately $527 million held in trust to secure pollution control bonds for which we are obligated and approximately $229 million held in trust to secure pollution control bonds for
 
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which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.1 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, 2009. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

Our current credit ratings are discussed in "Management’s Discussion and Analysis of Financial Condition and Results of Operations - Liquidity and Capital Resources - Future Sources and Uses of Cash - Impact on Liquidity of a Downgrade in Credit Ratings" in Item 7 of Part II 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 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, other than substations, because CenterPoint Houston believes it to be cost prohibitive. In the future, CenterPoint Houston may not be able to recover the costs incurred in restoring its transmission and distribution properties following hurricanes or other natural disasters through issuance of storm restoration bonds or a change in its regulated rates or otherwise, or 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. When the companies separated, RRI agreed to secure CERC against obligations under the guaranties RRI had been unable to extinguish by the time of separation. Pursuant to such agreement, as amended in December 2007, RRI has agreed to provide to CERC cash or letters of credit as security against CERC’s obligations under its remaining guaranties for demand charges under certain gas transportation agreements if and to the extent changes in market conditions expose CERC to a risk of loss on those guaranties.  The present value of the demand charges under these transportation contracts, which will be effective until 2018, was approximately $96 million as of December 31, 2009. As of December 31, 2009, RRI was not required to provide security to CERC.  If RRI should fail to perform the contractual obligations, CERC could have to honor its guarantee and, in such event, collateral provided as security may be insufficient to satisfy CERC’s obligations.

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.

On May 1, 2009, RRI completed the previously announced sale of its Texas retail business to NRG Retail LLC, a subsidiary of NRG Energy, Inc. In connection with the sale, RRI changed its name to RRI Energy, Inc. and no longer provides service as a REP in CenterPoint Houston’s service territory. The sale does not alter RRI’s contractual obligations to indemnify us and our subsidiaries, including CenterPoint Houston, for certain liabilities, including their indemnification regarding certain litigation, nor does it affect the terms of existing guaranty arrangements for certain RRI gas transportation contracts.

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of sales of natural gas in California and other markets. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include 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, Reliant Energy and Texas Genco entered into a separation agreement in which 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. If Texas Genco were unable to satisfy a liability that had been so
 
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assumed or indemnified against, and provided we or Reliant Energy had not been released from the liability in connection with the transfer, CenterPoint Houston could be responsible for satisfying the liability.

In connection with our sale of Texas Genco to a third party, the separation agreement was amended to provide that Texas Genco would no longer be liable for, and we would assume and agree to indemnify Texas Genco 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 held by us. Texas Genco and its related businesses now operate as subsidiaries of NRG Energy, Inc.

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 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 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 unsettled conditions in the global financial system may have impacts on our business, liquidity and financial condition that we currently cannot predict.

The recent credit crisis and unsettled conditions 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. Defaults of lenders in our credit facilities, should they further 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 increased non-cash pension expense in 2009 which impacted 2009 results of operations and may impact liquidity if contributions are made to offset reduced asset values.

In addition to the credit and financial market issues, a recurrence of 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.

Climate change legislation and regulatory initiatives could result in increased operating costs and reduced demand for our services.

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.  In addition, efforts have been made and continue to be made in the international community toward the adoption of international treaties or protocols that would address global climate change issues, such as the United Nations Climate Change Conference in Copenhagen in 2009. Also, the EPA has undertaken new efforts to collect information regarding greenhouse gas emissions and their effects. Recently, the EPA declared that certain greenhouse gases represent an endangerment to human health and proposed to expand its regulations relating to those emissions.  It is too early to determine whether, or in what form, further regulatory action regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory action 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 action that would require installation of new control technologies or a modification of its operations or would have the effect of reducing the consumption of natural gas.  Our electric transmission and distribution business, in contrast to some 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 burn fossil fuels to generate electricity.  Nevertheless, CenterPoint Houston’s revenues could be adversely affected to the extent any resulting regulatory action has the effect of reducing consumption of electricity by ultimate consumers
 
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within its service territory. Likewise, incentives to conserve energy or use energy sources other than natural gas could result in a decrease in demand for our services.

Climate changes could result in more frequent severe weather events and warmer temperatures which could adversely affect the results of operations of our businesses.

To the extent climate changes occur, our businesses may be adversely impacted, though we believe any such impacts are likely to occur very gradually and hence would be difficult to quantify with specificity.  To the extent global climate change results in warmer temperatures in our service territories, financial results from our natural gas distribution businesses could be adversely affected through lower gas sales, and our gas transmission and field services businesses could experience lower revenues. Another possible climate change that has been widely discussed in recent years is the possibility of more frequent and more severe weather events, such as hurricanes or tornadoes.  Since many of our facilities are located along or near the Gulf Coast, increased or more severe hurricanes or tornadoes can increase our costs to repair damaged facilities and restore service to our customers.  When we cannot deliver electricity or natural gas to customers or our customers cannot receive our services, our financial results can be impacted by lost revenues, and we generally must seek approval from regulators to recover restoration costs.  To the extent we are unable to recover those costs, or if higher rates resulting from our recovery of such costs result in reduced demand for our services, our future financial results may be adversely impacted.

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(e) 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 2009.
 

PART II

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

As of February 15, 2010, our common stock was held of record by approximately 45,607 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
 
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          
                         
2009
                       
First Quarter
                  $ 0.19  
February 6
  $ 14.39                  
March 6
          $ 8.88          
Second Quarter
                  $ 0.19  
May 27
          $ 9.77          
June 29
  $ 11.24                  
Third Quarter
                  $ 0.19  
July 9
          $ 10.78          
August 26
  $ 12.83                  
Fourth Quarter
                  $ 0.19  
October 2
          $ 12.22          
December 28
  $ 14.81                  

The closing market price of our common stock on December 31, 2009 was $14.51 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 21, 2010, we announced a regular quarterly cash dividend of $0.195 per share, payable on March 10, 2010 to shareholders of record on February 16, 2010.

Repurchases of Equity Securities

During the quarter ended December 31, 2009, 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,
 
   
2005(1)(2)
   
2006(2)
   
2007(2)
   
2008(2)
   
2009
 
   
(In millions, except per share amounts)
 
       
Revenues
  $ 9,722     $ 9,319     $ 9,623     $ 11,322     $ 8,281  
Income from continuing operations before extraordinary item
    220       427       395       446       372  
Discontinued operations, net of tax
    (3 )     -       -       -       -  
Extraordinary item, net of tax
    30       -       -       -       -  
Net income
  $ 247     $ 427     $ 395     $ 446     $ 372  
Basic earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 0.71     $ 1.37     $ 1.23     $ 1.32     $ 1.02  
Discontinued operations, net of tax
    (0.01 )     -       -       -       -  
Extraordinary item, net of tax
    0.10       -       -       -       -  
Basic earnings per common share
  $ 0.80     $ 1.37     $ 1.23     $ 1.32     $ 1.02  
Diluted earnings (loss) per common share:
                                       
Income from continuing operations before extraordinary item
  $ 0.66     $ 1.31     $ 1.15     $ 1.30     $ 1.01  
Discontinued operations, net of tax
    (0.01 )     -       -       -       -  
Extraordinary item, net of tax
    0.09       -       -       -       -  
Diluted earnings per common share
  $ 0.74     $ 1.31     $ 1.15     $ 1.30     $ 1.01  
                                         
Cash dividends declared per common share
  $ 0.40     $ 0.60     $ 0.68     $ 0.73     $ 0.76  
Dividend payout ratio from continuing operations
    56 %     44 %     55 %     55 %     75 %
Return from continuing operations on average common equity
    18.2 %     29.8 %     23.4 %     23.3 %     16.0 %
Ratio of earnings from continuing operations to fixed charges
    1.49       1.74       1.82       2.05       1.80  
At year-end:
                                       
Book value per common share
  $ 4.21     $ 4.98     $ 5.61     $ 5.84     $ 6.74  
Market price per common share
    12.85       16.58       17.13       12.62       14.51  
Market price as a percent of book value
    305 %     333 %     305 %     216 %     215 %
Total assets
  $ 17,116     $ 17,633     $ 17,872     $ 19,676     $ 19,773  
Short-term borrowings
    -       187       232       153       55  
Transition and system restoration bonds, including current maturities
    2,480       2,407       2,260       2,589       3,046  
Other long-term debt, including current maturities
    6,411       6,586       7, 417       7,925       6,976  
Capitalization:
                                       
Common stock equity
    13 %     15 %     16 %     16 %     21 %
Long-term debt, including current maturities
    87 %     85 %     84 %     84 %     79 %
Capitalization, excluding transition and system restoration bonds:
                                       
Common stock equity
    17 %     19 %     20 %     20 %     27 %
Long-term debt, excluding transition and system restoration bonds, including current maturities
    83 %     81 %     80 %     80 %     73 %
Capital expenditures, excluding discontinued operations
  $ 719     $ 1,121     $ 1,011     $ 1,053     $ 1,148  
__________
 
(1)
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.

 
(2)
Net income has been retrospectively adjusted by $5 million, $5 million, $4 million and $1 million for the years ended 2005, 2006, 2007 and 2008, respectively, to reflect the adoption of new accounting guidance as of January 1, 2009 for convertible debt instruments that may be settled in cash upon conversion.
 

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 the city of 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, 2009 is set forth below:

Electric Transmission & Distribution

Our electric transmission and distribution operations provide electric transmission and distribution services to retail electric providers (REPs) serving approximately 2.1 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.7 million people and includes the city of 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 Public Utility Commission of Texas (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 18 states in the central and eastern regions of the United 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 an 80 Bcf Bistineau storage facility located in Bienville Parish, Louisiana, with the remaining interest owned and operated by Gulf South Pipeline Company, LP. Most storage operations are in north Louisiana and Oklahoma.

Field Services

CERC’s field services business owns and operates approximately 3,700 miles of gathering pipelines and processing plants that collect, treat and process natural gas from approximately 140 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

Factors Influencing Our Business
 
We are an energy delivery company. The majority of our revenues are generated from the gathering, processing, transportation and sale of natural gas and the transportation and delivery of electricity by our subsidiaries. We do not own or operate electric generating facilities or make retail sales to end-use electric customers. To assess our financial performance, our management primarily monitors operating income and cash flows from our five business segments. Within these broader financial measures, we monitor margins, operation and maintenance expense, interest expense, capital spending and working capital requirements. In addition to these financial measures we also monitor a number of variables that management considers important to the operation of our business segments, including the number of customers, throughput, use per customer, commodity prices and heating and cooling degree days. We also monitor system reliability, safety factors and customer satisfaction to gauge our performance.

To the extent the adverse economic conditions affect our suppliers and customers, results from our energy delivery businesses may suffer.  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.

Performance of our Electric Transmission & Distribution and Natural Gas Distribution business segments is significantly influenced by the number of customers and energy usage per customer. Weather conditions can have a significant impact on energy usage, and we compare our results to weather on an adjusted basis. During 2009, we continued to see evidence that customers are seeking to conserve in their energy consumption, particularly during periods of high energy prices or in times of economic distress.  That conservation can have adverse effects on our results. In many of our service areas, particularly in the Houston area and in Minnesota, we have benefited from customer growth that tends to mitigate the effects of reduced consumption.  We anticipate that this growth will continue despite recent economic downturns, though that growth may be lower than we have recently experienced in these areas.  In addition, the profitability of these businesses is influenced significantly by the regulatory treatment we receive from the various state and local regulators who set our electric and gas distribution rates. In our recent Gas Operations rate filings, we have sought rate mechanisms that help to decouple our results from the impacts of
 
39

 
weather and conservation, but such rate mechanisms have not yet been approved in all jurisdictions. We plan to continue to pursue such decoupling mechanisms in our rate filings.

Our Field Services and Interstate Pipelines business segments are currently benefiting from their proximity to new natural gas producing regions in Texas, Arkansas, Oklahoma and Louisiana.  Our Interstate Pipelines business segment benefited from new projects placed into service in 2009 on our Carthage to Perryville line.  In our Field Services business segment, strong drilling activity in the new shale producing regions has helped offset declines in drilling activity in traditional producing regions due to the effects of the economic downturn and significantly lower commodity prices in 2009. In monitoring performance of the segments, we focus on throughput of the pipelines and gathering systems, and in the case of Field Services, on well-connects.

Our Competitive Natural Gas Sales and Services business segment contracts with customers for transportation, storage and sales of natural gas on an unregulated basis.  Its operations serve customers in the central and eastern regions of the United States.  The segment benefits from favorable price differentials, either on a geographic basis or on a seasonal basis. While it utilizes financial derivatives to hedge its exposure to price movements, it does not engage in speculative or proprietary trading and maintains a low value at risk level or VaR to avoid significant financial exposures.  Lower commodity prices and low price differentials during 2009 adversely affected results for this business segment.

The nature of our businesses requires significant amounts of capital investment, and we rely on internally generated cash, borrowings under our credit facilities and issuances of debt and equity in the capital markets to satisfy these capital needs. We strive to maintain investment grade ratings for our securities in order to access the capital markets on terms we consider reasonable. Our goal is to improve our credit ratings over time.  A reduction in our ratings generally would increase our borrowing costs for new issuances of debt, as well as borrowing costs under our existing revolving credit facilities. Disruptions in the financial markets, such as occurred in the last half of 2008 and continued during 2009, can also affect the availability of new capital on terms we consider attractive. In those circumstances companies like us may not be able to obtain certain types of external financing or may be required to accept terms less favorable than they would otherwise accept. For that reason, we seek to maintain adequate liquidity for our businesses through existing credit facilities and prudent refinancing of existing debt. For example, we have negotiated amendments to the financial covenant in our revolving credit facility to better ensure that adequate debt capacity would be available if needed to finance restoration costs following major storms. We expect to experience higher borrowing costs and greater uncertainty in executing capital markets transactions given the current uncertainties in the financial markets.

As it did with many businesses, the sharp decline in stock market values during the latter part of 2008 had a significant adverse impact on the value of our pension plan assets.  While that impact did not require us to make additional contributions to the pension plan, it significantly increased the pension expense we recognized during 2009 and expect to recognize in 2010 for all our business segments, other than our Electric Transmission & Distribution business segment, and we may need to make significant cash contributions to our pension plan subsequent to 2010.  Consistent with the regulatory treatment of such costs, we will defer until our next rate proceeding before the Texas Utility Commission the amount of pension expense that differs from the level of pension expense included in our 2007 base rates for our Electric Transmission & Distribution business segment.

Significant Events

Hurricane Ike

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

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 $30 million.

 
CenterPoint Houston deferred the uninsured system restoration costs as management believed it was probable that such costs would be recovered through the regulatory process. As a result, system restoration costs did not affect CenterPoint Energy’s or CenterPoint Houston’s reported operating income for 2008 or 2009.

Legislation enacted by the Texas Legislature in April 2009 authorized the Texas Utility Commission to conduct proceedings to determine the amount of system restoration costs and related costs associated with hurricanes or other major storms that utilities are entitled to recover, and to issue financing orders that would permit a utility like CenterPoint Houston to recover the distribution portion of those costs and related carrying costs through the issuance of non-recourse system restoration bonds similar to the securitization bonds issued previously.  The legislation also allowed such a utility to recover, or defer for future recovery, the transmission portion of its system restoration costs through the existing mechanisms established to recover transmission costs.

Pursuant to such legislation, CenterPoint Houston filed with the Texas Utility Commission an application for review and approval for recovery of approximately $678 million, including approximately $608 million in system restoration costs identified as of the end of February 2009, plus $2 million in regulatory expenses, $13 million in certain debt issuance costs and $55 million in incurred and projected carrying costs calculated through August 2009. In July 2009, CenterPoint Houston announced a settlement agreement with the parties to the proceeding.  Under that settlement agreement, CenterPoint Houston was entitled to recover a total of $663 million in costs relating to Hurricane Ike, along with carrying   costs from September 1, 2009 until system restoration bonds were issued. The Texas Utility Commission issued an order in August 2009 approving CenterPoint Houston’s application and the settlement agreement and authorizing recovery of $663 million, of which $643 million was attributable to distribution service and eligible for securitization and the remaining $20 million was attributable to transmission service and eligible for recovery through the existing mechanisms established to recover transmission costs.

In July 2009, CenterPoint Houston filed with the Texas Utility Commission its application for a financing order to recover the portion of approved costs related to distribution service through the issuance of system restoration bonds.   In August 2009, the Texas Utility Commission issued a financing order allowing CenterPoint Houston to securitize $643 million in distribution service costs plus carrying charges from September 1, 2009 through the date the system restoration bonds were issued, as well as certain up-front qualified costs capped at approximately $6 million.  In November 2009, CenterPoint Houston issued approximately $665 million of system restoration bonds through its CenterPoint Energy Restoration Bond Company, LLC subsidiary with interest rates of 1.833% to 4.243% and final maturity dates ranging from February 2016 to August 2023.  The bonds will be repaid over time through a charge imposed on customers.

In accordance with the financing order, CenterPoint Houston also placed a separate customer credit in effect when the storm restoration bonds were issued.  That credit (ADFIT Credit) is applied to customers’ bills while the bonds are outstanding to reflect the benefit of accumulated deferred federal income taxes (ADFIT) associated with the storm restoration costs (including a carrying charge of 11.075%). The beginning balance of the ADFIT related to storm restoration costs was approximately $207 million and will decline over the life of the system restoration bonds as taxes are paid on the system restoration tariffs. The ADFIT Credit will reduce operating income in 2010 by approximately $24 million.

In accordance with the orders discussed above, as of December 31, 2009, CenterPoint Houston has recorded $651 million associated with distribution-related storm restoration costs as a net regulatory asset and $20 million associated with transmission-related storm restoration costs, of which $18 million is recorded in property, plant and equipment and $2 million of related carrying costs is recorded in regulatory assets.  These amounts reflect carrying costs of $60 million related to distribution and $2 million related to transmission through December 31, 2009, based on the 11.075% cost of capital approved by the Texas Utility Commission.  The carrying costs have been bifurcated into two components: (i) return of borrowing costs and (ii) an allowance for earnings on shareholders’ investment.  During the year ended December 31, 2009, the component representing a return of borrowing costs of $23 million has been recognized and is included in other income in our Statements of Consolidated Income.  The component representing an allowance for earnings on shareholders’ investment of $39 million is being deferred and will be recognized as it is collected through rates.

 
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, 2009, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

Long-Term Gas Gathering and Treatment Agreements

In September 2009, CenterPoint Energy Field Services, Inc. (CEFS), a wholly-owned natural gas gathering and treating subsidiary of CERC Corp., entered into long-term agreements with an indirect wholly-owned subsidiary of EnCana Corporation (EnCana) and an indirect wholly-owned subsidiary of Royal Dutch Shell plc (Shell) to provide gathering and treating services for their natural gas production from certain Haynesville Shale and Bossier Shale formations in Louisiana. CEFS also acquired jointly-owned gathering facilities from EnCana and Shell in De Soto and Red River parishes in northwest Louisiana.  Each of the agreements includes acreage dedication and volume commitments for which CEFS has rights to gather Shell’s and EnCana’s natural gas production from the dedicated areas.

In connection with the agreements, CEFS commenced gathering and treating services utilizing the acquired facilities. CEFS is expanding the acquired facilities in order to gather and treat up to 700 million cubic feet (MMcf) per day of natural gas. If EnCana or Shell elect, CEFS will further expand the facilities in order to gather and treat additional future volumes.  The construction necessary to reach the contractual capacity of 700 MMcf per day includes more than 200 miles of gathering lines, nearly 25,500 horsepower of compression and over 800 MMcf per day of treating capacity.

CEFS estimates that the purchase of existing facilities and construction to gather 700 MMcf per day will cost up to $325 million. If EnCana and Shell elect expansion of the project to gather and process additional future volumes of up to 1 Bcf per day, CEFS estimates that the expansion would cost as much as an additional $300 million and EnCana and Shell would provide incremental volume commitments. Funds for construction are being provided from anticipated cash flows from operations, lines of credit or proceeds from the sale of debt or equity securities.  As of December 31, 2009, $176 million had been spent on the project, including the purchase of existing facilities.

Debt Financing Transactions

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 CenterPoint Houston’s revolving credit facility and the money pool, capital expenditures and storm restoration costs associated with Hurricane Ike.

In August 2009, Southeast Supply Header, LLC (SESH) closed on a private debt offering in the amount of $375 million.  Also during 2009, CERC Corp. made a capital contribution to SESH in the amount of $137 million.  Using $186 million of its proceeds from the debt offering and the capital contribution, SESH repaid the note receivable it owed to CERC Corp., which note had a principal balance of $323 million at the time of the repayment. CERC Corp. used the proceeds to repay borrowings under its credit facility.

In October 2009, CenterPoint Houston terminated its $600 million 364-day secured credit facility which had been arranged in November 2008 following Hurricane Ike.

In October 2009, the size of CERC Corp.’s revolving credit facility was reduced from $950 million to $915 million through removal of Lehman Brothers Bank, FSB (Lehman) as a lender.  Prior to its removal, Lehman had a $35 million commitment to lend.  All credit facility loans to CERC Corp. that were funded by Lehman were repaid in September 2009.

In October 2009, CERC amended its receivables facility to extend the termination date to October 8, 2010.  Availability under CERC’s 364-day receivables facility ranges from $150 million to $375 million, reflecting seasonal changes in receivables balances.

In January 2010, we purchased $290 million principal amount of pollution control bonds issued on our behalf at 101% of their principal amount plus accrued interest pursuant to the mandatory tender provisions of the bonds.
 
42

 
Prior to the purchase, the pollution control bonds had a fixed rate of interest of 5.125%. The purchase reduces temporary investments and leverage while providing us with the flexibility to finance future capital needs in the tax-exempt market through a remarketing of these bonds.

In January 2010, CERC Corp. redeemed $45 million of its outstanding 6% convertible subordinated debentures due 2012 at 100% of the principal amount plus accrued and unpaid interest to the redemption date.

Equity Financing Transactions

During the year ended December 31, 2009, we received net proceeds of approximately $280 million from the issuance of 24.2 million common shares in an underwritten public offering, net proceeds of $148 million from the issuance of 14.3 million common shares through a continuous offering program, proceeds of approximately $57 million from the sale of approximately 4.9 million common shares to our defined contribution plan and proceeds of approximately $15 million from the sale of approximately 1.3 million common shares to participants in our enhanced dividend reinvestment plan.

Asset Management Agreements

In 2009, Gas Operations entered into various asset management agreements associated with its utility distribution service in Arkansas, Louisiana, Mississippi, Oklahoma and Texas.  Generally, these asset management agreements are contracts between Gas Operations and an asset manager that are intended to transfer the working capital obligation and maximize the utilization of the assets. In these agreements, Gas Operations agreed to release transportation and storage capacity to other parties to manage gas storage, supply and delivery arrangements for Gas Operations and to use the released capacity for other purposes when it is not needed for Gas Operations. Gas Operations is compensated by the asset manager through payments made over the life of the agreements based in part on the results of the asset optimization.  Gas Operations has received approval from the state regulatory commissions in Arkansas, Louisiana, Mississippi and Oklahoma to retain a share of the asset management agreement proceeds, although the percentage of payments to be retained by Gas Operations varies based on the jurisdiction, with the majority of the payments to benefit customers. The agreements have varying terms, the longest of which expires in 2016.

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 proceedings, including, in particular, the results of appeals to the Texas Supreme Court regarding rulings obtained to date;

 
state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, health care reform, and changes in or application of laws or regulations applicable to the various aspects of our business;

 
state and federal legislative and regulatory actions, developments or regulations relating to the environment, including those related to global climate change;

 
timely and appropriate legislative and regulatory actions allowing securitization or other recovery of costs associated with any future hurricanes or natural disasters;

 
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, including supplies available for gathering by our field services business;

 
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;

 
the ability of RRI Energy, Inc. (RRI) (formerly known as Reliant Energy, Inc. and Reliant Resources, Inc.) and its subsidiaries to satisfy their obligations to us, including indemnity obligations, or in connection with the contractual arrangements pursuant to which we are their guarantor;

 
the ability of REPs that are subsidiaries of NRG Retail LLC and TXU Energy Retail Company LLC (TXU Energy), which are CenterPoint Houston’s two largest customers, to satisfy their obligations to us and our subsidiaries;

 
the outcome of litigation brought by or against us;

 
our ability to control costs;

 
the investment performance of our pension and postretirement 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,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 9,623     $ 11,322     $ 8,281  
Expenses
    8,438       10,049       7,157  
Operating Income
    1,185       1,273       1,124  
Gain (Loss) on Marketable Securities
    (114 )     (139 )     82  
Gain (Loss) on Indexed Debt Securities
    111       128       (68 )
Interest and Other Finance Charges
    (509 )     (468 )     (513 )
Interest on Transition and System Restoration Bonds
    (123 )     (136 )     (131 )
Distribution from AOL Time Warner Litigation Settlement
    32       -       3  
Additional Distribution to ZENS Holders
    (27 )     -       (3 )
Equity in Earnings of Unconsolidated Affiliates
    16       51       15  
Other Income, net
    17       14       39  
Income Before Income Taxes
    588       723       548  
Income Tax Expense
    (193 )     (277 )     (176 )
Net Income
  $ 395     $ 446     $ 372  
                         
Basic Earnings Per Share
  $ 1.23     $ 1.32     $ 1.02  
                         
Diluted Earnings Per Share
  $ 1.15     $ 1.30     $ 1.01  

2009 Compared to 2008

Net Income.   We reported net income of $372 million ($1.01 per diluted share) for 2009 compared to $446 million ($1.30 per diluted share) for the same period in 2008. The decrease in net income of $74 million was primarily due to a $149 million decrease in operating income, a $45 million increase in interest expense due primarily to higher interest rates and higher levels of debt during 2009, excluding transition and system restoration bond-related interest expense, a $36 million decrease in equity in earnings of unconsolidated affiliates and a $196 million decrease in the gain on our indexed debt securities.  These decreases in net income were partially offset by a $101 million decrease in income tax expense, a $221 million increase in the gain on our marketable securities, $23 million of carrying costs related to Hurricane Ike restoration costs included in Other Income, net and a $5 million decrease in interest expense on transition and system restoration bonds.

Income Tax Expense.   Our 2009 effective tax rate of 32.1% differed from the 2008 effective tax rate of 38.4% primarily due to the settlement of our federal income tax return examinations for tax years 2004 and 2005 and a reduction in state income taxes related to adjustments in prior years’ state estimates.  For more information, see Note 9 to our consolidated financial statements.

2008 Compared to 2007

Net Income.   We reported net income of $446 million ($1.30 per diluted share) for 2008 compared to $395 million ($1.15 per diluted share) for the same period in 2007. The increase in net income of $51 million was primarily due to an $88 million increase in operating income, a $41 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 $84 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.
 
 
RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for 2007, 2008 and 2009. 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,
 
   
2007
   
2008
   
2009
 
Electric Transmission & Distribution
  $ 561     $ 545     $ 545  
Natural Gas Distribution
    218       215       204  
Competitive Natural Gas Sales and Services
    75       62       21  
Interstate Pipelines
    237       293       256  
Field Services
    99       147       94  
Other Operations
    (5 )     11       4  
Total Consolidated Operating Income
  $ 1,185     $ 1,273     $ 1,124  

Electric Transmission & Distribution

The following tables provide summary data of our Electric Transmission & Distribution business segment, CenterPoint Houston, for 2007, 2008 and 2009 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
Revenues:
                 
Electric transmission and distribution utility
  $ 1,560     $ 1,593     $ 1,673  
Transition and system restoration bond companies
    277       323       340  
Total revenues
    1,837       1,916       2,013  
Expenses:
                       
Operation and maintenance, excluding transition and system
restoration bond companies
    652       703       774  
Depreciation and amortization, excluding transition and system
restoration bond companies
    243       277       277  
Taxes other than income taxes
    223       201       208  
Transition and system restoration bond companies
    158       190       209  
Total expenses
    1,276       1,371       1,468  
Operating Income
  $ 561     $ 545     $ 545  
                         
Operating Income:
                       
Electric transmission and distribution operations
  $ 400     $ 407     $ 414  
Competition transition charge
    42       5       -  
Transition and system restoration bond companies (1)  
    119       133       131  
Total segment operating income
  $ 561     $ 545     $ 545  
Throughput (in gigawatt-hours (GWh)):
                       
Residential
    23,999       24,258       24,815  
Total
    76,291       74,840       74,579  
Number of metered customers at end of period:
                       
Residential
    1,793,600       1,821,267       1,849,019  
Total
    2,034,074       2,064,854       2,094,210  
__________
 
(1)
Represents the amount necessary to pay interest on the transition and system restoration bonds.
 
2009 Compared to 2008.   Our Electric Transmission & Distribution business segment reported operating income of $545 million for 2009, consisting of $414 million from our regulated electric transmission and distribution utility operations (TDU) and $131 million related to transition and system restoration bond companies. For 2008, operating income totaled $545 million, consisting of $407 million from the TDU, exclusive of an additional $5 million from the competition transition charge (CTC), and $133 million related to transition bond companies. Revenues for the TDU increased due to higher transmission-related revenues ($50 million), in part reflecting the impact of a
 
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transmission rate increase implemented in November 2008, the impact of Hurricane Ike in 2008 ($17 million), revenues from implementation of AMS ($33 million) and higher revenues due to customer growth ($17 million) from the addition of over 29,000 new customers, partially offset by declines in energy demand ($27 million). Operation and maintenance expenses increased $71 million primarily due to higher transmission costs billed by transmission providers ($18 million), increased operating and maintenance expenses that were postponed in 2008 as a result of Hurricane Ike restoration efforts ($10 million), higher pension and other employee benefit costs ($10 million), expenses related to AMS ($14 million) and a gain on a land sale in 2008 ($9 million). Increased depreciation expense related to increased investment in AMS ($7 million) was offset by other declines in depreciation and amortization, primarily due to asset retirements. Taxes other than income taxes increased $7 million primarily as a result of a refund in 2008 of prior years’ state franchise taxes ($5 million). Changes in pension expense over our 2007 base year amount are being deferred until our next general rate case pursuant to Texas law.

2008 Compared to 2007.   Our Electric Transmission & Distribution business segment reported operating income of $545 million for 2008, consisting of $407 million from the TDU, exclusive of an additional $5 million from the 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 in 2008 due to customer growth, with over 30,000 metered customers added ($23 million), increased usage ($15 million) in part caused by favorable weather experienced, 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).

Natural Gas Distribution

The following table provides summary data of our Natural Gas Distribution business segment for 2007, 2008 and 2009 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 3,759     $ 4,226     $ 3,384  
Expenses:
                       
Natural gas
    2,683       3,124       2,251  
Operation and maintenance
    579       589       639  
Depreciation and amortization
    155       157       161  
Taxes other than income taxes
    124       141       129  
Total expenses
    3,541       4,011       3,180  
Operating Income
  $ 218     $ 215     $ 204  
Throughput (in Bcf):
                       
Residential
    172       175       173  
Commercial and industrial
    232       236       233  
Total Throughput
    404       411       406  
Number of customers at end of period:
                       
Residential
    2,961,110       2,987,222       3,002,114  
Commercial and industrial
    249,877       248,476       244,101  
Total
    3,210,987       3,235,698       3,246,215  

2009 Compared to 2008.   Our Natural Gas Distribution business segment reported operating income of $204 million for 2009 compared to $215 million for 2008. Operating income declined ($11 million) primarily as a result of increased pension expense ($37 million) and higher labor and other benefit costs ($16 million), partially
 
47

 
offset by increased revenues from rate increases ($36 million) and lower bad debt expense ($15 million). Revenues related to both energy-efficiency costs and gross receipts taxes are substantially offset by the related expenses. Depreciation and amortization expense increased $4 million primarily due to higher plant balances.  Taxes other than income taxes, net of the decrease in gross receipts taxes ($16 million), increased $4 million also primarily due to higher plant balances.

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 in 2008 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).

Competitive Natural Gas Sales and Services

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for 2007, 2008 and 2009 (in millions, except throughput and customer data):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 3,579     $ 4,528     $ 2,230  
Expenses:
                       
Natural gas
    3,467       4,423       2,165  
Operation and maintenance
    31       39       39  
Depreciation and amortization
    5       3       4  
Taxes other than income taxes
    1       1       1  
Total expenses
    3,504       4,466       2,209  
Operating Income
  $ 75     $ 62     $ 21  
                         
Throughput (in Bcf)
    522       528       504  
                         
Number of customers at end of period
    7,139       9,771       11,168  

2009 Compared to 2008.    Our Competitive Natural Gas Sales and Services business segment reported operating income of $21 million for 2009 compared to $62 million for 2008.  The decrease in operating income of $41 million was due to the unfavorable impact of the mark-to-market valuation for non-trading financial derivatives for 2009 of $23 million versus a favorable impact of $13 million for the same period in 2008.  A further $28 million decrease in margin is attributable to reduced basis spreads on pipeline transport opportunities and an absence of summer storage spreads. These decreases in operating income were partially offset by a $6 million write-down of natural gas inventory to the lower of cost or market for 2009 compared to a $30 million write-down in the same period last year.  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.

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 in 2008 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.


Interstate Pipelines

The following table provides summary data of our Interstate Pipelines business segment for 2007, 2008 and 2009 (in millions, except throughput data):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 500     $ 650     $ 598  
Expenses:
                       
Natural gas
    83       155       97  
Operation and maintenance
    125       133       166  
Depreciation and amortization
    44       46       48  
Taxes other than income taxes
    11       23       31  
Total expenses
    263       357       342  
Operating Income
  $ 237     $ 293     $ 256  
                         
Transportation throughput (in Bcf)
    1,216       1,538       1,592  

2009 Compared to 2008.   Our Interstate Pipeline business segment reported operating income of $256 million for 2009 compared to $293 million for 2008. Margins (revenues less natural gas costs) increased $6 million primarily due to the Carthage to Perryville pipeline ($28 million) and new contracts with power generation customers ($20 million), partially offset by reduced other transportation margins and ancillary services ($42 million) primarily due to the decline in commodity prices from the significantly higher levels in 2008.  Operations and maintenance expenses increased due to a gain on the sale of two storage development projects in 2008 ($18 million) and costs associated with incremental facilities ($12 million) and increased pension expenses ($9 million).  These expenses were partially offset by a write-down associated with pipeline assets removed from service in the third quarter of 2008 ($7 million).  Depreciation and amortization expenses increased $2 million and taxes other than income taxes increased by $8 million, $2 million of which was due to 2008 tax refunds.

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 in 2008 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 were 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.

Equity Earnings. In addition, this business segment recorded equity income of $6 million, $36 million and $7 million in the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in SESH, a jointly-owned pipeline. The 2007 and 2008 year-end results include $6 million and $33 million of pre-operating allowance for funds used during construction, respectively. The 2009 results include a non-cash pre-tax charge of $16 million to reflect SESH’s decision to discontinue the use of guidance for accounting for regulated operations, which was partially offset by the receipt of a one-time payment related to the construction of the pipeline and a reduction in estimated property taxes, of which our 50% share was $5 million. Excluding the effect of these adjustments, equity earnings from normal operations was $3 million and $18 million in 2008 and 2009, respectively.  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 2007, 2008 and 2009 (in millions, except throughput data):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 175     $ 252     $ 241  
Expenses:
                       
Natural gas
    (4 )     21       51  
Operation and maintenance
    66       69       77  
Depreciation and amortization
    11       12       15  
Taxes other than income taxes
    3       3       4  
Total expenses
    76       105       147  
Operating Income
  $ 99     $ 147     $ 94  
                         
Gathering throughput (in Bcf)
    398       421       426  

2009 Compared to 2008.   Our Field Services business segment reported operating income of $94 million for 2009 compared to $147 million for 2008. Operating margin from new projects and core gathering services increased approximately $24 million for 2009 when compared to the same period in 2008 primarily due to continued development in the shale plays.  This increase was offset primarily by the effect of a decline in commodity prices of approximately $54 million from the significantly higher prices experienced in 2008.  Operating income for 2009 also included higher costs associated with incremental facilities ($4 million) and increased pension cost ($2 million).  Operating income for 2008 benefited from a one-time gain ($11 million) related to a settlement and contract buyout of one of our customers and a gain on sale of assets ($6 million).

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 ($6 million).

Equity Earnings. In addition, this business segment recorded equity income of $10 million, $15 million and $8 million for the years ended December 31, 2007, 2008 and 2009, respectively, from its 50% interest in a jointly-owned gas processing plant. The decrease is driven by a decrease in natural gas liquid prices. 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 2007, 2008 and 2009 (in millions):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
                   
Revenues
  $ 10     $ 11     $ 11  
Expenses
    15             7  
Operating Income (Loss)
  $ (5 )   $ 11     $ 4  

2009 Compared to 2008.   Our Other Operations business segment’s operating income in 2009 compared to 2008 decreased by $7 million primarily as a result of an increase in depreciation and amortization expense ($4 million) and an increase in franchise taxes ($3 million).

 
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).

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The net cash provided by (used in) operating, investing and financing activities for 2007, 2008 and 2009 is as follows (in millions):

   
Year Ended December 31,
 
   
2007
   
2008
   
2009
 
Cash provided by (used in):
                 
Operating activities
  $ 774     $ 851     $ 1,841  
Investing activities
    (1,300 )     (1,368 )     (896 )
Financing activities
    528       555       (372 )

Cash Provided by Operating Activities

Net cash provided by operating activities in 2009 increased $990 million compared to 2008 primarily due to decreased cash used in net regulatory assets and liabilities primarily related to Hurricane Ike restoration costs in 2008 ($366 million), decreased cash used in net margin deposits ($298 million), decreased cash used in gas storage inventory ($246 million) and increased cash provided by net accounts receivable/payable ($41 million).

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).

Cash Used in Investing Activities

Net cash used in investing activities decreased $472 million in 2009 compared to 2008 due to decreased notes receivable from unconsolidated affiliates of $498 million, decreased investment in unconsolidated affiliates of $91 million and decreased restricted cash of transition bond companies of $37 million, offset by increased capital expenditures of $140 million primarily related to our Field Services business segment.

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.

Cash Provided by (Used in) Financing Activities

Net cash used in financing activities in 2009 increased $927 million compared to 2008 primarily due to decreased borrowings under revolving credit facilities ($2.6 billion), and decreased short-term borrowings ($19 million), which were partially offset by decreased repayments of long-term debt ($1.2 billion), increased proceeds from the issuance of common stock ($424 million) and increased proceeds from the issuance of long-term debt ($77 million).

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).
 

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 2010 include the following:

 
approximately $1.2 billion of capital requirements;

 
maturing long-term debt aggregating approximately $206 million;

 
$290 million for our January 2010 purchase of pollution control bonds issued on our behalf;

 
$241 million of scheduled principal payments on transition and system restoration bonds;

 
$45 million for our January 2010 redemption of debentures; 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 2010. 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 2009 and estimates of our capital requirements for 2010 through 2014 (in millions):

   
2009