ceheform10k.htm

10-K 1 ceheform10k.htm FORM 10-K - ANNUAL REPORT DECEMBER 31, 2008 ceheform10k.htm

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

________________

Form 10-K

(Mark One)
R	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the fiscal year ended December 31, 2008
or
£	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

	For the transition period from to

Commission file number 1-3187

______________________________

CenterPoint Energy Houston Electric, LLC

(Exact name of registrant as specified in its charter)

Texas	22-3865106
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1111 Louisiana
Houston, Texas 77002	(713) 207-1111
(Address and zip code of principal executive offices)	(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the act:

Title of each class	Name of each exchange on which registered
9.15% First Mortgage Bonds due 2021	New York Stock Exchange
6.95% General Mortgage Bonds due 2033	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the act:

None

CenterPoint Energy Houston Electric, LLC meets the conditions set forth in general instruction I(1)(a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes £ No R

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 £ No R

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 R 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 the registrant’s 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. R

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 o Accelerated filer o Non-accelerated filer þ 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 by Rule 12b-2 of the Exchange Act).Yes £ No R

The aggregate market value of the common equity held by non-affiliates as of June 30, 2008: None

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TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	1
Item 1A.	Risk Factors	12
Item 1B.	Unresolved Staff Comments	19
Item 2.	Properties	19
Item 3.	Legal Proceedings	19
Item 4.	Submission of Matters to a Vote of Security Holders	19

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	20
Item 6.	Selected Financial Data	20
Item 7.	Management’s Narrative Analysis of Results of Operations	20
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	31
Item 8.	Financial Statements and Supplementary Data	32
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	56
Item 9A(T).	Controls and Procedures	56
Item 9B.	Other Information	56

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	56
Item 11.	Executive Compensation	56
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	56
Item 13.	Certain Relationships and Related Transactions, and Director Independence	56
Item 14.	Principal Accounting Fees and Services	57

	PART IV
Item 15.	Exhibits and Financial Statement Schedules	57

Ex. 12	Computation of Ratios of Earnings to Fixed Charges
Ex. 23	Consent of Deloitte & Touche LLP
Ex. 31.1	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
Ex. 31.2	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
Ex. 32.1	Section 1350 Certification of David M. McClanahan
Ex. 32.2	Section 1350 Certification of Gary L. Whitlock

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We meet the conditions specified in General Instruction I (1)(a) and (b) of Form 10-K and are thereby permitted to use the reduced disclosure format for wholly owned subsidiaries of reporting companies specified therein. Accordingly, we have omitted from this report the information called for by Item 4 (Submission of Matters to a Vote of Security Holders), Item 10 (Directors, Executive Officers and Corporate Governance), Item 11 (Executive Compensation), Item 12 (Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters) and Item 13 (Certain Relationships and Related Transactions, and Director Independence) of Form 10-K. In lieu of the information called for by Item 6 (Selected Financial Data) and Item 7 (Management’s Discussion and Analysis of Financial Condition and Results of Operations) of Form 10-K, we have included, under Item 7, Management’s Narrative Analysis of Results of Operations to explain the reasons for material changes in the amount of revenue and expense items between 2006, 2007 and 2008.

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 provide electric transmission and distribution services to retail electric providers (REPs) serving over 2 million metered customers in a 5,000-square mile area of the Texas Gulf Coast that has a population of approximately 5.6 million people and includes Houston. In this report, unless the content indicates otherwise, references to “CenterPoint Houston,” “we,” “us” or similar terms mean CenterPoint Energy Houston Electric, LLC and its subsidiaries. We are an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company. We have only one reportable business segment: Electric Transmission & Distribution.

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 parent company’s 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). Our parent company’s website address is www.centerpointenergy.com. Except to the extent explicitly stated herein, documents and information on our parent company’s website are not incorporated by reference herein.

Electric Transmission & Distribution

In 1999, the Texas legislature adopted the Texas Electric Choice Plan (Texas electric restructuring law) that led to the restructuring of certain integrated electric utilities operating within Texas. Pursuant to that legislation, integrated electric utilities operating within the Electric Reliability Council of Texas, Inc. (ERCOT) were required to unbundle their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation also required that the prices for wholesale generation and retail electric sales be unregulated, but services by companies providing transmission and distribution service, such as us, would continue to be regulated by the Public Utility Commission of Texas (Texas Utility Commission). The legislation provided for a transition period to move to the new market structure and provided a true-up mechanism for the formerly integrated electric utilities to recover stranded and certain other costs resulting from the transition to competition. Those costs are recoverable after approval by the Texas Utility Commission either through the issuance of securitization bonds or through the implementation of a competition transition charge (CTC) as a rider to the utility’s tariff.

We are the only business of CenterPoint Energy that continues to engage in electric utility operations. We are a transmission and distribution electric utility that operates wholly within the state of Texas. Neither we nor any other subsidiary of CenterPoint Energy makes sales of electric energy at retail or wholesale, or owns or operates any electric generating facilities.

Electric Transmission

On behalf of REPs, we deliver 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 our certificated service territory. We provide transmission services under tariffs approved by the Texas Utility Commission.

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Electric Distribution

In ERCOT, end users purchase their electricity directly from certificated REPs. We deliver electricity for REPs in our certificated service area by carrying lower-voltage power from the substation to the retail electric customer. Our distribution network receives electricity from the transmission grid through power distribution substations and delivers electricity to end users through distribution feeders. Our operations include construction and maintenance of electric transmission and distribution facilities, metering services, outage response services and call center operations. We provide 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

We are a member of ERCOT. ERCOT serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally-owned electric utilities, rural electric cooperatives, independent generators, power marketers and REPs. The ERCOT market includes most of the State of Texas, other than a portion of the panhandle, portions of the eastern part of the state bordering Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market includes an aggregate net generating capacity of approximately 73,000 megawatts (MW). There are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council (NERC) and approved by the Federal Energy Regulatory Commission (FERC). These reliability standards are administered by the Texas Regional Entity (TRE), a functionally independent division of ERCOT. The Texas Utility Commission has primary jurisdiction over the ERCOT market to ensure the adequacy and reliability of electricity supply across the state’s main interconnected power transmission grid. The ERCOT independent system operator (ERCOT ISO) is responsible for operating the bulk electric power supply system in the ERCOT market. Its responsibilities include ensuring that electricity production and delivery are accurately accounted for among the generation resources and wholesale buyers and sellers. Unlike certain other regional power markets, the ERCOT market is not a centrally dispatched power pool, and the ERCOT ISO does not procure energy on behalf of its members other than to maintain the reliable operations of the transmission system. Members who sell and purchase power are responsible for contracting sales and purchases of power bilaterally. The ERCOT ISO also serves as agent for procuring ancillary services for those members who elect not to provide their own ancillary services.

Our 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. We participate with the ERCOT ISO and other ERCOT utilities to plan, design, obtain regulatory approval for and construct new transmission lines necessary to increase bulk power transfer capability and to remove existing constraints on the ERCOT transmission grid.

Recovery of True-Up Balance

The Texas electric restructuring law substantially amended the regulatory structure governing electric utilities in order to allow retail competition for electric customers beginning in January 2002. The Texas electric restructuring law required the Texas Utility Commission to conduct a “true-up” proceeding to determine our stranded costs and certain other costs resulting from the transition to a competitive retail electric market and to provide for our recovery of those costs.

In March 2004, we filed our 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 us 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

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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.

We 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 us 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 our initial request.

We 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 us to recover EMCs paid to Reliant Energy, Inc. (RRI);

•

ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

•

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

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

In June 2008, we petitioned the Texas Supreme Court for review of the court of appeals decision. In our petition, we seek 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 us 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 we 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) we should not have been permitted to recover construction work in progress balances without proving those amounts in the manner required by law and (v) the Texas Utility Commission was without authority to award interest on the capacity auction true-up award.

Review by the Texas Supreme Court of the court of appeals decision is at the discretion of the court. In November 2008, the Texas Supreme Court requested the parties to the Petitions for Review to submit briefs on the merits of the issues raised. Briefing at the Texas Supreme Court should be completed in the second quarter of 2009. Although the Texas Supreme Court has not indicated whether it will grant review of the lower court’s decision, its request for full briefing on the merits allowed the parties to more fully explain their positions. There is no prescribed time in which the Texas Supreme Court must determine whether to grant review or, if review is granted, for a decision by that court. Although we and CenterPoint Energy believe that our true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that we will be successful in our

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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 we ultimately are authorized to recover or are required to refund beyond the amounts recorded based on the True-Up Order, but could range from $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008.

In the True-Up Order, the Texas Utility Commission reduced our 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 our 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 us to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy 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 our 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 CenterPoint Energy to pay an amount equal to our unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny us the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals, though the Texas Supreme Court, if it grants review, will have authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. We and CenterPoint Energy will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to us in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a CTC or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of ours 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, we 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, we received an order from the Texas Utility Commission allowing us 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 us 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 us to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). We implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately

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$620 million. The return on the CTC portion of the true-up balance was included in our 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 us to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. We and the Texas Utility Commission appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two of the appellants have requested further review from the Texas Supreme Court. In March 2009, the Texas Supreme Court requested the parties to file briefs on the merits in their appeals. Review by the Texas Supreme Court is discretionary with that court, and there is no deadline for its action on the appeals. 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 financial condition, results of operations or cash flows.

During the years ended December 31, 2006, 2007 and 2008, we recognized approximately $55 million, $42 million and $5 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2006, 2007 and 2008, we recognized approximately $13 million, $14 million and $13 million, respectively, of the allowed equity return not previously recognized. As of December 31, 2008, we have not recognized an allowed equity return of $207 million on our true-up balance because such return will be recognized as it is recovered in rates.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, we 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. We 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 ours issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

Hurricane Ike

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

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

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not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $17 million.

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

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

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

Customers

We serve nearly all of the Houston/Galveston metropolitan area. Our customers consist of 79 REPs, which sell electricity to over 2 million metered customers in our certificated service area, and municipalities, electric cooperatives and other distribution companies located outside our certificated service area. Each REP is licensed by, and must meet minimal creditworthiness criteria established by, the Texas Utility Commission. Two of the REPs in our service area are subsidiaries of RRI. Sales to subsidiaries of RRI represented approximately 56%, 51% and 48% of our transmission and distribution revenues in 2006, 2007 and 2008, respectively. Our billed receivables balance from REPs as of December 31, 2008 was $141 million. Approximately 46% of this amount was owed by subsidiaries of RRI. In March 2009, RRI announced that it had reached an agreement to sell its Texas retail business to NRG Energy, Inc. We do not have long-term contracts with any of our customers. We operate 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, we received approval from the Texas Utility Commission to deploy an advanced metering system (AMS) across our service territory over the next five years. We 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. We will recover the cost for the AMS through a monthly surcharge to all REPs over 12 years. The surcharge for each residential consumer for the first 24 months, beginning in February 2009, will be $3.24 per month; thereafter, the surcharge is scheduled to be reduced to $3.05 per month. These amounts are subject to upward or downward adjustment in future proceedings to reflect actual costs incurred and to address required changes in scope. We project 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.

We are also pursuing possible deployment of an electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” which would make use of our facilities to provide on-demand data and information about the status of facilities on our system. Although this technology is still in the developmental stage, we believe we have the potential to provide a significant improvement in grid planning, operations and maintenance of our distribution system. These improvements would be expected to contribute to fewer and shorter outages, better customer service, improved operations costs, improved security and more effective use of our workforce. Texas

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Utility Commission approval and appropriate rate treatment would be sought in connection with any actual deployment of this technology.

Competition

There are no other electric transmission and distribution utilities in our service area. In order for another provider of transmission and distribution services to provide such services in our 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 our service area at this time.

Seasonality

A significant portion of our revenues are derived from rates that we collect from each REP based on the amount of electricity we deliver on behalf of such REP. Thus, our 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 our properties are located in Texas. Our properties consist primarily of high voltage electric transmission lines and poles, distribution lines, substations, service wires and meters. Most of our 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 ours, subject to certain exclusions, are currently subject to:

•

the lien of a Mortgage and Deed of Trust (the Mortgage) dated November 1, 1944, as supplemented; and

•

the lien of a General Mortgage (the General Mortgage) dated October 10, 2002, as supplemented, which is junior to the lien of the Mortgage.

As of December 31, 2008, we had outstanding approximately $2.6 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated, $600 million securing borrowings under a credit facility which was unutilized and approximately $229 million held in trust to secure pollution control bonds for which we are obligated. Additionally, we 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. We may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $1.8 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2008. However, we have contractually agreed that we will not issue additional first mortgage bonds, subject to certain exceptions. In January 2009, we issued $500 million aggregate principal amount of general mortgage bonds in a public offering.

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

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

Substations. As of December 31, 2008, we owned 229 major substation sites having a total installed rated transformer capacity of 51,400 megavolt amperes.

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Service Centers. We operate 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

We hold non-exclusive franchises from the incorporated municipalities in our service territory. In exchange for the payment of fees, these franchises give us the right to use the streets and public rights-of way of these municipalities to construct, operate and maintain our transmission and distribution system and to use that system to conduct our 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.

REGULATION

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

Federal Energy Regulatory Commission

We are not a “public utility” under the Federal Power Act and, therefore, are not generally regulated by the FERC, although certain of our 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 us and other utilities within ERCOT. Under this authority, the FERC has designated the NERC as the Electric Reliability Organization (ERO) to promulgate standards, under oversight of the FERC, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to impose fines and other sanctions on Electric Entities that fail to comply with the standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. We do not anticipate that the reliability standards proposed by the NERC and approved by the FERC will have a material adverse impact on our operations. To the extent that we are required to make additional expenditures to comply with these standards, it is anticipated that we 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, CenterPoint Energy filed with the FERC the required notification of its status as a public utility holding company. In October 2006, the FERC adopted additional rules regarding maintenance of books and records by utility holding companies and additional reporting and accounting requirements for centralized service companies that make allocations to public utilities regulated by the FERC under the Federal Power Act. Although CenterPoint Energy provides services to its subsidiaries through a service company, its service company is not subject to the FERC’s service company rules.

State and Local Regulation

We conduct our operations pursuant to a certificate of convenience and necessity issued by the Texas Utility Commission that covers our 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 us under cost of service rate regulation.

Our distribution rates charged to REPs for residential customers are based on amounts of energy delivered, whereas distribution rates for a majority of commercial and industrial customers are based on peak demand. All REPs in our service area pay the same rates and other charges for the same transmission and distribution services. Transmission rates charged to other distribution companies are based on amounts of energy transmitted under “postage stamp” rates that do not vary with the distance the energy is being transmitted. All distribution companies in ERCOT pay us the same rates and other charges for transmission services. This regulated delivery charge includes the transmission and distribution rate (which includes municipal franchise fees), a system benefit fund fee

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imposed by the Texas electric restructuring law, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility and transition charges associated with securitization of regulatory assets and securitization of stranded costs.

Recovery of True-Up Balance. For a discussion of our true-up proceedings, see “— Our Business — Electric Transmission & Distribution — Recovery of True-Up Balance” above.

Interim Transmission Costs of Service Update. In September 2008, we filed an application with the Texas Utility Commission requesting an interim update to our wholesale transmission rate. The filing resulted in a revenue requirement increase of $22.5 million over rates then in effect. Approximately 74% will be paid by distribution companies other than us. The remaining 26% represents our share, which cannot be included in rates until 2010 under the terms of the rate freeze implemented in the settlement of our 2006 rate proceeding described below. In November 2008, the Texas Utility Commission approved our request. The interim rates became effective for service on and after November 5, 2008.

Rate Agreement. Our 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 we will not seek to increase our 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. We 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 us that such a filing is unnecessary.

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 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.

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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. Legislation to regulate emissions of greenhouse gases has been introduced in Congress, and there has been a wide-ranging policy debate, both nationally and internationally, regarding the impact of these gases and possible means for their regulation. Some of the proposals would require industries such as the utility industry to meet stringent new standards requiring substantial reductions in carbon emissions. Those reductions could be costly and difficult to implement. Some proposals would provide for credits to those who reduce emissions below certain levels and would allow those credits to be traded and/or sold to others. While there is growing consensus that some form of global climate change program will be adopted, it is too early to determine when, and in what form, a regulatory scheme regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory scheme might have on us. Our electric transmission and distribution business, unlike most electric utilities, does not generate electricity and thus is not directly exposed to the risk of high capital costs and regulatory uncertainties that face electric utilities that are in the business of generating electricity. Nevertheless, our revenues could be adversely affected to the extent any resulting regulatory scheme has the effect of reducing consumption of electricity by ultimate consumers within our service territory.

Air Emissions

Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations regulate emissions of air pollutants from various industrial sources, and also impose various monitoring and reporting requirements. Such laws and regulations may require that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions or result in the increase of existing air emissions, obtain and strictly comply with air permits containing various emissions and operational limitations, or utilize specific emission control technologies to limit emissions. Our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, and potentially criminal enforcement actions. We may be required to incur certain capital expenditures in the future for air pollution control equipment in connection with obtaining and maintaining operating permits and approvals for air emissions. We believe, however, that our operations will not be materially adversely affected by such requirements, and the requirements are not expected to be any more burdensome to us than to other similarly situated companies.

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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 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. Ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes, and waste compressor oils may be regulated as hazardous waste.

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. In the course of our ordinary operations we generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the United States Environmental Protection Agency (EPA) and, in some cases, third parties to take action in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. Under CERCLA, we could be subject to joint and several liability for the costs of cleaning up and restoring sites where hazardous substances have been released, for damages to natural resources, and for the costs of certain health studies.

Liability for Preexisting Conditions

Some facilities owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries, including us, 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 CenterPoint Energy or us, but most existing claims relate to facilities previously owned by CenterPoint Energy or us. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its 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 CenterPoint Energy 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 CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to continue vigorously contesting claims that it does not consider to have merit and 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.

Other Environmental. From time to time we have received notices from regulatory authorities or others regarding our status as a potentially responsible party 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.

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EMPLOYEES

As of December 31, 2008, we had 2,858 full-time employees, of which approximately 43% are subject to collective bargaining agreements.

Item 1A. Risk Factors

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 our business.

Risk Factors Affecting Our Business

We may not be successful in ultimately recovering the full value of our true-up components, which could result in the elimination of certain tax benefits and could have an adverse impact on our results of operations, financial condition and cash flows.

In March 2004, we filed our true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued the True-Up Order allowing us 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.

•

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 us from recovering the interest component of the EMCs paid to REPs; and

•

affirmed the True-Up Order in all other respects.

We 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 us 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.

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Commission’s rulings that denied recovery of approximately $378 million related to depreciation and (iv) affirmed the Texas Utility Commission’s refusal to permit us 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 we 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) we 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 the True-Up Order, the Texas Utility Commission reduced our 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 us to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy 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 our stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

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challenged specifically by the appellants. We and CenterPoint Energy will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

We must seek recovery of significant restoration costs arising from Hurricane Ike.

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

We believe we are entitled to recover prudently incurred storm costs in accordance with applicable regulatory and legal principles. The Texas Legislature currently is considering passage of legislation that would (i) authorize the Texas Utility Commission to determine the amount of storm restoration costs that we would be entitled to recover and (ii) permit the Texas Utility Commission to issue a financing order that would allow us to recover the amount of storm restoration costs determined in such a proceeding through issuance of dedicated securitization bonds, which would be repaid over time through a charge imposed on REPs. In proceedings to determine and seek recovery of storm restoration costs under the proposed legislation, we would be required to prove to the Texas Utility Commission’s satisfaction our prudently incurred costs as well as to demonstrate the cost benefit from using securitization to recover those costs instead of alternative means. Alternatively, we have the right to seek recovery of these costs under traditional rate making principles. Our failure to recover costs incurred as a result of Hurricane Ike could adversely affect our liquidity, results of operations and financial condition. For more information about our recovery from Hurricane Ike, please read “Business — Electric Transmission & Distribution — Hurricane Ike” in Item 1 of this report.

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

Our receivables from the distribution of electricity are collected from REPs that supply the electricity we distribute to their customers. As of December 31, 2008, we did business with 79 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these REPs to pay for our services or could cause them to delay such payments. We depend on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a REP cannot make timely payments. Applicable Texas Utility Commission regulations significantly limit the extent to which we can demand credit protection from REPs for payments not made prior to the shift to the provider of last resort. However, the Texas Utility Commission is currently considering proposed revisions to those regulations that, as currently proposed, would (i) increase the credit protections that could be required from REPs and (ii) allow utilities to defer the loss of payments for recovery in a future rate case. Whether such revised regulations will ultimately be adopted and their terms cannot now be determined. RRI, through its subsidiaries, is our largest customer. Approximately 46% of our $141 million in billed receivables from REPs at December 31, 2008 was owed by subsidiaries of RRI. Any delay or default in payment by REPs such as RRI could adversely affect our cash flows, financial condition and results of operations. RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event RRI’s subsidiaries might seek to avoid honoring their obligations and claims might be made by creditors involving payments we have received from RRI’s subsidiaries.

Rate regulation of our business may delay or deny our ability to earn a reasonable return and fully recover our costs.

Our rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of our invested capital and our expenses in a test year. Thus, the rates that we are allowed to charge may not match our 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 our costs and enable us to earn a reasonable return on our invested capital.

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In this regard, pursuant to the Stipulation and Settlement Agreement approved by the Texas Utility Commission in September 2006, until June 30, 2010 we are limited in our 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 — Rate Agreement” in Item 1 of this report.

Disruptions at power generation facilities owned by third parties could interrupt our sales of transmission and distribution services.

We transmit and distribute to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. We do not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, our sales of transmission and distribution services may be diminished or interrupted, and our results of operations, financial condition and cash flows could be adversely affected.

Our revenues and results of operations are seasonal.

A significant portion of our revenues is derived from rates that we collect from each REP based on the amount of electricity we deliver on behalf of such REP. Thus, our 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 Associated with Our Consolidated Financial Condition

If we are unable to arrange future financings on acceptable terms, our ability to refinance existing indebtedness could be limited.

As of December 31, 2008, we had $4.4 billion of outstanding indebtedness on a consolidated basis, which includes $2.6 billion of non-recourse transition bonds. Our future financing activities may be significantly affected by, among other things:

•

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

•

our recovery of costs arising from Hurricane Ike;

•

general economic and capital market conditions;

•

credit availability from financial institutions and other lenders;

•

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

•

maintenance of acceptable credit ratings by us and CenterPoint Energy;

•

market expectations regarding our future earnings and cash flows;

•

market perceptions of our and CenterPoint Energy’s ability to access capital markets on reasonable terms;

•

our exposure to RRI as our customer and in connection with its indemnification obligations arising in connection with its separation from CenterPoint Energy; and

•

provisions of relevant tax and securities laws.

As of December 31, 2008, we had outstanding approximately $2.6 billion aggregate principal amount of general mortgage bonds, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated, $600 million securing borrowings under a credit facility which was unutilized and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated. Additionally, we had outstanding approximately $253 million aggregate principal amount of first

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mortgage bonds, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. We may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $1.8 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2008. However, we have contractually agreed that we will not issue additional first mortgage bonds, subject to certain exceptions. In January 2009, we issued $500 million aggregate principal amount of general mortgage bonds in a public offering.

Our current credit ratings are discussed in “Management’s Narrative Analysis of Results of Operations — Liquidity— Impact on Liquidity of a Downgrade in Credit Ratings” in Item 7 of this report. These credit ratings may not remain in effect for any given period of time and one or more of these ratings may be lowered or withdrawn entirely by a rating agency. We note that these credit ratings are not recommendations to buy, sell or hold our securities. Each rating should be evaluated independently of any other rating. Any future reduction or withdrawal of one or more of our credit ratings could have a material adverse impact on our ability to access capital on acceptable terms.

The financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

Our ratings and credit may be impacted by CenterPoint Energy’s credit standing. As of December 31, 2008, CenterPoint Energy and its subsidiaries other than us have approximately $953 million principal amount of debt required to be paid through 2011. This amount excludes amounts related to capital leases, transition bonds and indexed debt securities obligations. If CenterPoint Energy were to experience a deterioration in its credit standing or liquidity difficulties, our access to credit and our ratings could be adversely affected and the repayment of notes receivable from CenterPoint Energy in the amount of $750 million as of December 31, 2008 could be adversely affected.

We are an indirect wholly owned subsidiary of CenterPoint Energy. CenterPoint Energy can exercise substantial control over our dividend policy and business and operations and could do so in a manner that is adverse to our interests.

We are managed by officers and employees of CenterPoint Energy. Our management will make determinations with respect to the following:

•

our payment of dividends;

•

decisions on our financings and our capital raising activities;

•

mergers or other business combinations; and

•

our acquisition or disposition of assets.

There are no contractual restrictions on our ability to pay dividends to CenterPoint Energy. Our management could decide to increase our dividends to CenterPoint Energy to support its cash needs. This could adversely affect our liquidity. However, under our credit facility, our ability to pay dividends is restricted by a covenant that debt, excluding transition bonds, as a percentage of total capitalization may not exceed 65%.

Other Risks

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

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment as described in “Business — Environmental Matters” in Item 1 of this Form 10-K. As an owner or operator of electric transmission and distribution systems, we must comply with these laws and regulations at the

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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 our line of business that serve coastal regions, we do not have insurance covering our transmission and distribution system because we believe it to be cost prohibitive. We may not be able to recover the costs incurred in restoring our transmission and distribution properties following Hurricane Ike, or any such costs sustained in the future, through a change in our regulated rates, and any such recovery may not be timely granted. Therefore, we may not be able to restore any loss of, or damage to, any of our transmission and distribution properties without negative impact on our results of operations, financial condition and cash flows.

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

Under some circumstances, we and CenterPoint Energy could incur liabilities associated with assets and businesses we and CenterPoint Energy no longer own. These assets and businesses were previously owned by Reliant Energy, Incorporated (Reliant Energy), our predecessor, 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, CenterPoint Energy and its subsidiaries, including us, 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 and CenterPoint Energy could be responsible for satisfying the liability.

RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it would need to consider, among various options, restructuring under the bankruptcy laws, in which event RRI might not honor its indemnification obligations and claims by RRI’s creditors might be made against us as its former owner.

Reliant Energy and RRI are named as defendants in a number of lawsuits arising out of energy sales in California and other markets and financial reporting matters. Although these matters relate to the business and operations of RRI, claims against Reliant Energy have been made on grounds that include the effect of RRI’s financial results on Reliant Energy’s historical financial statements and liability of Reliant Energy as a controlling shareholder of RRI. We or CenterPoint Energy could incur liability if claims in one or more of these lawsuits were successfully asserted against us or CenterPoint Energy and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.

In connection with the organization and capitalization of Texas Genco, Texas Genco assumed liabilities associated with the electric generation assets Reliant Energy transferred to it. Texas Genco also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, CenterPoint Energy and its subsidiaries, including us, with respect to liabilities associated with the transferred assets and businesses. In many cases the liabilities assumed were our obligations and we were not released by third parties from these liabilities. The indemnity provisions were intended generally to place sole financial responsibility on Texas Genco and its subsidiaries for all liabilities associated with the current and historical businesses and operations of Texas Genco, regardless of the time those liabilities arose. In connection with the sale of Texas Genco’s fossil generation assets (coal, lignite and gas-fired plants) to NRG Texas LP (previously named Texas Genco LLC), the separation agreement CenterPoint Energy entered into with Texas Genco in connection with the organization and capitalization of Texas Genco was amended to provide that all of Texas Genco’s rights and obligations under the separation agreement relating to its fossil generation assets, including Texas Genco’s obligation to indemnify CenterPoint Energy with respect to liabilities associated with the fossil generation assets and related business, were assigned to and assumed by NRG Texas LP. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and CenterPoint Energy has assumed and agreed to indemnify NRG Texas LP against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by CenterPoint Energy. If Texas Genco or NRG Texas LP were unable to satisfy a liability that had been so assumed or indemnified against, and provided Reliant Energy had not been released from the liability in connection with the transfer, we could be responsible for satisfying the liability.

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CenterPoint Energy or its subsidiaries, including us, have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations owned by CenterPoint Energy or us, but most existing claims relate to facilities previously owned by CenterPoint Energy or us that are 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 CenterPoint Energy 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 CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense by NRG Texas LP.

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

The continued credit crisis and related turmoil in the global financial system may have an impact on our business, liquidity and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our liquidity and flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. With respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which had an $11 million participation in our credit facility, stopped funding its commitment following the bankruptcy filing of its parent in September 2008 and was subsequently terminated as a lender in our facility. Defaults of other lenders should they occur could adversely affect our liquidity. Capital market turmoil was also reflected in significant reductions in equity market valuations in 2008, which significantly reduced the value of assets of CenterPoint Energy’s pension plan, in which we participate. These reductions are expected to result in increased pension expense in 2009, which will impact 2009 results of operations.

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

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

Character of Ownership

We own or lease our principal properties in fee. Most of our electric lines are located, pursuant to easements and other rights, on public roads or on land owned by others. For information regarding our properties, please read “Business — Electric Transmission & Distribution — Properties” 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 “Regulation” and “Environmental Matters” in Item 1 of this report and Notes 3 and 8(b) to our consolidated financial statements, which information is incorporated herein by reference.

Item 4. Submission of Matters to a Vote of Security Holders

The information called for by Item 4 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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PART II

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

All of our 1,000 outstanding common shares are held by Utility Holding, LLC, a wholly owned subsidiary of CenterPoint Energy.

In 2006, 2007 and 2008, we paid dividends on our common shares of $100 million, $100 million and $640 million, respectively, to Utility Holding, LLC.

Our revolving credit facility limits our debt (excluding transition and other securitization bonds) as a percentage of total capitalization to 65%. This covenant could restrict our ability to distribute dividends.

Item 6. Selected Financial Data

The information called for by Item 6 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries). The ratio of earnings to fixed charges as calculated pursuant to Securities and Exchange Commission rules was 2.20, 1.99, 2.62, 2.61, and 2.33 for the years ended December 31, 2004, 2005, 2006, 2007 and 2008, respectively.

Item 7. Management’s Narrative Analysis of Results of Operations

The following narrative analysis should be read in combination with our consolidated financial statements and notes contained in Item 8 of this report.

OVERVIEW

We provide electric transmission and distribution services to retail electric providers (REPs) serving over 2 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.6 million people and includes Houston.

On behalf of REPs, we deliver electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout our 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).

EXECUTIVE SUMMARY

Significant Events in 2008 and 2009

Hurricane Ike

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

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

Debt Financing Transactions

Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of ours issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, we securitized transition property of approximately $483 million representing the remaining balance of the competition transition charge (CTC) adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement.

In November 2008, we entered into a $600 million 364-day credit facility. The credit facility will terminate if bonds are issued to securitize the costs incurred as a result of Hurricane Ike and if those bonds are issued prior to the November 24, 2009 expiration of the facility. We expect to seek legislative and regulatory approval for the issuance of such bonds during 2009.

In January 2009, we 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 our revolving credit facility and from the money pool, capital expenditures and storm restoration costs associated with Hurricane Ike.

Outlook

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

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during the last two quarters of 2008 have led to higher borrowing costs and greater uncertainty regarding the ability to execute transactions in these markets.

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

To the extent the adverse economic conditions affect our suppliers and customers, results from our energy delivery business 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. These factors may lead to reduced earnings during 2009, compared to 2008, if they continue significantly into 2009 or if the magnitude of the economic downturn increases beyond the impacts experienced in 2008.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

Our past earnings and results of operations are not necessarily indicative of our future earnings and results of operations. The magnitude of our future earnings and results of our operations will depend on or be affected by numerous factors including:

•

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

•

state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, environmental regulations, including regulations related to global climate change, and changes in or application of laws or regulations applicable to the various aspects of our business;

•

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

•

timely and appropriate rate actions and increases, allowing recovery of costs and a reasonable return on investment;

•

industrial, commercial and residential growth in our service territory and changes in market demand and demographic patterns;

•

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;

•

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

•

the ability of RRI and its subsidiaries to satisfy their other obligations to us, including indemnity obligations;

•

the outcome of litigation brought by or against us;

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•

our ability to control costs;

•

the investment performance of CenterPoint Energy’s employee benefit plans;

•

our potential business strategies, including acquisitions or dispositions of assets or businesses, which we cannot assure will be completed or will have the anticipated benefits to us; 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

Our results of operations are affected by seasonal fluctuations in the demand for electricity. Our results of operations are also affected by, among other things, the actions of various state and local governmental authorities having jurisdiction over rates we charge, debt service costs and income tax expense.

The following table sets forth selected financial data for the years ended December 31, 2006, 2007 and 2008, followed by a discussion of our consolidated results of operations based on operating income. We have provided a reconciliation of consolidated operating income to net income below.

	Year Ended December 31,
	2006			2007			2008
	(In millions, except throughput and customer data)
Revenues:
Electric transmission and distribution utility	$	1,516		$	1,560		$	1,593
Transition bond companies		265			277			323
Total Revenues		1,781			1,837			1,916
Expenses:
Operation and maintenance, excluding transition bond companies		611			652			703
Depreciation and amortization, excluding transition bond companies		243			243			277
Taxes other than income taxes		212			223			201
Transition bond companies		139			158			190
Total Expenses		1,205			1,276			1,371
Operating Income		576			561			545
Interest and other finance charges		(110	)		(107	)		(109	)
Interest on transition bonds (1)		(130	)		(123	)		(136	)
Other Income, net		67			68			43
Income Before Income Taxes		403			399			343
Income Tax Expense		(132	)		(126	)		(121	)
Net Income	$	271		$	273		$	222

Throughput (in gigawatt-hours (GWh)):
Residential		23,955			23,999			24,258
Total		75,877			76,291			74,840

Average number of metered customers:
Residential		1,743,963			1,793,600			1,821,267
Total		1,980,960			2,034,074			2,064,854

____________

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

2008 Compared to 2007. We reported operating income of $545 million for 2008, consisting of $407 million from our regulated electric transmission and distribution utility operations (TDU), exclusive of an additional $5 million from the competition transition charge (CTC), and $133 million related to transition bond companies. For 2007, operating income totaled $561 million, consisting of $400 million from the TDU, exclusive of an additional $42 million from the CTC, and $119 million related to transition bond companies. Revenues for the TDU increased due to customer growth, with over 30,000 metered customers added in 2008 ($23 million), increased usage ($15 million) in part caused by favorable weather experienced in 2008, increased transmission-related revenues

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($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 State Franchise Tax Law (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).

Income Tax Expense. Our effective tax rate of 35.4% differed from the 2007 effective tax rate of 31.6% primarily as a result of revisions to the Texas margin tax which was reported as an operating expense prior to 2008 and is now being reported as an income tax.

2007 Compared to 2006. We reported operating income of $561 million for 2007, consisting of $400 million from the TDU, exclusive of an additional $42 million from the CTC, and $119 million related to transition bond companies. For 2006, operating income totaled $576 million, consisting of $395 million from the TDU, exclusive of an additional $55 million from the CTC, and $126 million related to transition bond companies. Revenues increased due to growth ($22 million), with over 53,000 metered customers added in 2007, higher transmission-related revenues ($22 million), increased miscellaneous service charges ($15 million), increased demand ($7 million), interest on settlement of the final fuel reconciliation ($4 million) and a one-time charge in the second quarter of 2006 related to the resolution of the unbundled cost of service order ($32 million). These increases were partially offset by the rate reduction resulting from the 2006 rate case settlement that was implemented in October 2006 ($41 million) and lower CTC return resulting from the reduction in the allowed interest rate on the unrecovered CTC balance from 11.07% to 8.06% in 2006 ($13 million). Operation and maintenance expense increased primarily due to higher transmission costs ($25 million), the absence of a gain on the sale of property in 2006 ($13 million), and increased expenses, primarily related to low income and energy efficiency programs as required by the 2006 rate case settlement ($8 million), partially offset by settlement of the final fuel reconciliation ($13 million).

LIQUIDITY

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 during 2009 include approximately $422 million of capital expenditures and $208 million of scheduled principal payments on transition bonds.

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

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

2008	$	481
2009		422
2010		591
2011		579
2012		504
2013		506

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

Contractual Obligations	Total		2009			2010-2011		2012-2013	2014 and thereafter
Transition bond debt (1)	$	2,589	$	208	$	461	$	546	$	1,374
Other long-term debt		1,842		—		—		746		1,096
Interest payments - transition bond debt (1) (2)		794		140		227		177		250
Interest payments - other long-term debt (2)		1,319		118		261		246		694
Capital leases		1		—		—		—		1
Benefit obligations (3)		—		—		—		—		—
Income taxes (4)		3		3		—		—		—
Total contractual cash obligations	$	6,548	$	469	$	949	$	1,715	$	3,415

____________

(1)	Transition charges are adjusted at least annually to cover debt service on transition bonds.

(2)

We calculated estimated interest payments for long-term debt as follows: for fixed-rate debt and term debt, we calculated interest based on the applicable rates and payment dates; for variable-rate debt and/or non-term debt, we used interest rates in place as of December 31, 2008. We typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)	We expect to contribute approximately $8 million to our postretirement benefits plan in 2009 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.

(4)

Represents estimated income tax liability for settled positions for tax years under examination. In addition, as of December 31, 2008, the liability for uncertain income tax positions was $123 million. However, due to the high degree of uncertainty regarding the timing of potential future cash flows associated with these liabilities, we are unable to make a reasonably reliable estimate of the amount and period in which these liabilities might be paid.

Off-Balance Sheet Arrangements. Other than operating leases and first mortgage bonds and general mortgage bonds issued as collateral for long-term debt of CenterPoint Energy as discussed below, we have no off-balance sheet arrangements.

Debt Financing Transactions. Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of ours issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates in February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, we securitized transition property of approximately $483 million representing the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the fuel reconciliation settlement.

In January 2009, we issued $500 million 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 our revolving credit facility and from the money pool, capital expenditures and storm restoration costs associated with Hurricane Ike.

Credit Facilities. In November 2008, we entered into a $600 million 364-day credit facility. The credit facility will terminate if bonds are issued to securitize the costs incurred as a result of Hurricane Ike and if those bonds are issued prior to the November 24, 2009 expiration of the facility. We expect to seek legislative and regulatory approval for the issuance of such bonds during 2009.

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The 364-day credit facility is secured by a pledge of $600 million of general mortgage bonds issued by us. Borrowing costs for London Interbank Offered Rate (LIBOR)-based loans will be at a margin of 2.25 percent above LIBOR rates, based on our current ratings. In addition, we will pay lenders, based on current ratings, a per annum commitment fee of 0.5 percent for their commitments under the facility and a quarterly duration fee of 0.75 percent on the average amount of outstanding borrowings during the quarter. The spread to LIBOR and the commitment fee fluctuate based on the borrower’s credit rating. The facility contains covenants, including a debt (excluding transition and other securitization bonds) to total capitalization covenant.

Our $289 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on our current credit ratings. The facility contains a debt (excluding transition and other securitization bonds) to total capitalization covenant. Under our $289 million credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on our credit rating.

Borrowings under our credit facilities are subject to customary terms and conditions. However, there is no requirement that we make representations prior to borrowings as to the absence of material adverse changes or litigation that could be expected to have a material adverse effect. Borrowings under our credit facilities are subject to acceleration upon the occurrence of events of default that we consider customary. We are currently in compliance with the various business and financial covenants contained in our credit facilities.

As of February 13, 2009, we had the following facilities (in millions):

Date Executed	Type of Facility	Size of Facility		Amount Utilized at February 13, 2009			Termination Date
June 29, 2007	Revolver	$	289	$	4	(1)	June 29, 2012
November 25, 2008	Revolver		600		—		November 24, 2009

_________

(1)	Includes $4 million of outstanding letters of credit.

Securities Registered with the SEC. In October 2008, we and CenterPoint Energy jointly registered indeterminate principal amounts of our general mortgage bonds and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units.

Temporary Investments. As of February 13, 2009, we had no external temporary investments.

Money Pool. We participate in a money pool through which we and certain of our affiliates can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. At February 13, 2009, we had $103 million invested in the money pool. The money pool may not provide sufficient funds to meet our cash needs.

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Long-term Debt. Our long-term debt consists of our obligations and the obligations of our subsidiaries, including transition bonds issued by wholly owned subsidiaries. The following table shows future maturity dates of long-term debt issued by us to third parties and affiliates and scheduled future payment dates of transition bonds issued by our subsidiaries, CenterPoint Energy Transition Bond Company, LLC (Bond Company), CenterPoint Energy Transition Bond Company II, LLC (Bond Company II) and CenterPoint Energy Transition Bond Company III, LLC (Bond Company III), as of December 31, 2008. Amounts are expressed in millions.

Year	Third-Party		Affiliate		Sub-Total		Transition Bonds		Total
2009	$	—	$	—	$	—	$	208	$	208
2010		—		—		—		221		221
2011		—		—		—		240		240
2012		297		—		297		262		559
2013		450		—		450		283		733
2014		300		—		300		188		488
2015		—		151		151		201		352
2016		—		—		—		215		215
2017		127		—		127		231		358
2018		—		—		—		247		247
2019		—		—		—		264		264
2020		—		—		—		29		29
2021		102		—		102		—		102
2023		200		—		200		—		200
2027		56		—		56		—		56
2033		312		—		312		—		312
Total	$	1,844	$	151	$	1,995	$	2,589	$	4,584

As of December 31, 2008, outstanding first mortgage bonds and general mortgage bonds aggregated approximately $2.9 billion as shown in the following table. Amounts are expressed in millions.

	Issued Directly to Third Parties		Issued as Collateral for Our Debt		Issued as Collateral for CenterPoint Energy’s Debt		Total
First Mortgage Bonds	$	102	$	—	$	151	$	253
General Mortgage Bonds		1,262		829		527		2,618
Total	$	1,364	$	829	$	678	$	2,871

The lien of the general mortgage indenture is junior to that of the mortgage, pursuant to which the first mortgage bonds are issued. We may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $1.8 billion of additional first mortgage bonds and general mortgage bonds could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2008. However, we are contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.

The following table shows the maturity dates of the $678 million of first mortgage bonds and general mortgage bonds that we have issued as collateral for long-term debt of CenterPoint Energy. These bonds are not reflected in our consolidated financial statements because of the contingent nature of the obligations. Amounts are expressed in millions.

Year	First Mortgage Bonds		General Mortgage Bonds		Total
2011	$	—	$	19	$	19
2015		151		—		151
2018		—		50		50
2019		—		200		200
2020		—		90		90
2026		—		100		100
2028		—		68		68
Total	$	151	$	527	$	678

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At December 31, 2008, Bond Company had $449 million aggregate principal amount of outstanding transition bonds that were issued in 2001 in accordance with the Texas Electric Choice Plan (Texas electric restructuring law). At December 31, 2008, Bond Company II had $1.65 billion aggregate principal amount of outstanding transition bonds that were issued in 2005 in accordance with the Texas electric restructuring law. At December 31, 2008, Bond Company III had $488 million aggregate principal amount of outstanding transition bonds that were issued pursuant to a financing order issued by the Texas Utility Commission in September 2007. The transition bonds are secured by “transition property,” as defined in the Texas electric restructuring law, which includes the irrevocable right to recover, through non-bypassable transition charges payable by retail electric customers, qualified costs provided in the Texas electric restructuring law. The transition bonds are reported as our long-term debt, although the holders of the transition bonds have no recourse to any of our assets or revenues, and our creditors have no recourse to any assets or revenues (including, without limitation, the transition charges) of the bond companies. We have no payment obligations with respect to the transition bonds except to remit collections of transition charges as set forth in a servicing agreement between us and the bond companies and in an intercreditor agreement among us, the bond companies and other parties.

Impact on Liquidity of a Downgrade in Credit Ratings. As of February 13, 2009, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services, a division of The McGraw Hill Companies (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior debt.

Moody’s

S&P

Fitch

Instrument

Rating

Outlook(1)

Rating

Outlook(2)

Rating

Outlook(3)

Senior Secured Debt (First Mortgage Bonds)

Baa2

Stable

BBB+

Stable

A-

Stable

Senior Secured Debt (General Mortgage Bonds)

Baa2

Stable

BBB+

Stable

BBB+

Stable

__________

(1)	A “stable” outlook from Moody’s indicates that Moody’s does not expect to put the rating on review for an upgrade or downgrade within 18 months from when the outlook was assigned or last affirmed.

(2)	An S&P rating outlook assesses the potential direction of a long-term credit rating over the intermediate to longer term.

(3)	A “stable” outlook from Fitch encompasses a one-to-two year horizon as to the likely ratings direction.

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

A decline in credit ratings could increase borrowing costs under our two credit facilities. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions.

Cross Defaults. Under CenterPoint Energy’s revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us will cause a default. In addition, four outstanding series of CenterPoint Energy’s senior notes, aggregating $950 million in principal amount as of February 13, 2009, provide that a payment default by us, in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our debt instruments or bank credit facilities.

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

•

increases in interest expense in connection with debt refinancings and borrowings under our credit facilities;

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•

various regulatory actions;

•

the ability of RRI and its subsidiaries to satisfy their obligations as our principal customers and in respect of RRI’s indemnity obligations to us;

•

the outcome of litigation brought by and against us;

•

restoration costs and revenue losses resulting from natural disasters such as hurricanes and the timing of recovery of such costs; and

•

various other risks identified in “Risk Factors” in Item 1A of this report.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. Our credit facilities limit our debt (excluding transition and other securitization bonds) as a percentage of our total capitalization to 65%. Additionally, we have contractually agreed that we will not issue additional first mortgage bonds, subject to certain exceptions.

Relationship with CenterPoint Energy. We are an indirect wholly owned subsidiary of CenterPoint Energy. As a result of this relationship, the financial condition and liquidity of our parent company could affect our access to capital, our credit standing and our financial condition.

CRITICAL ACCOUNTING POLICIES

A critical accounting policy is one that is both important to the presentation of our financial condition and results of operations and requires management to make difficult, subjective or complex accounting estimates. An accounting estimate is an approximation made by management of a financial statement element, item or account in the financial statements. Accounting estimates in our historical consolidated financial statements measure the effects of past business transactions or events, or the present status of an asset or liability. The accounting estimates described below require us to make assumptions about matters that are highly uncertain at the time the estimate is made. Additionally, different estimates that we could have used or changes in an accounting estimate that are reasonably likely to occur could have a material impact on the presentation of our financial condition or results of operations. The circumstances that make these judgments difficult, subjective and/or complex have to do with the need to make estimates about the effect of matters that are inherently uncertain. Estimates and assumptions about future events and their effects cannot be predicted with certainty. We base our estimates on historical experience and on various other assumptions that we believe to be reasonable under the circumstances, the results of which form the basis for making judgments. These estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. Our significant accounting policies are discussed in Note 2 to our consolidated financial statements. We believe the following accounting policies involve the application of critical accounting estimates. Accordingly, these accounting estimates have been reviewed and discussed with the audit committee of the board of directors of CenterPoint Energy.

Accounting for Rate Regulation

Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71), provides that rate-regulated entities account for and report assets and liabilities consistent with the recovery of those incurred costs in rates if the rates established are designed to recover the costs of providing the regulated service and if the competitive environment makes it probable that such rates can be charged and collected. We apply SFAS No. 71, therefore, certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet as regulatory assets or liabilities and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Regulatory assets and liabilities are recorded when it is probable, as defined in SFAS No. 5, “Accounting for Contingencies” (SFAS No. 5), that these items will be recovered or reflected in future rates. Determining probability requires significant judgment on the part of management and includes, but is not limited to, consideration of testimony presented in regulatory hearings, proposed regulatory decisions, final regulatory orders and the strength or status of applications for rehearing or state court appeals. If events were to occur that would make the recovery of these assets and liabilities no longer probable, we would be required to write off or write down

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these regulatory assets and liabilities. At December 31, 2008, we had recorded regulatory assets of $2.8 billion and regulatory liabilities of $313 million.

Impairment of Long-Lived Assets and Intangibles

We review the carrying value of our long-lived assets, including identifiable intangibles, whenever events or changes in circumstances indicate that such carrying values may not be recoverable. Unforeseen events and changes in circumstances and market conditions and material differences in the value of long-lived assets and intangibles due to changes in estimates of future cash flows, interest rates, regulatory matters and operating costs could negatively affect the fair value of our assets and result in an impairment charge.

Fair value is the amount at which the asset could be bought or sold in a current transaction between willing parties and may be estimated using a number of techniques, including quoted market prices or valuations by third parties, present value techniques based on estimates of cash flows, or multiples of earnings or revenue performance measures. The fair value of the asset could be different using different estimates and assumptions in these valuation techniques.

Asset Retirement Obligations

We account for our long-lived assets under SFAS No. 143, “Accounting for Asset Retirement Obligations” (SFAS No. 143), and Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations ─ An Interpretation of SFAS No. 143” (FIN 47). SFAS No. 143 and FIN 47 require that an asset retirement obligation be recorded at fair value in the period in which it is incurred if a reasonable estimate of fair value can be made. In the same period, the associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with SFAS No. 143 and FIN 47, and costs recovered through the ratemaking process.

We estimate the fair value of asset retirement obligations by calculating the discounted cash flows that are dependent upon the following components:

•

Inflation adjustment - The estimated cash flows are adjusted for inflation estimates for labor, equipment, materials, and other disposal costs;

•

Discount rate - The estimated cash flows include contingency factors that were used as a proxy for the market risk premium; and

•

Third party markup adjustments - Internal labor costs included in the cash flow calculation were adjusted for costs that a third party would incur in performing the tasks necessary to retire the asset.

Changes in these factors could materially affect the obligation recorded to reflect the ultimate cost associated with retiring the assets under SFAS No. 143 and FIN 47. For example, if the inflation adjustment increased 25 basis points, this would increase the balance for asset retirement obligations by approximately 2%. Similarly, an increase in the discount rate by 25 basis points would decrease asset retirement obligations by approximately the same percentage. At December 31, 2008, our estimated cost of retiring these assets was approximately $17 million.

Unbilled Energy Revenues

Revenues related to electricity delivery are generally recognized upon delivery to customers. However, the determination of deliveries to individual customers is based on the reading of their meters, which is performed on a systematic basis throughout the month. At the end of each month, deliveries to customers since the date of the last meter reading are estimated and the corresponding unbilled revenue is estimated. Unbilled electricity delivery revenue is estimated each month based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience. As additional information becomes available, or actual amounts are determinable, the recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

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NEW ACCOUNTING PRONOUNCEMENTS

See Note 2(l) to the consolidated financial statements, incorporated herein by reference, for a discussion of new accounting pronouncements that affect us.

OTHER SIGNIFICANT MATTERS

Pension Plans. As discussed in Note 2(m) to the consolidated financial statements, we participate in CenterPoint Energy’s qualified and non-qualified pension plans covering substantially all employees. Pension expense for 2009 is expected to be $44 million, of which we expect $28 million to impact pre-tax earnings, based on an expected return on plan assets of 8.00% and a discount rate of 6.90% as of December 31, 2008. We recorded pension income of $3 million for the year ended December 31, 2008. The increase in pension expense in 2009 is primarily the result of a decline in 2008 in plan assets of the CenterPoint Energy pension plan, in which we participate. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension plan will impact our future pension expense and liabilities. We cannot predict with certainty what these factors will be in the future.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

As of December 31, 2008, we had outstanding long-term debt, bank loans, lease obligations and money pool borrowings from affiliates that subject us to the risk of loss associated with movements in market interest rates.

We had floating rate obligations of $97 million and $259 million at December 31, 2007 and 2008, respectively. If the floating interest rates were to increase by 10% from December 31, 2008 rates, our combined interest expense would increase by less than $1 million annually.

At December 31, 2007 and 2008, we had outstanding fixed-rate debt aggregating $4.0 billion and $4.3 billion in principal amount and having a fair value of approximately $4.0 billion and $4.2 billion in 2007 and 2008, respectively. These instruments are fixed-rate and therefore, do not expose us to the risk of loss in earnings due to changes in market interest rates (please read Note 6 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $137 million if interest rates were to decline by 10% from their levels at December 31, 2008. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

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Item 8. Financial Statements and Supplementary Data

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of

CenterPoint Energy Houston Electric, LLC

Houston, Texas

We have audited the accompanying consolidated balance sheets of CenterPoint Energy Houston Electric, LLC and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2008 and 2007, and the related statements of consolidated income, cash flows, and member’s equity for each of the three years in the period ended December 31, 2008. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy Houston Electric, LLC and subsidiaries at December 31, 2008 and 2007, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2008, in conformity with accounting principles generally accepted in the United States of America.

DELOITTE & TOUCHE LLP

Houston, Texas

March 11, 2009

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MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL

OVER FINANCIAL REPORTING

Our management is responsible for establishing and maintaining adequate internal control over financial reporting. Internal control over financial reporting is defined in Rule 13a-15(f) or 15d-15(f) promulgated under the Securities Exchange Act of 1934 as a process designed by, or under the supervision of, the company’s principal executive and principal financial officers and effected by the company’s board of directors, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles and includes those policies and procedures that:

•

Pertain to the maintenance of records that in reasonable detail accurately and fairly reflect the transactions and dispositions of the assets of the company;

•

Provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

•

Provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company’s assets that could have a material effect on the financial statements.

Management has designed its internal control over financial reporting to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with accounting principles generally accepted in the United States of America. Management’s assessment included review and testing of both the design effectiveness and operating effectiveness of controls over all relevant assertions related to all significant accounts and disclosures in the financial statements.

All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management has concluded that our internal control over financial reporting was effective as of December 31, 2008.

This annual report does not include an attestation report of our registered public accounting firm regarding internal control over financial reporting. Management’s report was not subject to attestation by our registered public accounting firm pursuant to temporary rules of the Securities and Exchange Commission that permit us to provide only management’s report in this annual report.

/s/ DAVID M. MCCLANAHAN
Chairman

/s/ GARY L. WHITLOCK
Executive Vice President and Chief
Financial Officer

March 11, 2009

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME

	Year Ended December 31,
	2006			2007			2008
	(In Millions)

Revenues	$	1,781		$	1,837		$	1,916

Expenses:
Operation and maintenance		614			655			709
Depreciation and amortization		379			398			460
Taxes other than income taxes		212			223			202
Total		1,205			1,276			1,371

Operating Income		576			561			545

Other Income (Expense):
Interest and other finance charges		(110	)		(107	)		(109	)
Interest on transition bonds		(130	)		(123	)		(136	)
Other, net		67			68			43
Total		(173	)		(162	)		(202	)

Income Before Income Taxes		403			399			343
Income tax expense		(132	)		(126	)		(121	)

Net Income	$	271		$	273		$	222

See Notes to the Company’s Consolidated Financial Statements

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS

	December 31,
	2007		2008
	(In Millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	128	$	166
Accounts and notes receivable, net		172		227
Accounts and notes receivable—affiliated companies		25		30
Accrued unbilled revenues		102		60
Inventory		60		74
Taxes receivable		3		8
Deferred tax asset		—		1
Other		70		82
Total current assets		560		648

Property, Plant and Equipment, net		4,391		4,604

Other Assets:
Regulatory assets		2,621		2,832
Notes receivable—affiliated companies		750		750
Other		36		48
Total other assets		3,407		3,630

Total Assets	$	8,358	$	8,882

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	159	$	208
Accounts payable		47		150
Accounts and notes payable—affiliated companies		75		36
Taxes accrued		87		87
Interest accrued		83		100
Other		74		89
Total current liabilities		525		670

Other Liabilities:
Accumulated deferred income taxes, net		1,189		1,506
Unamortized investment tax credits		28		21
Benefit obligations		176		187
Regulatory liabilities		354		313
Notes payable—affiliated companies		151		151
Other		134		170
Total other liabilities		2,032		2,348

Long-Term Debt		3,743		4,224

Commitments And Contingencies (Note 8)

Member’s Equity		2,058		1,640

Total Liabilities and Member’s Equity	$	8,358	$	8,882

See Notes to the Company’s Consolidated Financial Statements

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Year Ended December 31,
	2006			2007			2008
	(In Millions)
Cash Flows from Operating Activities:
Net income	$	271		$	273		$	222
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		379			398			460
Deferred income taxes		(76	)		(73	)		347
Amortization of deferred financing costs		12			11			13
Changes in other assets and liabilities:
Accounts and notes receivable, net		14			(14	)		(13	)
Accounts receivable/payable, affiliates		(36	)		23			(5	)
Taxes receivable		(6	)		31			(5	)
Inventory		(3	)		3			(14	)
Accounts payable		8			(24	)		21
Interest and taxes accrued		1			(20	)		17
Net regulatory assets and liabilities		56			67			(376	)
Other current assets		(2	)		—			(2	)
Other current liabilities		17			7			13
Other assets		9			(1	)		1
Other liabilities		17			(18	)		(5	)
Other, net		(6	)		1			(9	)
Net cash provided by operating activities		655			664			665
Cash Flows from Investing Activities:
Capital expenditures		(381	)		(402	)		(462	)
Increase in restricted cash of transition bond companies		(32	)		(1	)		(11	)
Other, net		1			12			14
Net cash used in investing activities		(412	)		(391	)		(459	)
Cash Flows from Financing Activities:
Long-term revolving credit facility, net		—			50			201
Proceeds from long-term debt		—			—			488
Payments of long-term debt		(74	)		(147	)		(159	)
Increase (decrease) in short-term notes payable with affiliates		49			(70	)		(39	)
Debt issuance costs		—			—			(19	)
Contribution to parent		(36	)		—			—
Dividend to parent		(100	)		(100	)		(640	)
Net cash used in financing activities		(161	)		(267	)		(168	)

Net Increase in Cash and Cash Equivalents		82			6			38
Cash and Cash Equivalents at Beginning of the Year		40			122			128
Cash and Cash Equivalents at End of the Year	$	122		$	128		$	166
Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	198		$	221		$	235
Income taxes (refunds), net		304			180			(231	)
Non-cash transactions:
Accounts payable related to capital expenditures	$	23		$	23		$	42

See Notes to the Company’s Consolidated Financial Statements

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED MEMBER’S EQUITY

	2006					2007					2008
	Shares		Amount			Shares		Amount			Shares		Amount
	(In millions of dollars and shares)
Preference Stock, none outstanding		—	$	—			—	$	—			—	$	—
Cumulative Preferred Stock, $0.01 par value; authorized 20,000,000 shares, none outstanding		—		—			—		—			—		—
Common Stock, $0.01 par value; authorized 1,000,000,000 shares
Balance, beginning of year		1,000		—			1,000		—			1,000		—
Balance, end of year		1,000		—			1,000		—			1,000		—
Additional Paid-in-Capital
Balance, beginning of year				1,719					1,712					1,712
Contribution to parent				(8	)				—					—
Dividend to parent				—					—					(482	)
Other				1					—					—
Balance, end of year				1,712					1,712					1,230
Retained Earnings (Deficit)
Balance, beginning of year				(1	)				170					346
Net income				271					273					222
Dividend to parent				(100	)				(100	)				(158	)
Cumulative effect of uncertain tax positions standard				—					3					—
Balance, end of year				170					346					410
Total Member’s Equity			$	1,882				$	2,058				$	1,640

See Notes to the Company’s Consolidated Financial Statements

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(1)	Background

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston or the Company) engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston. The Company is an indirect wholly owned subsidiary of CenterPoint Energy, Inc. (CenterPoint Energy), a public utility holding company. At December 31, 2008, the Company had three subsidiaries, CenterPoint Energy Transition Bond Company, LLC, CenterPoint Energy Transition Bond Company II, LLC and CenterPoint Energy Transition Bond Company III, LLC (collectively, the transition bond companies). Each is a special purpose Delaware limited liability company formed for the principal purpose of purchasing and owning transition property, issuing transition bonds and performing activities incidental thereto. For further discussion of the transition bond companies, see Notes 2(e), 2(f), 3(a) and 5.

(2)	Summary of Significant Accounting Policies

(a)	Use of Estimates

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

(b)	Principles of Consolidation

The accounts of the Company and its wholly owned subsidiaries are included in the Company’s consolidated financial statements. All intercompany transactions and balances are eliminated in consolidation.

(c)

Revenues

The Company records revenue for electricity delivery under the accrual method and these revenues are recognized upon delivery to customers. Electricity deliveries not billed by month-end are accrued based on daily supply volumes, applicable rates and analyses reflecting significant historical trends and experience.

(d)	Long-Lived Assets and Intangibles

The Company records property, plant and equipment at historical cost. The Company expenses repair and maintenance costs as incurred. Property, plant and equipment includes the following:

	Weighted Average Useful		December 31,
	Lives (Years)		2007		2008
			(In millions)
Transmission		38	$	1,456	$	1,597
Distribution		26		4,757		4,853
Other		17		780		806
Total				6,993		7,256
Accumulated depreciation				2,602		2,652
Property, plant and equipment, net			$	4,391	$	4,604

The Company periodically evaluates long-lived assets, including property, plant and equipment, and specifically identifiable intangibles, when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted cash flows attributable to the assets, as compared to the carrying value of the assets.

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At December 31, 2007 and 2008, the Company’s asset retirement obligations were $19 million and $17 million, respectively. The decrease in asset retirement obligations in 2008 of $2 million is primarily attributable to the increase in the credit-adjusted risk-free rate used to value the asset retirement obligations as of the end of the period. The decrease in asset retirement obligations results in an increase in removal cost regulatory liabilities as discussed in Note 2(e).

(e)	Regulatory Assets and Liabilities

The Company applies the accounting policies established in Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation” (SFAS No. 71). The following is a list of regulatory assets/liabilities reflected on the Company’s Consolidated Balance Sheets as of December 31, 2007 and 2008:

	December 31,
	2007			2008
	(In millions)
Electric generation-related regulatory assets (1)	$	545		$	3
Securitized regulatory asset (1)		2,131			2,430
Unrecognized equity return		(220	)		(207	)
Unamortized loss on reacquired debt		79			73
Hurricane Ike restoration cost (2)		—			435
Postretirement-related regulatory asset (3)		39			50
Other long-term regulatory assets		47			48
Total regulatory assets (2)		2,621			2,832

Electric generation-related regulatory liabilities (1)		44			—
Estimated removal costs		290			301
Other long-term regulatory liabilities		20			12
Total regulatory liabilities		354			313

Total regulatory assets and liabilities, net	$	2,267		$	2,519

____________

(1)

As discussed in Note 6(b), the Company securitized approximately $483 million of electric generation-related regulatory assets, net, in February 2008.

(2)

Pending review and approval by the Public Utility Commission of Texas (Texas Utility Commission), the Company is not recording a return on its Hurricane Ike restoration costs, see Note 3(a). Other regulatory assets that are not earning a return were not material at December 31, 2007 and 2008.

(3)

The Company has recorded a regulatory asset for the unrecognized costs of its postretirement plans because it has historically recovered and currently recovers postretirement expenses in rates.

The Company recognizes removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2007 and 2008, these removal costs of $290 million and $301 million, respectively, are classified as regulatory liabilities in the Company’s Consolidated Balance Sheets. A portion of the amount of removal costs that relate to asset retirement obligations have been reclassified from a regulatory liability to an asset retirement liability in accordance with Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47).

(f)	Depreciation and Amortization Expense

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. Transition property is being amortized over the expected life of the three series of transition bonds, (12 years, 14 years and 12 years, respectively), based on estimated revenue from transition charges, interest accruals and other expenses. Other amortization expense includes amortization of regulatory assets and other intangibles.

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The following table presents depreciation and amortization expense for 2006, 2007 and 2008:

	Year Ended December 31,
	2006			2007			2008
	(In millions)
Depreciation expense	$	245		$	251		$	256
Amortization of securitized regulatory assets		135			155			183
Other amortization		(1	)		(8	)		21
Total depreciation and amortization	$	379		$	398		$	460

(g)	Allowance for Funds Used During Construction

Allowance for funds used during construction (AFUDC) represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction. Although AFUDC increases both utility plant and earnings, it is realized in cash when the assets are included in rates. AFUDC is capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. During 2006, 2007 and 2008, the Company capitalized AFUDC of $4 million, $10 million and $7 million, respectively.

(h)	Income Taxes

The Company is included in the consolidated income tax returns of CenterPoint Energy. The Company calculates its income tax provision on a separate return basis under a tax sharing agreement with CenterPoint Energy. Pursuant to the tax sharing agreement with CenterPoint Energy, in 2006, the Company received an allocation of CenterPoint Energy’s tax expenses totaling $8 million.

The Company uses the asset and liability method of accounting for deferred income taxes in accordance with SFAS No. 109, “Accounting for Income Taxes”. Deferred income tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. A valuation allowance is established against deferred tax assets for which management believes realization is not considered more likely than not. Investment tax credits were deferred and are being amortized over the estimated lives of the related property. Current federal and certain state income taxes are payable to or receivable from CenterPoint Energy.

Prior to 2007, the Company evaluated uncertain income tax positions and recorded a tax liability for those positions that management believed were probable of an unfavorable outcome and could be reasonably estimated. Effective January 1, 2007, the Company accounts for the tax effects of uncertain income tax positions in accordance with FIN 48, “Accounting for Uncertainty in Income Taxes – an Interpretation of FASB Statement No. 109” (FIN 48). The Company recognizes interest and penalties as a component of income tax expense. For additional information regarding income taxes, see Note 7.

(i)	Accounts Receivable and Allowance for Doubtful Accounts

Accounts and notes receivable, net, are net of an allowance for doubtful accounts of $1 million and $2 million at December 31, 2007 and 2008, respectively. The provision for doubtful accounts in the Company’s Statements of Consolidated Income for 2006, 2007 and 2008 was $(2) million, $1 million and $2 million, respectively.

(j)

Inventory

Inventory consists principally of materials and supplies and is valued at the lower of average cost or market.

(k)	Statements of Consolidated Cash Flows

For purposes of reporting cash flows, the Company considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. In connection with the issuance of transition bonds in October 2001, December 2005 and February 2008, the Company was required to establish restricted cash accounts to collateralize the bonds that were issued in these financing transactions. These restricted cash accounts are not available for withdrawal until the maturity of the bonds. Cash and cash equivalents does not

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include restricted cash of $49 million and $60 million at December 31, 2007 and 2008, respectively, which is included in other current assets in the Company’s Consolidated Balance Sheets. For additional information regarding transition bonds, see Notes 3(b) and 6. Cash and cash equivalents includes $128 million and $166 million at December 31, 2007 and 2008, respectively, that is held by the Company’s transition bond subsidiaries solely to support servicing the transition bonds.

(l)	New Accounting Pronouncements

In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.

In December 2007, the FASB issued SFAS No. 141 (Revised 2007), “Business Combinations” (SFAS No. 141R). SFAS No. 141R will significantly change the accounting for business combinations. Under SFAS No. 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition date fair value with limited exceptions. SFAS No. 141R also includes a substantial number of new disclosure requirements and applies prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. As the provisions of SFAS No. 141R are applied prospectively, the impact to the Company cannot be determined until applicable transactions occur.

In December 2007, the FASB issued SFAS No. 160, “Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No. 51” (SFAS No. 160). SFAS No. 160 establishes new accounting and reporting standards for the noncontrolling interest in a subsidiary and for the deconsolidation of a subsidiary. This accounting standard is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. The Company will adopt SFAS No. 160 as of January 1, 2009. The Company expects that the adoption of SFAS No. 160 will not have a material impact on its financial position, results of operations or cash flows.

(m)	Employee Benefit Plans

Pension Plans

Substantially all of the Company’s employees participate in CenterPoint Energy’s non-contributory qualified defined benefit plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 5% of eligible earnings, which increased from 4% effective January 1, 2009, and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. Certain employees participating in the plan as of December 31, 1998 automatically receive the greater of the accrued benefit calculated under the prior plan formula through 2008 or the cash balance formula.

CenterPoint Energy’s funding policy is to review amounts annually in accordance with applicable regulations in order to achieve adequate funding of projected benefit obligations. Pension expense is allocated to the Company based on covered employees. This calculation is intended to allocate pension costs in the same manner as a separate employer plan. Assets of the plan are not segregated or restricted by CenterPoint Energy’s participating subsidiaries. The Company recognized pension expense of $10 million and $1 million for the years ended December 31, 2006, and 2007, respectively, and pension income of $4 million for the year ended December 31, 2008.

In addition to the pension plan, the Company participates in CenterPoint Energy’s non-qualified benefit restoration plans, which allow participants to receive the benefits to which they would have been entitled under the non-contributory pension plan except for federally mandated limits on qualified plan benefits or on the level of compensation on which qualified plan benefits may be calculated. The expense associated with the non-qualified pension plan was less than $1 million for each of the years ended December 31, 2006, 2007 and 2008.

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Savings Plan

The Company participates in CenterPoint Energy’s qualified savings plan, which includes a cash or deferred arrangement under Section 401(k) of the Internal Revenue Code of 1986, as amended (the Code), and an Employee Stock Ownership Plan (ESOP) under Section 4975(e)(7) of the Code. Under the plan, participating employees may contribute a portion of their compensation, on a pre-tax or after-tax basis, generally up to a maximum of 50%, which increased from 16% in prior years, of compensation. Effective January 1, 2009, the Company matches 100% of the first 6% of each employee’s compensation contributed. The Company previously matched 75% of the first 6% of each employee’s compensation contributed with the potential for an additional discretionary match of up to 50% of the first 6% of each employee’s compensation contributed. The matching contributions are fully vested at all times. CenterPoint Energy allocates to the Company the savings plan benefit expense related to the Company’s employees. Savings plan benefit expense was $12 million for each of the years ended December 31, 2006 and 2007, and $14 million for the year ended December 31, 2008.

Postretirement Benefits

The Company’s employees participate in CenterPoint Energy’s plans which provide certain healthcare and life insurance benefits for retired employees on a contributory and non-contributory basis. Employees become eligible for these benefits if they have met certain age and service requirements at retirement, as defined in the plans. Under plan amendments effective in early 1999, healthcare benefits for future retirees were changed to limit employer contributions for medical coverage. Such benefit costs are accrued over the active service period of employees.

The Company is required to fund a portion of its obligations in accordance with rate orders. The net postretirement benefit cost includes the following components:

	Year Ended December 31,
	2006			2007			2008
	(In millions)
Service cost— benefits earned during the period	$	1		$	1		$	1
Interest cost on projected benefit obligation		16			17			17
Expected return on plan assets		(11	)		(11	)		(11	)
Amortization of transition obligation		6			6			6
Net postretirement benefit cost	$	12		$	13		$	13

The Company used the following assumptions to determine net postretirement benefit costs:

	Year Ended December 31,
	2006			2007			2008
Discount rate		5.70	%		5.85	%		6.40	%
Expected return on plan assets		8.50	%		8.00	%		8.00	%

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

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Following are reconciliations of the Company’s beginning and ending balances of its postretirement benefit plan’s benefit obligation, plan assets and funded status for 2007 and 2008. The measurement dates for plan assets and obligations were December 31, 2007 and 2008.

	Year Ended December 31,
	2007			2008
	(In millions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	294		$	281
Service cost		1			1
Interest cost		17			17
Benefits paid		(17	)		(18	)
Participant contributions		1			1
Medicare drug reimbursement		—			2
Actuarial gain		(15	)		(12	)
Accumulated benefit obligation, end of year	$	281		$	272
Change in Plan Assets
Plan assets, beginning of year	$	138		$	142
Benefits paid		(17	)		(18	)
Employer contributions		9			9
Participant contributions		1			1
Actual investment return (loss)		11			(19	)
Plan assets, end of year	$	142		$	115
Amounts Recognized in Balance Sheets
Other liabilities-benefit obligations	$	(139	)	$	(157	)
Net liability, end of year	$	(139	)	$	(157	)
Actuarial Assumptions
Discount rate		6.40	%		6.90	%
Expected long-term return on assets		8.00	%		8.00	%
Healthcare cost trend rate assumed for the next year		7.00	%		6.50	%
Prescription drug cost trend rate assumed for the next year		13.00	%		12.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		5.50	%		5.50	%
Year that the healthcare rate reaches the ultimate trend rate	2012			2011
Year that the prescription drug rate reaches the ultimate trend rate	2015			2014

The discount rate was determined by reviewing yields on high-quality bonds that receive one of the two highest ratings given by a recognized rating agency and expected duration of obligations specific to the characteristics of CenterPoint Energy’s plans.

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

For measurement purposes, healthcare costs are assumed to increase 6.5% during 2009, after which this rate decreases until reaching the ultimate rate of 5.5% in 2011. Prescription drug costs are assumed to increase 12% in 2009, after which this rate decreases until reaching the ultimate rate of 5.5% in 2014.

The Company does not have amounts recognized in accumulated other comprehensive income related to its postretirement benefit plans as of December 31, 2007 and 2008. Unrecognized costs were recorded as a regulatory asset, because the Company historically and currently recovers postretirement expenses in rates.

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

	1% Increase		1% Decrease
	(In millions)
Effect on the postretirement benefit obligation	$	11	$	(9	)
Effect on total of service and interest cost		1		(1	)

The following table displays the weighted average asset allocations as of December 31, 2007 and 2008 for the Company’s postretirement benefit plans:

	December 31,
	2007			2008
Domestic equity securities		30	%		29	%
International equity securities		11			10
Debt securities		59			61
Total		100	%		100	%

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

As part of the investment strategy discussed above, the Company has adopted and maintains the following asset allocation ranges for its postretirement benefit plans:

Domestic equity securities	25-35	%
International equity securities	5-15	%
Debt securities	55-65	%
Cash	0-2	%

The Company expects to contribute $8 million to its postretirement benefits plan in 2009. The following benefit payments are expected to be paid by the postretirement benefit plan (in millions):

	Postretirement Benefit Plan
	Benefit Payments		Medicare Subsidy Receipts
2009	$	20	$	(2	)
2010		21		(2	)
2011		22		(2	)
2012		23		(2	)
2013		24		(3	)
2014-2018		132		(16	)

Postemployment Benefits

The Company participates in CenterPoint Energy’s plan which provides postemployment benefits for former or inactive employees, their beneficiaries and covered dependents, after employment but before retirement (primarily health care and life insurance benefits for participants in the long-term disability plan). The Company recorded postemployment benefit costs of $2 million in 2006 and postemployment income of $1 million in each of the years ended December 31, 2007 and 2008. Amounts relating to postemployment obligations included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2007 and 2008 were $18 million and $14 million, respectively.

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Other Non-Qualified Plans

The Company participates in CenterPoint Energy’s deferred compensation plans that provide benefits payable to directors, officers and certain key employees or their designated beneficiaries at specified future dates, upon termination, retirement or death. Benefit payments are made from the general assets of the Company. The Company recorded benefit expense relating to these programs of $1 million in each of the years ended December 31, 2006, 2007 and 2008. Amounts relating to deferred compensation plans included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2007 and 2008 were $17 million and $15 million, respectively.

(n)	Other Current Assets and Liabilities

Included in other current assets in the Consolidated Balance Sheets at both December 31, 2007 and 2008 was $49 million and $60 million, respectively, of restricted cash related to the transition bond companies. Included in other current liabilities in the Consolidated Balance Sheets at December 31, 2007 and 2008 was $37 million and $45 million, respectively, of customer deposits.

(3)	Regulatory Matters

(a)	Hurricane Ike

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

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

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

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

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

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(b)	Recovery of True-Up Balance

In March 2004, the Company filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing the Company 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.

The Company 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 the Company from recovering the interest component of the EMCs paid to retail electric providers (REPs); and

•

affirmed the True-Up Order in all other respects.

The Company 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 the Company to recover EMCs paid to Reliant Energy, Inc. (RRI);

•

ordered that the tax normalization issue described below be remanded to the Texas Utility Commission as requested by the Texas Utility Commission; and

•

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

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

In June 2008, the Company petitioned the Texas Supreme Court for review of the court of appeals decision. In its petition, the Company 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 the Company 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 the Company 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) the Company 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.

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

To reflect the impact of the True-Up Order, in 2004 and 2005, the Company recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in the Company’s consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of further review by the Texas Supreme Court, the Company anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts the Company ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-Up Order, but could range from $170 million to $385 million (pre-tax) plus interest subsequent to December 31, 2008.

In the True-Up Order, the Texas Utility Commission reduced the Company’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. CenterPoint Energy believes 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 the Company to pass the tax benefits back to customers without creating normalization violations. In addition, CenterPoint Energy 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 the Company’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 CenterPoint Energy to pay an amount equal to the Company’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny the Company the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on the Company’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review or briefs filed with the Texas Supreme Court, has challenged that order by the court of appeals, though the Texas Supreme Court, if it grants review, will have authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. The Company and CenterPoint Energy will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to the Company in the Texas Utility Commission’s True-Up Order to be recovered either through securitization or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of the Company

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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, the Company 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, the Company 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 the Company 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 the Company to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). The Company 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 the Company’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 the Company to recover through the Rider RCE the costs (approximately $5 million) for a panel appointed by the Texas Utility Commission in connection with the valuation of electric generation assets. Finally, the district court accepted the contention of one party that the CTC should not be allocated to retail customers that have switched to new on-site generation. The Texas Utility Commission and the Company appealed the district court’s judgment to the Texas Third Court of Appeals, and in July 2008, the court of appeals reversed the district court’s judgment in all respects and affirmed the Texas Utility Commission’s order. Two of the appellants have requested further review from the Texas Supreme Court. In March 2009, the Texas Supreme Court requested the parties to file briefs on the merits in their appeals. Review by the Texas Supreme Court is discretionary with that court, and there is no deadline for its action on the appeals. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on its financial condition, results of operations or cash flows.

During the years ended December 31, 2006, 2007 and 2008, the Company recognized approximately $55 million, $42 million and $5 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2006, 2007 and 2008, the Company recognized approximately $13 million, $14 million and $13 million, respectively, of the allowed equity return not previously recognized. As of December 31, 2008, the Company had not recognized an allowed equity return of $207 million on the Company’s true-up balance because such return will be recognized as it is recovered in rates.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, the Company 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. The Company 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 the Company issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

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(c)	Rate Proceedings

In September 2008, the Company filed an application with the Texas Utility Commission requesting an interim update to its wholesale transmission rate. The filing resulted in a revenue requirement increase of $22.5 million over rates then in effect. Approximately 74% will be paid by distribution companies other than the Company. The remaining 26% represents the Company’s share, which cannot be included in rates until 2010 under the terms of the rate freeze implemented in the settlement of the Company’s 2006 rate proceeding. In November 2008, the Texas Utility Commission approved the Company’s request. The interim rates became effective for service on and after November 5, 2008.

(4)	Fair Value Measurements

Effective January 1, 2008, the Company adopted SFAS No. 157, “Fair Value Measurements” (SFAS No. 157), which requires additional disclosures about the Company’s financial assets and liabilities that are measured at fair value. FASB Staff Position No. FAS 157-2 delays the effective date for SFAS No. 157 for nonfinancial assets and liabilities, except for items that are recognized or disclosed at fair value in the financial statements on a recurring basis, to fiscal years, and interim periods within those fiscal years, beginning after November 15, 2008. The Company has elected to defer the adoption of SFAS No. 157 for the measurement of asset retirement obligations until January 1, 2009, as permitted. Beginning in January 2008, assets and liabilities recorded at fair value in the Consolidated Balance Sheet are categorized based upon the level of judgment associated with the inputs used to measure their value. Hierarchical levels, as defined in SFAS No. 157 and directly related to the amount of subjectivity associated with the inputs to fair valuations of these assets and liabilities, are as follows:

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value are investments. At December 31, 2008, the Company held Level 1 investments of $59 million, which were primarily money market funds.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. The Company had no Level 2 assets or liabilities at December 31, 2008.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset. The Company had no Level 3 assets or liabilities at December 31, 2008.

(5)	Related Party Transactions and Major Customers

(a)	Related Party Transactions

The Company participates in a money pool through which it can borrow or invest on a short-term basis. Funding needs are aggregated and external borrowing or investing is based on the net cash position. The net funding requirements of the money pool are expected to be met with borrowings under CenterPoint Energy’s revolving credit facility or the sale of CenterPoint Energy’s commercial paper. The Company had money pool borrowings of $47 million and $8 million at December 31, 2007 and 2008, respectively, which are included in accounts and notes payable—affiliated companies in the Consolidated Balance Sheets. At December 31, 2008, the Company’s money pool borrowings had a weighted average interest rate of 1.541%.

At December 31, 2007 and 2008, the Company had a $750 million note receivable from its parent, which bears interest at the prime rate, 3.25% at December 31, 2008.

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For the years ended December 31, 2006, 2007 and 2008, the Company had net interest income related to affiliate borrowings of $50 million, $49 million and $31 million, respectively.

CenterPoint Energy provides some corporate services to the Company. The costs of services have been charged directly to the Company using methods that management believes are reasonable. These methods include negotiated usage rates, dedicated asset assignment and proportionate corporate formulas based on operating expenses, assets, gross margin, employees and a composite of assets, gross margin and employees. These charges are not necessarily indicative of what would have been incurred had the Company not been an affiliate. Amounts charged to the Company for these services were $112 million, $103 million and $116 million in 2006, 2007 and 2008, respectively, and are included primarily in operation and maintenance expenses.

Pursuant to the tax sharing agreement with CenterPoint Energy, the Company received an allocation of CenterPoint Energy’s tax expense of $8 million for 2006, which was recorded in additional paid-in capital.

In 2006, 2007 and 2008, the Company paid a dividend of $100 million, $100 million and $640 million, respectively.

(b)	Major Customers

During 2006, 2007 and 2008, revenues derived from energy delivery charges provided by the Company to subsidiaries of RRI totaled $737 million, $661 million and $635 million, respectively.

(6)	Short-term Borrowings and Long-term Debt

	December 31, 2007					December 31, 2008
	Long-Term			Current(1)		Long-Term			Current(1)
	(In millions)
Long-term debt:
First mortgage bonds 9.15% due 2021(2)	$	102		$	—	$	102		$	—
General mortgage bonds 5.60% to 6.95% due 2013 to 2033(2)		1,262			—		1,262			—
Pollution control bonds 3.625% to 5.60% due 2012 to 2027(3)		229			—		229			—
Transition Bonds 4.192% to 5.63% due 2008 to 2020		2,101			159		2,381			208
Bank loans due 2012(4)		50			—		251			—
Other		(1	)		—		(1	)		—
Total long-term debt	$	3,743		$	159	$	4,224		$	208

__________

(1)	Includes amounts due or scheduled to be paid within one year of the date noted.

(2)

Excludes $151 million of first mortgage bonds and $527 million of general mortgage bonds that the Company had issued as collateral for long-term debt of CenterPoint Energy, and general mortgage bonds that the Company had issued as collateral for its debt aggregating $229 million at both December 31, 2007 and 2008. Debt issued as collateral is excluded from the financial statements because of the contingent nature of the obligation.

(3)	These series of debt are secured by the Company’s general mortgage bonds.

(4)	Classified as long-term debt because the termination date of the facility under which the funds were borrowed is more than one year beyond the dates referenced in the table.

(a)	Short-term Borrowings

Revolving Credit Facility. In November 2008, the Company entered into a $600 million 364-day credit facility. The credit facility will terminate if bonds are issued to securitize the costs incurred as a result of Hurricane Ike and if those bonds are issued prior to the November 24, 2009 expiration of the facility. The Company expects to seek legislative and regulatory approval for the issuance of such bonds during 2009.

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The 364-day credit facility is secured by a pledge of $600 million of general mortgage bonds issued by the Company. Borrowing costs for London Interbank Offered Rate (LIBOR)-based loans will be at a margin of 2.25 percent above LIBOR rates, based on the Company’s current ratings. In addition, the Company will pay lenders, based on current ratings, a per annum commitment fee of 0.5 percent for their commitments under the facility and a quarterly duration fee of 0.75 percent on the average amount of outstanding borrowings during the quarter. The spread to LIBOR and the commitment fee fluctuate based on the borrower’s credit rating. The facility contains covenants, including a debt (excluding transition and other securitization bonds) to total capitalization covenant. As of December 31, 2008, there were no borrowings outstanding under the $600 million credit facility and the Company was in compliance with all debt covenants.

(b)	Long-term Debt

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

Revolving Credit Facility. The Company’s $289 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on the Company’s current credit ratings. The facility contains a debt (excluding transition and other securitization bonds) to total capitalization covenant. Under the credit facility, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating.

As of December 31, 2007 and 2008, the Company had $50 million and $251 million of borrowings, respectively, under this credit facility. In addition, as of both December 31, 2007 and 2008, the Company had approximately $4 million of outstanding letters of credit under this credit facility. The Company was in compliance with all debt covenants as of December 31, 2008.

Transition Bonds. Pursuant to a financing order issued by the Texas Utility Commission in September 2007, in February 2008 a subsidiary of the Company issued approximately $488 million in transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Scheduled final payment dates are February 2017 and February 2020. Through issuance of the transition bonds, the Company securitized transition property of approximately $483 million representing the remaining balance of the CTC less an environmental refund as reduced by the fuel reconciliation settlement amount. See Note 3(b) for further discussion.

Maturities. The Company’s maturities of long-term debt and scheduled payments on transition bonds are $208 million in 2009, $221 million in 2010, $240 million in 2011, $559 million in 2012 and $733 million in 2013.

Liens. As of December 31, 2008, the Company’s assets were subject to liens securing approximately $253 million of first mortgage bonds. Sinking or improvement fund and replacement fund requirements on the first mortgage bonds may be satisfied by certification of property additions. Sinking fund and replacement fund requirements for 2006, 2007 and 2008 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2009 is approximately $170 million, and the sinking fund requirement to be satisfied in 2009 is approximately $3 million. The Company expects to meet these 2009 obligations by certification of property additions. As of December 31, 2008, the Company’s assets were also subject to liens securing approximately $2.6 billion of general mortgage bonds which are junior to the liens of the first mortgage bonds.

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(7)	Income Taxes

The components of the Company’s income tax expense (benefit) were as follows:

	Year Ended December 31,
	2006			2007			2008
	(In millions)
Current:
Federal	$	208		$	199		$	(236	)
State		—			—			10
Total current		208			199			(226	)
Deferred:
Federal		(76	)		(73	)		345
State		—			—			2
Total deferred		(76	)		(73	)		347
Income tax expense	$	132		$	126		$	121

A reconciliation of the federal statutory income tax rate to the effective income tax rate is as follows:

	Year Ended December 31,
	2006			2007			2008
	(In millions)
Income before income taxes	$	403		$	399		$	343
Federal statutory rate		35	%		35	%		35	%
Income taxes at statutory rate		141			139			120
Net addition (reduction) in taxes resulting from:
State income taxes (benefit), net of valuation allowance and federal income tax		—			—			8
Amortization of investment tax credit		(7	)		(7	)		(7	)
Other, net		(2	)		(6	)		—
Total		(9	)		(13	)		1
Income tax expense	$	132		$	126		$	121
Effective income tax rate		32.7	%		31.6	%		35.4	%

Changes in the Texas State Franchise Tax Law (Texas margin tax) resulted in classifying Texas margin tax of approximately $8 million, net of federal income tax effect, as income tax expense in 2008.

The tax effects of temporary differences that give rise to significant portions of deferred tax assets and liabilities were as follows:

	December 31,
	2007		2008
	(In millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	—	$	1
Non-current:
Employee benefits		74		84
Other		35		18
Total non-current deferred tax assets		109		102
Total deferred tax assets		109		103
Deferred tax liabilities:
Non-current:
Depreciation		463		697
Regulatory assets, net		826		910
Other		9		1
Total deferred tax liabilities		1,298		1,608
Accumulated deferred income taxes, net	$	1,189	$	1,505

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Uncertain Income Tax Positions. The Company adopted the provisions of FIN 48 on January 1, 2007. As a result of the adoption of FIN 48, the Company recognized a decrease of approximately $3 million in the liability for unrecognized tax benefits, which was accounted for as an increase to the January 1, 2007 retained earnings. A reconciliation of the change in unrecognized tax benefits for 2007 and 2008, included in other long-term liabilities in the Consolidated Balance Sheets, is as follows (in millions):

	December 31,
	2007			2008
Balance, beginning of year	$	70		$	92
Tax Positions related to prior years:
Additions		30			16
Reductions		(12	)		(1	)
Tax Positions related to current year:
Additions		4			16
Balance, end of year	$	92		$	123

The Company has approximately $8 million and $11 million of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate for 2007 and 2008, respectively. The Company recognizes interest and penalties as a component of income tax expense. The Company recognized approximately $5 million and $7 million of interest on uncertain income tax positions during 2007 and 2008, respectively. The Company accrued $7 million and $14 million of interest on uncertain income tax positions at December 31, 2007 and 2008, respectively. The Company does not expect the amount of unrecognized tax benefits to change significantly over the next 12 months.

Tax Audits and Settlements. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through the 2003 tax year and the IRS is currently at various stages of the examination process for tax years 2004 through 2007. The Company has considered the effects of these examinations in its accrual for settled issues and liability for uncertain income tax positions as of December 31, 2008.

(8)	Commitments and Contingencies

(a)	Lease Commitments

The Company currently has no further obligations under non-cancelable long-term operating leases for the years 2009 to 2013. Total lease expense for all operating leases was approximately $5 million, $4 million and $5 million for the years ended December 31, 2006, 2007 and 2008, respectively.

(b)	Legal and Environmental Matters

Legal Matters

RRI Indemnified Litigation

The Company, CenterPoint Energy or their predecessor, Reliant Energy, Incorporated (Reliant Energy), and certain of their former subsidiaries are named as defendants in several lawsuits described below. Under a master separation agreement between CenterPoint Energy and Reliant Energy, Inc. (formerly Reliant Resources, Inc.) (RRI), CenterPoint Energy and its subsidiaries are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of the lawsuits described below under “Gas Market Manipulation Cases” and “Electricity Market Manipulation Cases.” Pursuant to the indemnification obligation, RRI is defending the Company and its subsidiaries to the extent named in these lawsuits. Although the ultimate outcome of these matters cannot be predicted at this time, the Company has not considered it necessary to establish reserves related to this litigation.

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Gas Market Manipulation Cases. A large number of lawsuits were filed against numerous gas market participants in a number of federal and western state courts in connection with the operation of the natural gas markets in 2000-2001. CenterPoint Energy’s former affiliate, RRI, was a participant in gas trading in the California and Western markets. These lawsuits, many of which have been filed as class actions, allege violations of state and federal antitrust laws. Plaintiffs in these lawsuits are seeking a variety of forms of relief, including, among others, recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages, full consideration damages and attorneys’ fees. CenterPoint Energy and/or Reliant Energy were named in approximately 30 of these lawsuits, which were instituted between 2003 and 2007. In October 2006, RRI reached a settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the other gas cases consolidated in state court in California, the Court of Appeals found that CenterPoint Energy was not a successor to the liabilities of a subsidiary of RRI, and CenterPoint Energy was dismissed from these suits in April 2008. In the Nevada federal litigation, three of the complaints were dismissed based on defendants’ filed rate doctrine defense, but the Ninth Circuit Court of Appeals reversed those dismissals and remanded the cases back to the district court for further proceedings. In July 2008, the plaintiffs in four of the federal court cases agreed to dismiss CenterPoint Energy from those cases. In August 2008, the plaintiffs in five additional cases also agreed to dismiss CenterPoint Energy from those cases, but one of these plaintiffs has moved to amend its complaint to add CenterPoint Energy Services, Inc., an indirect subsidiary of CenterPoint Energy, as a defendant in that case. As a result, CenterPoint Energy remains a party in only two remaining gas market manipulation cases, one pending in Nevada state court in Clark County and one in federal district court in Nevada. CenterPoint Energy believes it is not a proper defendant in the remaining cases and will continue to pursue dismissal from those cases.

Electricity Market Manipulation Cases. A large number of lawsuits were filed against numerous market participants in connection with the operation of the California electricity markets in 2000-2001. CenterPoint Energy’s former affiliate, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally. CenterPoint Energy was named as a defendant in certain of these suits. These lawsuits, many of which were filed as class actions and which were based on a number of legal theories, have all been resolved. In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001, including the claims made by plaintiffs in the suits against RRI naming CenterPoint Energy. The settlement was approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases were pending. An appeal by two parties to the California Court of Appeals was denied with no further appeal sought. A party in the FERC proceedings sought review of the FERC’s order approving the settlement in the Ninth Circuit Court of Appeals, but in December 2008, that party voluntarily withdrew its petition for review, and the settlement is now final. The Company and CenterPoint Energy are not parties to the settlement, but may rely on the settlement as a defense to any claims.

Environmental Matters

Asbestos. Some facilities owned by CenterPoint Energy contain or have contained asbestos insulation and other asbestos-containing materials. CenterPoint Energy or its subsidiaries, including the Company, 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 CenterPoint Energy or the Company, but most existing claims relate to facilities previously owned by CenterPoint Energy or the Company. CenterPoint Energy anticipates that additional claims like those received may be asserted in the future. In 2004, CenterPoint Energy sold its 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 CenterPoint Energy 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 CenterPoint Energy has agreed to continue to defend such claims to the extent they are covered by insurance maintained by CenterPoint Energy, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, CenterPoint Energy intends to continue vigorously contesting claims that it does not consider to have merit and the Company does not expect, based on its experience to date, these matters, either

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individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a potentially responsible party in connection with sites found to require remediation due to the presence of environmental contaminants. In addition, the Company has been named from time to time as a defendant in litigation related to such sites. Although the ultimate outcome of such matters cannot be predicted at this time, the Company does not expect, based on its experience to date, these matters, either individually or in the aggregate, to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

Other Proceedings

The Company is involved in other legal, environmental, tax and regulatory proceedings before various courts, regulatory commissions and governmental agencies regarding matters arising in the ordinary course of business. Some of these proceedings involve substantial amounts. The Company regularly analyzes current information and, as necessary, provides accruals for probable liabilities on the eventual disposition of these matters. The Company does not expect the disposition of these matters to have a material adverse effect on the Company’s financial condition, results of operations or cash flows.

(9)	Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents, short-term borrowings and the $750 million notes receivable from the Company’s parent are estimated to be equivalent to carrying amounts and have been excluded from the table below.

	December 31, 2007				December 31, 2008
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
	(In millions)
Financial liabilities:
Long-term debt (including $151 million of long-term notes payable to parent)	$	4,052	$	4,083	$	4,582	$	4,424

(10)	Unaudited Quarterly Information

Summarized quarterly financial data is as follows:

	Year Ended December 31, 2007
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions)
Revenues	$	406	$	465	$	528	$	438
Operating income		104		157		196		104
Net income		41		77		105		50

	Year Ended December 31, 2008
	First Quarter		Second Quarter		Third Quarter		Fourth Quarter
	(In millions)
Revenues	$	409	$	510	$	552	$	445
Operating income		91		164		202		88
Net income		26		72		98		26

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Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A(T). Controls and Procedures

Disclosure Controls and Procedures

In accordance with Exchange Act Rules 13a-15 and 15d-15, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal financial officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures were effective as of December 31, 2008 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such information is accumulated and communicated to our management, including our principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding disclosure.

There has been no change in our internal controls over financial reporting that occurred during the three months ended December 31, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

Item 9B. Other Information

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

The information called for by Item 10 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 11. Executive Compensation

The information called for by Item 11 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

The information called for by Item 12 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

Item 13. Certain Relationships and Related Transactions, and Director Independence

The information called for by Item 13 is omitted pursuant to Instruction I(2) to Form 10-K (Omission of Information by Certain Wholly Owned Subsidiaries).

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Item 14. Principal Accounting Fees and Services

Aggregate fees billed to the Company during the fiscal years ending December 31, 2007 and 2008 by its principal accounting firm, Deloitte & Touche LLP, are set forth below.

	Year Ended December 31,
	2007		2008
Audit fees (1)	$	476,050	$	679,550
Audit-related fees (2)		96,000		105,000
Total audit and audit-related fees		572,050		784,550
Tax fees		—		—
All other fees		—		—
Total fees	$	572,050	$	784,550

__________

(1)	For 2008 and 2007, amounts include fees for services provided by the principal accounting firm relating to the integrated audit of financial statements and internal control over financial reporting, statutory audits, attest services, and regulatory filings.

(2)	For 2008 and 2007, includes fees for consultations concerning financial accounting and reporting standards and various agreed-upon or expanded procedures related to accounting records to comply with financial accounting or regulatory reporting matters.

The Company is not required to have, and does not have, an audit committee.

PART IV

Item 15. Exhibits and Financial Statement Schedules

(a)(1) Financial Statements.
Report of Independent Registered Public Accounting Firm	32
Statements of Consolidated Income for the Three Years Ended December 31, 2008	34
Consolidated Balance Sheets at December 31, 2007 and 2008	35
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2008	36
Statements of Consolidated Member’s Equity for the Three Years Ended December 31, 2008	37
Notes to Consolidated Financial Statements	38

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2008.

Report of Independent Registered Public Accounting Firm	58
II— Qualifying Valuation Accounts	59

The following schedules are omitted because of the absence of the conditions under which they are required or because the required information is included in the financial statements:

I, III, IV and V.

(a)(3) Exhibits.

See Index of Exhibits beginning on page 61.

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REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Member of

CenterPoint Energy Houston Electric, LLC

Houston, Texas

We have audited the consolidated financial statements of CenterPoint Energy Houston Electric, LLC and subsidiaries (the “Company”, an indirect wholly owned subsidiary of CenterPoint Energy, Inc.) as of December 31, 2008 and 2007, and for each of the three years in the period ended December 31, 2008, and have issued our report thereon dated March 11, 2009; such report is included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Company listed in the index at Item 15(a)(2). This consolidated financial statement schedule is the responsibility of the Company's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

Houston, Texas

March 11, 2009

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

SCHEDULE II — QUALIFYING VALUATION ACCOUNTS

For the Three Years Ended December 31, 2008

(In Millions)

Column A	Column B		Column C			Column D		Column E
Description	Balance At Beginning of Period		Additions Charged to Income			Deductions From Reserves(1)		Balance At End Of Period
Year Ended December 31, 2008:
Accumulated provisions:
Uncollectible accounts receivable	$	1	$	2		$	1	$	2
Year Ended December 31, 2007:
Accumulated provisions:
Uncollectible accounts receivable	$	1	$	1		$	1	$	1
Year Ended December 31, 2006:
Accumulated provisions:
Uncollectible accounts receivable	$	5	$	(2	)	$	2	$	1

__________

(1)	Deductions from reserves represent losses or expenses for which the respective reserves were created. In the case of the uncollectible accounts reserve, such deductions are net of recoveries of amounts previously written off.

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SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, the State of Texas, on the 11th day of March, 2009.


	CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC
	(Registrant)

By:	/s/ DAVID M. MCCLANAHAN
	David M. McClanahan
	Manager

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities indicated on March 11, 2009.

Signature		Title

/s/ DAVID M. MCCLANAHAN		Manager and Chairman
(David M. McClanahan)		(Principal Executive Officer)

/s/ GARY L. WHITLOCK		Executive Vice President and Chief Financial Officer
(Gary L. Whitlock)		(Principal Financial Officer)

/s/ WALTER L. FITZGERALD		Senior Vice President and Chief Accounting Officer
(Walter L. Fitzgerald)		(Principal Accounting Officer)

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CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC

EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K

For Fiscal Year Ended December 31, 2008

INDEX OF EXHIBITS

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3(a)	Articles of Conversion of REI	Form 8-K dated August 31, 2002 filed with the SEC on September 3, 2002	1-3187	3(a)
3(b)	Articles of Organization of CenterPoint Energy Houston Electric, LLC (“CenterPoint Houston”)	Form 8-K dated August 31, 2002 filed with the SEC on September 3, 2002	1-3187	3(b)
3(c)	Limited Liability Company Regulations of CenterPoint Houston	Form 8-K dated August 31, 2002 Filed with the SEC on September 3, 2002	1-3187	3(c)
4(a)(1)	Mortgage and Deed of Trust, dated November 1, 1944 between Houston Lighting and Power Company (“HL&P”) and Chase Bank of Texas, National Association (formerly, South Texas Commercial National Bank of Houston), as Trustee, as amended and supplemented by 20 Supplemental Indentures thereto	HL&P’s Form S-7 filed on August 25, 1977	2-59748	2(b)
4(a)(2)	Twenty-First through Fiftieth Supplemental Indentures to Exhibit 4(a)(1)	HL&P’s Form 10-K for the year ended December 31, 1989	1-3187	4(a)(2)
4(a)(3)	Fifty-First Supplemental Indenture to Exhibit 4(a)(1) dated as of March 25, 1991	HL&P’s Form 10-Q for the quarter ended June 30, 1991	1-3187	4(a)
4(a)(4)	Fifty-Second through Fifty- Fifth Supplemental Indentures to Exhibit 4(a)(1) each dated as of March 1, 1992	HL&P’s Form 10-Q for the quarter ended March 31, 1992	1-3187	4
4(a)(5)	Fifty-Sixth and Fifty-Seventh Supplemental Indentures to Exhibit 4(a)(1) each dated as of October 1, 1992	HL&P’s Form 10-Q for the quarter ended September 30, 1992	1-3187	4
4(a)(6)	Fifty-Eighth and Fifty-Ninth Supplemental Indentures to Exhibit 4(a)(1) each dated as of March 1, 1993	HL&P’s Form 10-Q for the quarter ended March 31, 1993	1-3187	4
4(a)(7)	Sixtieth Supplemental Indenture to Exhibit 4(a)(1) dated as of July 1, 1993	HL&P’s Form 10-Q for the quarter ended June 30, 1993	1-3187	4
4(a)(8)	Sixty-First through Sixty-Third Supplemental Indentures to Exhibit 4(a)(1) each dated as of December 1, 1993	HL&P’s Form 10-K for the year ended December 31, 1993	1-3187	4(a)(8)

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4(a)(9)	Sixty-Fourth and Sixty-Fifth Supplemental Indentures to Exhibit 4(a)(1) each dated as of July 1, 1995	HL&P’s Form 10-K for the year ended December 31, 1995	1-3187	4(a)(9)
4(b)(1)	General Mortgage Indenture, dated as of October 10, 2002, between CenterPoint Energy Houston Electric, LLC and JPMorgan Chase Bank, as Trustee	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(1)
4(b)(2)	Second Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(3)
4(b)(3)	Third Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(4)
4(b)(4)	Fourth Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(5)
4(b)(5)	Fifth Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(6)
4(b)(6)	Sixth Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(7)
4(b)(7)	Seventh Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(8)
4(b)(8)	Eighth Supplemental Indenture to Exhibit 4(b)(1), dated as of October 10, 2002	Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2002	1-3187	4(j)(9)
4(b)(9)	Officer’s Certificates dated October 10, 2002, setting forth the form, terms and provisions of the First through Eighth Series of General Mortgage Bonds	CenterPoint Energy, Inc.’s (“CNP’s”) Form 10-K for the year ended December 31, 2003	1-31447	4(c)(10)
4(b)(10)	Ninth Supplemental Indenture to Exhibit 4(b)(1), dated as of November 12, 2002	CNP’s Form 10-K for the year ended December 31, 2002	1-31447	4(e)(10)
4(b)(11)	Officer’s Certificate dated November 12, 2002 setting forth the form, terms and provisions of the Ninth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2003	1-31447	4(e)(12)
4(b)(12)	Tenth Supplemental Indenture to Exhibit 4(b)(1), dated as of March 18, 2003	Form 8-K dated March 13, 2003	1-3187	4.1

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Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4(b)(13)	Officer’s Certificate dated March 18, 2003 setting forth the form, terms and provisions of the Tenth Series and Eleventh Series of General Mortgage Bonds	Form 8-K dated March 13, 2003	1-3187	4.2
4(b)(14)	Eleventh Supplemental Indenture to Exhibit 4(b)(1), dated as of May 23, 2003	Form 8-K dated May 16, 2003	1-3187	4.1
4(b)(15)	Officer’s Certificate dated May 23, 2003 setting forth the form, terms and provisions of the Twelfth Series of General Mortgage Bonds	Form 8-K dated May 16, 2003	1-3187	4.2
4(b)(16)	Twelfth Supplemental Indenture to Exhibit 4(b)(1), dated as of September 9, 2003	Form 8-K dated September 9, 2003	1-3187	4.2
4(b)(17)	Officer’s Certificate dated September 9, 2003 setting forth the form, terms and provisions of the Thirteenth Series of General Mortgage Bonds	Form 8-K dated September 9, 2003	1-3187	4.3
4(b)(18)	Thirteenth Supplemental Indenture to Exhibit 4(b)(1), dated as of February 6, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(16)
4(b)(19)	Officer’s Certificate dated February 6, 2004 setting forth the form, terms and provisions of the Fourteenth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(17)
4(b)(20)	Fourteenth Supplemental Indenture to Exhibit 4(b)(1), dated as of February 11, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(18)
4(b)(21)	Officer’s Certificate dated February 11, 2004 setting forth the form, terms and provisions of the Fifteenth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(19)
4(b)(22)	Fifteenth Supplemental Indenture to Exhibit 4(b)(1), dated as of March 31, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(20)
4(b)(23)	Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Sixteenth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(21)
4(b)(24)	Sixteenth Supplemental Indenture to Exhibit 4(b)(1), dated as of March 31, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(22)
4(b)(25)	Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Seventeenth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(23)
4(b)(26)	Seventeenth Supplemental Indenture to Exhibit 4(b)(1), dated as of March 31, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(24)

Table of Contents

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
4(b)(27)	Officer’s Certificate dated March 31, 2004 setting forth the form, terms and provisions of the Eighteenth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(25)
4(b)(28)	Nineteenth Supplemental Indenture to Exhibit 4(b)(1), dated as of November 26, 2008	CNP’s Form 8-K dated November 25, 2008	1-31447	4.2
4(b)(29)	Officer’s Certificate date November 26, 2008 setting forth the form, terms and provisions of the Twentieth Series of General Mortgage Bonds	CNP’s Form 8-K dated November 25, 2008	1-31447	4.3
4(b)(30)	Twentieth Supplemental Indenture to Exhibit 4(b)(1), dated as of December 9, 2008	Form 8-K dated January 6, 2009	1-3187	4.2
4(b)(31)	Twenty-First Supplemental Indenture to Exhibit 4(b)(1), dated as of January 9, 2009	CNP’s Form 10-K for the year ended December 31, 2008	1-31447	4(e)(31)
4(b)(32)	Officer’s Certificate date January 20, 2009 setting forth the form, terms and provisions of the Twenty-First Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2008	1-31447	4(e)(32)
4(c)(1)	$300,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007 among CenterPoint Houston, as Borrower, and the banks named therein	CNP’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4(c)(2)	First Amendment to Exhibit 4(c)(1), dated as of November 18, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CNP’s Form 8-K dated November 18, 2008	1-31447	4.2
4(d)	$600,000,000 Credit Agreement dated as of November 25, 2008, among CenterPoint Houston, as Borrower, and the banks named therein	CNP’s Form 8-K dated November 25, 2008	1-31447	4.1

Table of Contents

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, the Company has not filed as exhibits to this Form 10-K certain long-term debt instruments, including indentures, under which the total amount of securities authorized does not exceed 10% of the total assets of the Company and its subsidiaries on a consolidated basis. The Company hereby agrees to furnish a copy of any such instrument to the SEC upon request.

Exhibit Number	Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
10	City of Houston Franchise Ordinance	CNP’s Form 10-Q for the quarter ended June 30, 2005	1-31447	10.1
+12	Computation of Ratios of Earnings to Fixed Charges
+23	Consent of Deloitte & Touche LLP
+31.1	Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
+31.2	Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
+32.1	Section 1350 Certification of David M. McClanahan
+32.2	Section 1350 Certification of Gary L. Whitlock