SEC Filing | CenterPoint Energy, Inc.,

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

(Mark One)


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

For the fiscal year ended December 31, 2007


o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 1-3187

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 o No þ

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes o No þ

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein and will not be contained, to the best of 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. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer 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 Act).Yes o No þ

The aggregate market value of the common equity held by non-affiliates as of June 30, 2007: None

TABLE OF CONTENTS


		Page
	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		11
Item 1B.	Unresolved Staff Comments		17
Item 2.	Properties		17
Item 3.	Legal Proceedings		17
Item 4.	Submission of Matters to a Vote of Security Holders		17

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		17
Item 6.	Selected Financial Data		18
Item 7.	Management’s Narrative Analysis of Results of Operations		18
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk		28
Item 8.	Financial Statements and Supplementary Data		29
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		51
Item 9A(T).	Controls and Procedures		51
Item 9B.	Other Information		52

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		52
Item 11.	Executive Compensation		52
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		52
Item 13.	Certain Relationships and Related Transactions, and Director Independence		52
Item 14.	Principal Accounting Fees and Services		52

	PART IV
Item 15.	Exhibits and Financial Statement Schedules		53
Computation of Ratios of Earnings to Fixed Charges
Rule 13a-14(a)/15d-14(a) Certification of David M. McClanahan
Rule 13a-14(a)/15d-14(a) Certification of Gary L. Whitlock
Section 1350 Certification of David M. McClanahan
Section 1350 Certification of Gary L. Whitlock

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 2005, 2006 and 2007.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING INFORMATION

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

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

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

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

PART I

Item 1. Business

OUR BUSINESS

Overview

We provide electric transmission and distribution services to retail electric providers (REPs) serving approximately 2.0 million metered customers in a 5,000-square mile area of the Texas Gulf Coast that has a population of approximately 5.5 million people and includes Houston. 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 integrated electric utilities operating within Texas. Pursuant to that legislation, integrated electric utilities operating within the Electric Reliability Council of Texas, Inc. (ERCOT) were required to separate their integrated operations into separate retail sales, power generation and transmission and distribution companies. The legislation also required that the prices for wholesale generation and retail electric sales be unregulated, but services by companies providing transmission and distribution service, such as 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 the control area managed by ERCOT. We provide transmission services under tariffs approved by the Texas Utility Commission.

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 may be reviewed only through rate cases conducted before 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, a portion of the eastern part of the state bordering Louisiana and the area in and around El Paso. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. The ERCOT market includes an aggregate net generating capacity of approximately 72,000 megawatts (MW). There are only limited direct current interconnections between the ERCOT market and other power markets in the United States and Mexico.

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

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 recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and in certain other respects.

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; and

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

We and two other parties filed motions for rehearing with the court of appeals. In the event that the motions for rehearing are not resolved in a manner favorable to us, we intend to seek further review by the Texas Supreme Court. Although we 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 further appeals, we can provide no assurance as to the ultimate rulings by the courts on the issues to be considered in the various appeals or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005 we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of the pending motions for rehearing or on further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts 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 $130 million to $350 million, plus interest subsequent to December 31, 2007.

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 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. CenterPoint Energy subsequently requested a Private Letter Ruling (PLR) asking the IRS whether the Texas Utility Commission’s order reducing our stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations. In that ruling, which was received in August 2007, the IRS concluded that such reductions would cause normalization violations with respect to the ADITC and EDFIT. As in a similar PLR issued in May 2006 to another Texas utility, the IRS did not reference its proposed regulations.

The district court affirmed the Texas Utility Commission’s ruling on the tax normalization issue, but in response to a request from the Texas Utility Commission, the court of appeals ordered that the tax normalization issue be remanded for further consideration. If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require 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. However, 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 the issuance of transition bonds 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 $620 million. Effective September 13, 2005, the return on the CTC portion of the true-up balance is included in our tariff-based revenues.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the new rule discussed below. Second, the district court reversed the Texas Utility Commission’s ruling that allows 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 disagree with the district court’s conclusions and, in May 2006, appealed the judgment to the Texas Third Court of Appeals, and if required, we plan to seek further review from the Texas Supreme Court. All briefs in the appeal have been filed, and oral arguments were held in December 2006. The ultimate outcome of this matter cannot be predicted at this time. However, we do not expect the disposition of this matter to have a material adverse effect on our financial condition, results of operations or cash flows.

In June 2006, the Texas Utility Commission adopted the revised rule governing the carrying charges on unrecovered CTC balances as recommended by its staff (Staff). The rule, which applies to us, reduced the allowed interest rate on the unrecovered CTC balance prospectively from 11.075% to a weighted average cost of capital of 8.06%. The annualized impact on operating income is a reduction of approximately $18 million per year for the first year with lesser impacts in subsequent years. In July 2006, we made a compliance filing necessary to implement the rule changes effective August 1, 2006.

During the years ended December 31, 2005, 2006 and 2007, we recognized approximately $19 million, $55 million and $42 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2005, 2006 and 2007, we recognized approximately $1 million, $13 million and $14 million, respectively, of the allowed equity return not previously recorded. As of December 31, 2007, we have not recorded an allowed equity return of $220 million on 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, after taking into account the environmental refund and the fuel reconciliation settlement amounts discussed below. 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, a new special purpose subsidiary of ours issued approximately $488 million of transition bonds pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

Refund of Environmental Retrofit Costs

The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to our generation assets. The True-Up Order required us to provide evidence by January 31, 2007 that the entire $699 million was actually spent by December 31, 2006 on environmental programs and provided for the Texas Utility Commission to determine the appropriate manner to return to customers any unused portion of these funds, including interest on the funds and on stranded costs attributable to the environmental costs portion of the stranded costs recovery. In January 2007, the successor in interest to our generation assets advised that, as of December 31, 2006, it had spent only approximately $664 million. On January 31, 2007, we made the required filing with the Texas Utility Commission, identifying approximately $35 million in unspent funds to be refunded to customers along with approximately $7 million of interest and requesting permission to refund these amounts through a reduction of the CTC. Such amounts were recorded as regulatory liabilities as of December 31, 2006. In July 2007, we, the Staff and the other parties filed a settlement agreement in which it was agreed that the total amount of the refund, including all principal and interest, was $45 million as of May 31, 2007, that interest would continue to accrue after May 31, 2007 on any unrefunded balance at a rate of 5.4519% per year and that the refund should be used to offset the principal amount proposed in our application to securitize the CTC and other amounts. The offset occurred in connection with the approximately $488 million of transition bonds issued in February 2008. In August 2007, the Texas Utility Commission issued a final order consistent with the terms of that settlement agreement. As of December 31, 2007, we had recorded a regulatory liability of $46 million related to this matter.

Final Fuel Reconciliation

The results of the Texas Utility Commission’s final decision related to our final fuel reconciliation were a component of the True-Up Order. We appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation in 2003 plus interest of $10 million. That decision was upheld by a Travis County district court and affirmed by the Texas Third Court of Appeals. Although we filed an appeal with the Texas Supreme Court, in February 2007 we asked the Texas Supreme Court to hold that appeal in abeyance pending consideration by the Texas Utility Commission of a tentative settlement reached by the parties. In October 2007, the Texas Utility Commission issued a final order consistent with the settlement, and the Texas Supreme Court ultimately vacated the lower court decisions. The settlement allows us recovery of $12.5 million plus interest from January 2002. As a result of the settlement, we recorded a regulatory asset of $17 million in 2007.

Customers

We serve nearly all of the Houston/Galveston metropolitan area. Our customers consist of 74 REPs, which sell electricity to approximately 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 62%, 56% and 51%

of our transmission and distribution revenues in 2005, 2006 and 2007, respectively. Our billed receivables balance from REPs as of December 31, 2007 was $141 million. Approximately 48% of this amount was owed by subsidiaries of RRI. 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)

We are pursuing development and possible deployment of an advanced metering system (AMS) and electric distribution grid automation strategy that involves the implementation of an “Intelligent Grid” which would make use of our lines and other facilities to provide on-demand data and information about electricity usage and the status of facilities on our system. Although this technology is still in the developmental stage, we believe we have the potential to enable customers of the REPs to better monitor and control their usage of electricity as well as offer a significant improvement in metering, grid planning, operations and maintenance of 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. In May 2007, the Texas Utility Commission issued rules establishing minimum functionality requirements for an AMS and a surcharge mechanism to enable timely recovery of the costs of implementation. To date, we have deployed approximately 10,000 advanced meters and utilized broadband over power line technology as part of a limited deployment to help in proving the technology and in validating its potential benefits prior to a full-scale implementation. We would be required to file our deployment plan for approval by the Texas Utility Commission prior to full scale implementation 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 is derived from rates that we collect from each REP based on the amount of electricity we distribute 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 of our real and tangible properties, 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.

mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2007. However, we have contractually agreed that we will not issue additional first mortgage bonds, subject to certain exceptions.

Electric Lines — Overhead. As of December 31, 2007, we owned 27,421 pole miles of overhead distribution lines and 3,738 circuit miles of overhead transmission lines, including 424 circuit miles operated at 69,000 volts, 2,098 circuit miles operated at 138,000 volts and 1,216 circuit miles operated at 345,000 volts.

Electric Lines — Underground. As of December 31, 2007, we owned 18,955 circuit miles of underground distribution lines and 28.4 circuit miles of underground transmission lines, including 4.5 circuit miles operated at 69,000 volts and 23.9 circuit miles operated at 138,000 volts.

Substations. As of December 31, 2007, we owned 229 major substation sites having total installed rated transformer capacity of 50,586 megavolt amperes.

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 Policy Act of 2005 (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 FERC oversight, for all owners, operators and users of the bulk power system (Electric Entities). The ERO and the FERC have authority to impose fines and other sanctions on Electric Entities that fail to comply with the standards. The FERC has approved the delegation by the NERC of authority for reliability in ERCOT to the TRE. 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 imposed by the Texas electric restructuring law, a nuclear decommissioning charge associated with decommissioning the South Texas nuclear generating facility, transition charges associated with securitization of regulatory assets and securitization of stranded costs, a competition transition charge for collection of the true-up balance not securitized and a rate case expense charge.

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

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 and the implementation of charges associated with securitizations. 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.

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial actions, and the issuance of orders enjoining future operations. Certain environmental statutes impose strict, joint and several liability for costs required to clean up and restore sites where hazardous substances have been disposed or otherwise released. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

The trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. We try to anticipate future regulatory requirements that might be imposed and plan accordingly to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

Based on current regulatory requirements and interpretations, we do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position, results of operations or cash flows. In addition, we believe that our current environmental remediation activities will not materially interrupt or diminish our operational ability. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs. The following is a discussion of all material environmental and safety laws and regulations that relate to our operations. We believe that we are in substantial compliance with all of these environmental laws and regulations.

Global Climate Change

In recent years, there has been increasing public debate regarding the potential impact on global climate change by various “greenhouse gases” such as carbon dioxide, a byproduct of burning fossil fuels, and methane. 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. It is too early to determine whether, and in what form, a regulatory scheme regarding greenhouse gas emissions will be adopted or what specific impacts a new regulatory scheme might have on us and our subsidiaries. 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.

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 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, but most existing claims relate to facilities previously owned by CenterPoint Energy or its subsidiaries. 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 (NRG). Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but 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.

EMPLOYEES

As of December 31, 2007, we had 2,746 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 in certain other respects.

	•		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; and

•

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

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. Currently, we do business with 74 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these retail providers to pay for 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 retail electric provider cannot make timely payments. Applicable Texas Utility Commission regulations limit the extent to which we can demand security from REPs for payment of our delivery charges. RRI, through its subsidiaries, is our largest customer. Approximately 48% of our $141 million in billed receivables from REPs at December 31, 2007 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect our cash flows, financial condition and results of operations.

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. In this connection, pursuant to the Settlement Agreement, discussed in “Business — Regulation — State and Local Regulation — Rate Agreement” in Item 1 of this report, until June 30, 2010 we are limited in our ability to request rate relief. The regulatory process by which rates are determined may not always result in rates that will produce full recovery of our costs and enable us to earn a reasonable return on our invested capital.

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 may be adversely affected.

Our revenues and results of operations are seasonal.

Risk Factors Associated with Our Consolidated Financial Condition

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

As of December 31, 2007, we had $3.9 billion of outstanding indebtedness on a consolidated basis, which includes $2.3 billion of non-recourse transition bonds. In February 2008, we issued approximately $488 million of additional non-recourse transition bonds. Our future financing activities may depend, at least in part, on:

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

	•		general economic and capital market conditions;

	•		credit availability from financial institutions and other lenders;

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

	•		maintenance of acceptable credit ratings 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, 2007, we had outstanding $2.0 billion aggregate principal amount of general mortgage bonds under the General Mortgage, including approximately $527 million held in trust to secure pollution control bonds for which CenterPoint Energy is obligated and approximately $229 million held in trust to secure pollution control bonds for which 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 $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2007. However, we have contractually agreed that we will not issue additional first mortgage bonds, subject to certain exceptions.

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, 2007, CenterPoint Energy and its subsidiaries other than us have approximately $842 million principal amount of debt required to be paid through 2010. This amount excludes amounts related to capital leases, transition bonds and indexed debt securities obligations, but includes $123 million of 3.75% convertible notes converted by holders in January and February 2008. In addition, CenterPoint Energy has cash settlement obligations with respect to $412 million of outstanding 3.75% convertible notes on which holders could exercise their conversion rights during the first quarter of 2008 and in subsequent quarters in which CenterPoint Energy’s common stock price causes such notes to be convertible. 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, 2007 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 discussed in “Business — Environmental Matters” in Item 1 of this report. 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.

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. If we were to sustain any loss of, or damage to, our transmission and distribution properties, we may not be able to recover such loss or damage 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.

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:

	•		those transferred to RRI or its subsidiaries in connection with the organization and capitalization of RRI prior to its initial public offering in 2001; and

	•		those transferred to Texas Genco in connection with its organization and capitalization.

In connection with the organization and capitalization of RRI, RRI and its subsidiaries assumed liabilities associated with various assets and businesses Reliant Energy transferred to them. RRI also agreed to indemnify, and cause the applicable transferee subsidiaries to indemnify, 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 is unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy has not been 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 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 Texas Genco LLC. In addition, under the amended separation agreement, Texas Genco is no longer liable for, and CenterPoint Energy has assumed and

agreed to indemnify Texas Genco LLC against, liabilities that Texas Genco originally assumed in connection with its organization to the extent, and only to the extent, that such liabilities are covered by certain insurance policies or other similar agreements held by CenterPoint Energy. If Texas Genco or Texas Genco LLC were unable to satisfy a liability that had been so assumed or indemnified against, and provided CenterPoint Energy had not been released from the liability in connection with the transfer, we could be responsible for satisfying the liability.

CenterPoint Energy or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a large number of individuals who claim injury due to exposure to asbestos. Most claimants in such litigation have been workers who participated in construction of various industrial facilities, including power plants. Some of the claimants have worked at locations CenterPoint Energy owns, but most existing claims relate to facilities previously owned by its subsidiaries but currently owned by Texas Genco LLC, which is now known as NRG Texas LP. We anticipate that additional claims like those received may be asserted in the future. Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but 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 Texas Genco LLC.

Item 1B. Unresolved Staff Comments

Not applicable.

Item 2. Properties

Character of Ownership

We own or lease our principal properties in fee. 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 7(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).

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

Our revolving credit facility limits our debt (excluding transition 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 2.80, 2.20, 1.99, 2.62, and 2.61 for the years ended December 31, 2003, 2004, 2005, 2006 and 2007, 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 approximately 2.0 million metered customers in a 5,000-square-mile area of the Texas Gulf Coast that has a population of approximately 5.5 million people and includes Houston.

On behalf of REPs, we deliver electricity from power plants to substations, from one substation to another and to retail electric customers in locations throughout the control area managed by the Electric Reliability Council of Texas (ERCOT), which serves as the regional reliability coordinating council for member electric power systems in Texas. ERCOT membership is open to consumer groups, investor and municipally owned electric utilities, rural electric cooperatives, independent generators, power marketers and REPs. The ERCOT market represents approximately 85% of the demand for power in Texas and is one of the nation’s largest power markets. Transmission and distribution services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

EXECUTIVE SUMMARY

Significant Events in 2007 and 2008

Debt Refinancing

In June 2007, we entered into an amended and restated bank credit facility. Our amended credit facility is a $300 million five-year senior unsecured revolving credit facility. The facility’s first drawn cost remains at London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings.

Transition Bonds

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) less an environmental refund as reduced by the fuel reconciliation settlement amount.

Recovery of True-Up Balance

In December 2007, the Texas Third Court of Appeals issued its decision in the appeal of the 2004 final order (True-Up Order) issued by the Texas Utility Commission to us. 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 excess mitigation credits (EMCs) paid to Reliant Energy, Inc. (RRI);

	•		ordered that the tax normalization issue be remanded to the Texas Utility Commission; and

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

To reflect the impact of the True-Up Order, in 2004 and 2005 we recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of the pending motions for rehearing or on further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue and the calculation of interest on any amounts 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 $130 million to $350 million, plus interest subsequent to December 31, 2007.

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

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

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

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

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

	•		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 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;

	•		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, 2005, 2006 and 2007, 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,
	2005			2006			2007
	(In millions,
	except throughput and customer data)
Revenues:
Electric transmission and distribution utility	$	1,538		$	1,516		$	1,560
Transition bond companies ⁽¹⁾		106			265			277

Total Revenues		1,644			1,781			1,837

Expenses:
Operation and maintenance, excluding transition bond companies		618			611			652
Depreciation and amortization, excluding transition bond companies		258			243			243
Taxes other than income taxes		214			212			223
Transition bond companies ⁽¹⁾		67			139			158

Total Expenses		1,157			1,205			1,276

Operating Income		487			576			561
Interest and other finance charges		(288	)		(110	)		(107	)
Interest on transition bonds ⁽¹⁾		(40	)		(130	)		(123	)
Return on true-up balance		121			—			—
Other Income, net		51			67			68

Income Before Income Taxes and Extraordinary Item		331			403			399
Income Tax Expense		108			132			126

Income Before Extraordinary Item		223			271			273
Extraordinary Item, net of tax		30			—			—

Net Income	$	253		$	271		$	273


Throughput (in gigawatt-hours (GWh)):
Residential		24,924			23,955			23,999
Total		74,189			75,877			76,291

Average number of metered customers:
Residential		1,683,100			1,732,656			1,773,319
Total		1,912,346			1,968,114			2,012,636


(1)		We issued $748.9 million of transition bonds in October 2001 and $1.851 billion in December 2005. Transition charges are designed to collect revenues in amounts necessary to service principal and interest of the transition bonds and cover related operating expenses of the transition bond companies. The net income of the transition bond companies for all periods presented is $-0-.

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

2006 Compared to 2005. We reported operating income of $576 million for 2006, consisting of $395 million from the TDU, $55 million from the CTC and $126 million related to the transition bond companies. For 2005, operating income totaled $487 million, consisting of $429 million for the TDU, $19 million from the CTC, and $39 million related to the transition bond companies. Increases in operating income from growth ($34 million), a higher CTC amount collected in 2006 ($36 million), revenues from ancillary services ($11 million) and proceeds from land sales ($13 million) were partially offset by milder weather and reduced demand ($49 million), and the implementation of reduced base rates ($13 million) and spending on low income assistance and energy efficiency programs ($5 million) resulting from the settlement agreement discussed above. In addition, the TDU’s operating income for 2006 included the $32 million adverse impact of the resolution of the remand of the 2001 unbundled cost of service order.

In September 2005, our service area in Texas was adversely affected by Hurricane Rita. Although damage to our electric facilities was limited, over 700,000 customers lost power at the height of the storm. Power was restored to over a half million customers within 36 hours and all power was restored in less than five days. Revenues lost as a result of the storm were more than offset by warmer than normal weather during the third quarter of 2005. We deferred $28 million of restoration costs which are being amortized over a seven-year period that began in October 2006.

Interest expense, excluding transition bond-related interest expense, decreased $178 million in 2006 due to reduced borrowing costs and borrowing levels. During the fourth quarter of 2005, we retired at maturity our $1.341 billion term loan, which bore interest at LIBOR plus 975 basis points, subject to a minimum LIBOR rate of 3 percent. Borrowings under our credit facility, which at that time bore interest at LIBOR plus 75 basis points, were used for the payment of the term loan and then repaid with a portion of the proceeds of the December 2005 issuance of transition bonds.

Additionally, other income related to the return on the true-up balance decreased $121 million in 2006 as the return on the true-up balance was discontinued in September 2005 and December 2005 due to the implementation of the CTC and the sale of transition bonds, respectively.

Net income for 2005 included an after-tax extraordinary gain of $30 million reflecting an adjustment to the extraordinary loss recorded in 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.

LIQUIDITY

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements during 2008 include approximately $371 million of capital expenditures and $159 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 cash needs for the next twelve months. Cash needs may also be met by issuing debt securities in the capital markets.

Capital Requirements. The following table sets forth our capital expenditures for 2007 and estimates of our capital requirements for 2008 through 2012 (in millions):


2007	$	401
2008		371
2009		358
2010		444
2011		415
2012		392

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


									2013 and
Contractual Obligations	Total		2008		2009-2010		2011-2012		thereafter
Transition bond debt⁽¹⁾	$	2,260	$	159	$	366	$	432	$	1,303
Other long-term debt		1,642		—		—		96		1,546
Interest payments — transition bond debt ^{(1) (2)}		745		117		207		166		255
Interest payments — other long-term debt ⁽²⁾		1,245		97		196		193		759
Capital leases		1		—		—		—		1
Operating leases ⁽³⁾		4		4		—		—		—
Benefit obligations ⁽⁴⁾		—		—		—		—		—
Income taxes ⁽⁵⁾		3		3		—		—		—

Total contractual cash obligations	$	5,900	$	380	$	769	$	887	$	3,864


(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, 2007; we typically expect to settle such interest payments with cash flows from operations and short-term borrowings.

(3)		For a discussion of operating leases, please read Note 7(a) to our consolidated financial statements.

(4)		We expect to contribute approximately $7 million to our postretirement benefits plan in 2008 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.

(5)		Represents estimated income tax liability for settled positions for tax years under examination. In addition, as of December 31, 2007, the liability for uncertain income tax positions was $92 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 predict the periods in which these liabilities might be paid.

Transition Bonds. During the 2007 legislative session, the Texas legislature amended certain statutes authorizing amounts that can be securitized by utilities. In June 2007, 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, as well as the fuel reconciliation settlement amount, provisions for deduction of the environmental refund and certain other matters. We reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. The financing order allowed for the netting of the fuel reconciliation settlement amount against the environmental refund. In February 2008, approximately $488 million of transition bonds were issued by a new special purpose subsidiary of ours pursuant to the financing order. Proceeds were used by the special purpose entity to purchase $483 million of transition property from us and to pay costs of issuance. We issued a dividend of those net proceeds to our parent, Utility Holding, LLC, which had the effect of reducing our parent’s equity investment in us.

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.

Credit Facilities. In June 2007, we entered into an amended and restated bank credit facility. The amended facility is a $300 million five-year senior unsecured revolving credit facility. The facility’s first drawn cost remains at LIBOR plus 45 basis points based on our current credit ratings. The facility contains covenants, including a debt (excluding transition bonds) to total capitalization covenant of 65%.

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 our credit rating. Borrowings under the facility 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 the credit facility 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 facility. As of February 15, 2008, we had no borrowings and approximately $4 million of outstanding letters of credit under the credit facility.

Temporary Investments. As of February 15, 2008, 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 15, 2008, we had borrowings from the money pool aggregating $112 million. The money pool may not provide sufficient funds to meet our cash needs.

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) and CenterPoint Energy Transition Bond Company II, LLC (Bond Company II), as of December 31, 2007. Amounts are expressed in millions.


							Transition
Year	Third-Party		Affiliate		Sub-Total		Bonds		Total
2008	$	—	$	—	$	—	$	159	$	159
2009		—		—		—		175		175
2010		—		—		—		191		191
2011		—		—		—		206		206
2012		96		—		96		226		322
2013		450		—		450		245		695
2014		300		—		300		147		447
2015		—		151		151		158		309
2016		—		—		—		169		169
2017		127		—		127		182		309
2018		—		—		—		194		194
2019		—		—		—		208		208
2021		102		—		102		—		102
2023		200		—		200		—		200
2027		56		—		56		—		56
2033		312		—		312		—		312

Total	$	1,643	$	151	$	1,794	$	2,260	$	4,054

As of December 31, 2007, outstanding first mortgage bonds and general mortgage bonds aggregated approximately $2.3 billion as shown in the following table. Amounts are expressed in millions.


			Issued as		Issued as Collateral
	Issued Directly		Collateral for Our		for CenterPoint
	to Third Parties		Debt		Energy’s Debt		Total
First Mortgage Bonds	$	102	$	—	$	151	$	253
General Mortgage Bonds		1,262		229		527		2,018

Total	$	1,364	$	229	$	678	$	2,271

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 $2.3 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, 2007. 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.


	First Mortgage		General
Year	Bonds		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

At December 31, 2007, Bond Company had $515 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, 2007, Bond Company II had $1.75 billion aggregate principal amount of outstanding transition bonds that were issued in 2005 in accordance with the Texas electric restructuring law. 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 15, 2008, 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+

Positive

A-

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 $300 million credit facility. A decline in credit ratings would also increase the interest rate on long-term debt to be issued in the capital markets and could negatively impact our ability to complete capital market transactions.

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. Pursuant to the indenture governing CenterPoint Energy’s senior notes, 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. As of December 31, 2007, CenterPoint Energy had six series of senior notes aggregating $1.4 billion in principal amount outstanding under this indenture. 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 facility;

	•		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

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

Certain Contractual Limits on Ability to Issue Securities and Borrow Money. Our credit facility limits our debt (excluding transition bonds) as a percentage of our total capitalization to 65 percent. 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, which results in our accounting for the regulatory effects of recovery of stranded costs and other regulatory assets resulting from the unbundling of the transmission and distribution business from our former electric generation operations in our consolidated financial statements. Certain expenses and revenues subject to utility regulation or rate determination normally reflected in income are deferred on the balance sheet and are recognized in income as the related amounts are included in service rates and recovered from or refunded to customers. Significant accounting estimates embedded within the application of SFAS No. 71 relate to $281 million of recoverable electric generation-related net regulatory assets as of December 31, 2007. These costs are recoverable under the provisions of the 1999 Texas Electric Choice Plan. Based on our analysis of the final order issued by the Texas Utility Commission, we recorded an after-tax charge to earnings in 2004 of approximately $977 million to write down our electric generation-related regulatory assets to their realizable value, which was reflected as an extraordinary loss. Based on subsequent orders received from the Texas Utility Commission, we recorded an extraordinary gain of $30 million after-tax in 2005 related to the regulatory asset. Additionally, a district court in Travis County, Texas issued a judgment which would have had the effect of restoring approximately $650 million, plus interest, of disallowed costs. 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 be remanded to the Texas Utility Commission; and

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

recorded in our consolidated financial statements. However, if the court of appeals decision is not reversed or modified as a result of the pending motions for rehearing or on further review by the Texas Supreme Court, we anticipate that we would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue and the calculation of interest on any amounts 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 $130 million to $350 million, plus interest subsequent to December 31, 2007.

Impairment of Long-Lived Assets and Intangibles

We review the carrying value of our long-lived assets, including 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, 2007, our estimated cost of retiring these assets was approximately $19 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.

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. We expect to record pension income of $3 million in 2008 based on an expected return on plan assets of 8.50% and a discount rate of 6.40% as of December 31, 2007. Pension expense for the year ended December 31, 2007 was $2 million. 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, 2007, 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 $117 million and $97 million at December 31, 2006 and 2007, respectively. If the floating interest rates were to increase by 10% from December 31, 2007 rates, our combined interest expense would increase by less than $1 million annually.

At December 31, 2006 and 2007, we had outstanding fixed-rate debt aggregating $4.1 billion and $4.0 billion in principal amount and having a fair value of approximately $4.3 billion and $4.0 billion in 2006 and 2007, 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 5 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $150 million if interest rates were to decline by 10% from their levels at December 31, 2007. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

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, 2007 and 2006, 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, 2007. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 as of December 31, 2007 and 2006, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the consolidated financial statements, the Company adopted Financial Accounting Standards Board Interpretation No. 47, “Accounting for Conditional Asset Retirement Obligations,” effective December 31, 2005.

DELOITTE & TOUCHE LLP

Houston, Texas
March 12, 2008

MANAGEMENT’S ANNUAL REPORT ON INTERNAL CONTROL
OVER FINANCIAL REPORTING

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

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

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

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

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

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

Under the supervision and with the participation of our management, including our principal executive officer and principal financial officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our evaluation under the framework in Internal Control — Integrated Framework, our management has concluded that our internal control over financial reporting was effective as of December 31, 2007.

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 12, 2008

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED INCOME


	Year Ended December 31,
	2005			2006			2007
	(In Millions)
Revenues	$	1,644		$	1,781		$	1,837


Expenses:
Operation and maintenance		621			614			655
Depreciation and amortization		322			379			398
Taxes other than income taxes		214			212			223

Total		1,157			1,205			1,276

Operating Income		487			576			561


Other Income (Expense):
Interest and other finance charges		(288	)		(110	)		(107	)
Interest on transition bonds		(40	)		(130	)		(123	)
Return on true-up balance		121			—			—
Other, net		51			67			68

Total		(156	)		(173	)		(162	)


Income Before Income Taxes and Extraordinary Item		331			403			399
Income tax expense		(108	)		(132	)		(126	)

Income Before Extraordinary Item		223			271			273
Extraordinary item, net of tax		30			—			—

Net Income	$	253		$	271		$	273

See Notes to the Company’s Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

CONSOLIDATED BALANCE SHEETS


	December 31,
	2006		2007
	(In Millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	122	$	128
Accounts and notes receivable, net		165		172
Accounts and notes receivable—affiliated companies		49		25
Accrued unbilled revenues		95		102
Inventory		63		60
Taxes receivable		34		3
Other		69		70

Total current assets		597		560

Property, Plant and Equipment, net		4,257		4,391

Other Assets:
Regulatory assets		2,820		2,621
Notes receivable—affiliated companies		750		750
Other		39		36

Total other assets		3,609		3,407

Total Assets	$	8,463	$	8,358

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	147	$	159
Accounts payable		72		47
Accounts and notes payable—affiliated companies		141		75
Taxes accrued		105		87
Interest accrued		85		83
Other		67		74

Total current liabilities		617		525

Other Liabilities:
Accumulated deferred income taxes, net		1,341		1,189
Unamortized investment tax credits		35		28
Benefit obligations		197		176
Regulatory liabilities		336		354
Notes payable—affiliated companies		151		151
Other		53		134

Total other liabilities		2,113		2,032

Long-Term Debt		3,851		3,743

Commitments And Contingencies (Note 7)
Member’s Equity		1,882		2,058

Total Liabilities and Member’s Equity	$	8,463	$	8,358

See Notes to the Company’s Consolidated Financial Statements

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,
	2005			2006			2007
	(In Millions)
Cash Flows from Operating Activities:
Net income	$	253		$	271		$	273
Extraordinary item, net of tax		(30	)		—			—

Income before extraordinary item		223			271			273
Adjustments to reconcile income before extraordinary item to net cash provided by operating activities:
Depreciation and amortization		322			379			398
Deferred income taxes		116			(76	)		(73	)
Amortization of deferred financing costs		31			12			11
Changes in other assets and liabilities:
Accounts and notes receivable, net		(59	)		14			(14	)
Accounts receivable/payable, affiliates		61			(36	)		23
Taxes receivable		(79	)		(6	)		31
Inventory		(7	)		(3	)		3
Accounts payable		6			8			(24	)
Interest and taxes accrued		16			1			(20	)
Net regulatory assets and liabilities		(181	)		56			67
Other current assets		(10	)		(2	)		—
Other current liabilities		(15	)		17			7
Other assets		(3	)		9			(1	)
Other liabilities		(17	)		17			(18	)
Other, net		—			(6	)		1

Net cash provided by operating activities		404			655			664

Cash Flows from Investing Activities:
Capital expenditures		(267	)		(381	)		(402	)
Decrease in notes receivable from affiliates		73			—			—
Increase in restricted cash of transition bond companies		(12	)		(32	)		(1	)
Other, net		—			1			12

Net cash used in investing activities		(206	)		(412	)		(391	)

Cash Flows from Financing Activities:
Long-term revolving credit facility, net		—			—			50
Proceeds from long-term debt		3,161			—			—
Payments of long-term debt		(2,668	)		(74	)		(147	)
Increase (decrease) in short-term notes payable with affiliates		68			49			(70	)
Decrease in long-term payable with affiliates		(303	)		—			—
Debt issuance costs		(16	)		—			—
Contribution from (to) parent		113			(36	)		—
Dividend to parent		(537	)		(100	)		(100	)
Other, net		(1	)		—			—

Net cash used in financing activities		(183	)		(161	)		(267	)

Net Increase in Cash and Cash Equivalents		15			82			6
Cash and Cash Equivalents at Beginning of the Year		25			40			122

Cash and Cash Equivalents at End of the Year	$	40		$	122		$	128

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	319		$	198		$	221
Income taxes		155			304			180
Non-cash transactions:
Increase in accounts payable related to capital expenditures	$	10		$	7		$	—

See Notes to the Company’s Consolidated Financial Statements

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES
(An Indirect Wholly Owned Subsidiary of CenterPoint Energy, Inc.)

STATEMENTS OF CONSOLIDATED MEMBER’S EQUITY


	2005					2006					2007
	Shares		Amount			Shares		Amount			Shares		Amount
	(In millions, except share amounts)
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				2,278					1,719					1,712
Contribution to parent				(28	)				(8	)				—
Dividend to parent				(528	)				—					—
Other				(3	)				1					—

Balance, end of year				1,719					1,712					1,712

Retained Earnings (Deficit)
Balance, beginning of year				(245	)				(1	)				170
Net income				253					271					273
Dividend to parent				(9	)				(100	)				(100	)
Cumulative effect of adopting FIN 48				—					—					3

Balance, end of year				(1	)				170					346

Total Member’s Equity			$	1,718				$	1,882				$	2,058

See Notes to the Company’s Consolidated Financial Statements

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, 2007, the Company had two subsidiaries, CenterPoint Energy Transition Bond Company, LLC and CenterPoint Energy Transition Bond Company II, 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 in the United States of America 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)		2006		2007
			(In millions)
Transmission		39	$	1,427	$	1,456
Distribution		25		4,643		4,757
Other		17		753		780

Total				6,823		6,993
Accumulated depreciation				2,566		2,602

Property, plant and equipment, net			$	4,257	$	4,391

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

(e) Regulatory Assets and Liabilities

The Company applies the accounting policies established in 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, 2006 and 2007:


	December 31,
	2006		2007
	(In millions)
Electric generation-related regulatory assets(1)	$	343	$	325
Securitized regulatory assets(2)		2,285		2,131
Unamortized loss on reacquired debt		85		79
Postretirement-related regulatory asset(3)		60		39
Other long-term regulatory assets		47		47

Total regulatory assets		2,820		2,621


Electric generation-related regulatory liabilities		39		44
Estimated removal costs		273		290
Other long-term regulatory liabilities		24		20

Total regulatory liabilities		336		354

Total regulatory assets and liabilities, net	$	2,484	$	2,267


(1)		Excludes $234 million and $220 million of allowed equity return on the true-up balance as of December 31, 2006 and 2007, respectively.

(2)		Represents the transition property of the transition bond companies.

(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.

If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write off or write down these regulatory assets and liabilities. During 2004, the Company wrote off net regulatory assets of $1.5 billion ($977 million after-tax) as an extraordinary loss in response to an order of the Public Utility Commission of Texas (Texas Utility Commission) on the Company’s final true-up application. Based on subsequent orders received from the Texas Utility Commission, the Company recorded an extraordinary gain of $47 million ($30 million after-tax) in the second quarter of 2005 related to these regulatory assets. For further discussion of regulatory assets, see Note 3.

The Company recognizes removal costs as a component of depreciation expense in accordance with regulatory treatment. As of December 31, 2006 and 2007, these removal costs of $273 million and $290 million, respectively, are classified as regulatory liabilities in the Consolidated Balance Sheets. The Company adopted Financial Accounting Standards Board (FASB) Interpretation No. (FIN) 47, “Accounting for Conditional Asset Retirement Obligations” (FIN 47), effective December 31, 2005. FIN 47 clarifies that an entity must record a liability for a “conditional” asset retirement obligation if the fair value of the obligation can be reasonably estimated. The Company has identified conditional asset retirement obligations for treated utility poles and for transformers contaminated by polychlorinated biphenyls. The fair value of these obligations is recorded as a liability on a discounted basis with a corresponding increase to the related asset. Over time, the liabilities are accreted for the change in the present value and the initial capitalized costs are depreciated over the useful lives of the related assets. The adoption of FIN 47 resulted in the recognition of an asset retirement obligation liability of $11 million, an increase in property, plant and equipment of $6 million and a $5 million increase in regulatory assets. Upon adoption of FIN 47, the portion of the removal costs that relates to this asset retirement obligation has been reclassified from a regulatory liability to an asset retirement liability, which is included in other liabilities in the Consolidated Balance Sheets. At December 31, 2006 and 2007, the Company had recorded asset retirement obligations of $18 million and $19 million, respectively.

(f) Depreciation and Amortization Expense

Depreciation is computed using the straight-line method based on economic lives or a regulatory-mandated recovery period. The transition property is being amortized over the expected life of the two series of transition bonds (12 years and 14 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.

The following table presents depreciation and amortization expense for 2005, 2006 and 2007:


	Year Ended December 31,
	2005		2006			2007
	(In millions)
Depreciation expense	$	237	$	245		$	251
Amortization of securitized regulatory assets		65		135			155
Other amortization		20		(1	)		(8	)

Total depreciation and amortization	$	322	$	379		$	398

(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 2005, 2006 and 2007, the Company capitalized AFUDC of $3 million, $4 million and $10 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 2005 and 2006, the Company received an allocation of CenterPoint Energy’s tax expenses totaling $28 million and $8 million, respectively.

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 6.

(i) Accounts Receivable and Allowance for Doubtful Accounts

Accounts and notes receivable, net, are net of an allowance for doubtful accounts of $1 million at both December 31, 2006 and 2007. The provision for doubtful accounts in the Company’s Statements of Consolidated Income for 2005, 2006 and 2007 was $3 million, $(2) million and $1 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 and December 2005, 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 include restricted cash of $49 million at both December 31, 2006 and 2007. For additional information regarding transition bonds, see Notes 3(a) and 5. Cash and cash equivalents includes $123 million and $128 million at December 31, 2006 and 2007, respectively, that is held by the Company’s transition bond subsidiaries solely to support servicing the transition bonds.

(l) New Accounting Pronouncements

In July 2006, the FASB issued FIN 48. FIN 48 clarifies the accounting for uncertain income tax positions and requires the Company to recognize management’s best estimate of the impact of a tax position if it is considered “more likely than not,” as defined in SFAS No. 5, “Accounting for Contingencies,” of being sustained on audit based solely on the technical merits of the position. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure and transition. The cumulative effect of adopting FIN 48 as of January 1, 2007 was an approximately $3 million credit to retained earnings.

In September 2006, the FASB issued SFAS No. 157, “Fair Value Measurements” (SFAS No. 157). SFAS No. 157 establishes a framework for measuring fair value and requires expanded disclosure about the information used to measure fair value. The statement applies whenever other statements require or permit assets or liabilities to be measured at fair value. The statement does not expand the use of fair value accounting in any new circumstances and is effective for the Company for the year ended December 31, 2008 and for interim periods included in that year, with early adoption encouraged. The Company will adopt SFAS No. 157 on January 1, 2008, for its financial assets and liabilities, and on January 1, 2009, for its non-financial assets and liabilities. For its financial assets and liabilities, the Company expects that the adoption of SFAS No. 157 will primarily impact its disclosures and will not have a material impact on its financial position, results of operations and cash flows. The Company is currently evaluating the impact with respect to its non-financial assets and liabilities.

In February 2007, the FASB issued 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 the 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 and cash flows.

(m) Employee Benefit Plans

Pension Plans

Substantially all of the Company’s employees participate in CenterPoint Energy’s qualified non-contributory defined benefit pension plan. Under the cash balance formula, participants accumulate a retirement benefit based upon 4% of eligible earnings and accrued interest. Prior to 1999, the pension plan accrued benefits based on years of service, final average pay and covered compensation. As a result, certain employees participating in the plan as of December 31, 1998 are eligible to receive the greater of the accrued benefit calculated under the prior plan 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 $9 million, $10 million and $1 million for the years ended December 31, 2005, 2006 and 2007, respectively.

In addition to the pension plan, the Company participates in CenterPoint Energy’s non-qualified benefit restoration plan, which allows participants to retain the benefits to which they would have been entitled under the non-contributory pension plan except for federally mandated limits on these benefits or on the level of compensation on which these 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, 2005, 2006 and 2007.

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 16% of compensation. CenterPoint Energy matches 75% of the first 6% of each employee’s compensation contributed. CenterPoint Energy may contribute an additional discretionary match of up to 50% of the first 6% of each employee’s compensation contributed. These 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 $13 million, $12 million and $12 million for the years ended December 31, 2005, 2006 and 2007, respectively.

Postretirement Benefits

The Company’s employees participate in CenterPoint Energy’s plans which provide certain health care 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, health care 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.

Upon adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132 (R)” (SFAS No. 158), at December 31, 2006, the Company recorded a regulatory asset of $60 million and a corresponding increase in its benefit obligations for its unrecognized postretirement costs as the associated operations have historically recovered and currently recover such costs in rates. The adoption of SFAS No. 158 did not impact the income statement recognition provisions of benefit plan accounting.

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,
	2005			2006			2007
	(In millions)
Service cost— benefits earned during the period	$	1		$	1		$	1
Interest cost on projected benefit obligation		17			16			17
Expected return on plan assets		(11	)		(11	)		(11	)
Amortization of transition obligation		6			6			6

Net postretirement benefit cost	$	13		$	12		$	13

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


	Year Ended December 31,
	2005			2006			2007
Discount rate		5.75	%		5.70	%		5.85	%
Expected return on plan assets		8.00	%		8.50	%		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.

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 2006 and 2007. The measurement dates for plan assets and obligations were December 31, 2006 and 2007.


	Year Ended December 31,
	2006			2007
	(In millions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	296		$	294
Service cost		1			1
Interest cost		16			17
Benefits paid		(19	)		(17	)
Participant contributions		1			1
Plan amendment		1			—
Actuarial gain		(2	)		(15	)

Accumulated benefit obligation, end of year	$	294		$	281

Change in Plan Assets
Plan assets, beginning of year	$	134		$	138
Benefits paid		(19	)		(17	)
Employer contributions		9			9
Participant contributions		1			1
Actual investment return		13			11

Plan assets, end of year	$	138		$	142

Amounts Recognized in Balance Sheets
Other liabilities-benefit obligations	$	(156	)	$	(139	)

Net liability, end of year	$	(156	)	$	(139	)

Actuarial Assumptions
Discount rate		5.85	%		6.40	%
Expected long-term return on assets		8.00	%		8.00	%
Healthcare cost trend rate assumed for the next year		7.00	%		7.00	%
Prescription drug cost trend rate assumed for the next year		13.00	%		13.00	%
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		2011			2012
Year that the prescription drug rate reaches the ultimate trend rate		2014			2015

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 the Company’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 7% during 2008, after which this rate decreases until reaching the ultimate rate of 5.50% in 2012. Prescription drug costs are assumed to increase 13% in 2008, after which this rate decreases until reaching the ultimate rate of 5.50% in 2015.

The Company does not have amounts recognized in accumulated other comprehensive income as of December 31, 2006 and 2007 related to its postretirement benefit plans. Unrecognized costs were recorded as a regulatory asset because the Company has historically recovered and currently recovers postretirement expenses in rates.

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%		1%
	Increase		Decrease
	(In millions)
Effect on the postretirement benefit obligation	$	13	$	(11	)
Effect on total of service and interest cost		1		(1	)

The following table displays the weighted average asset allocations as of December 31, 2006 and 2007 for the Company’s postretirement benefit plans:


	December 31,
	2006			2007
Domestic equity securities		31	%		30	%
International equity securities		12			11
Debt securities		57			59

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, which 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 $7 million to its postretirement benefits plan in 2008. The following benefit payments are expected to be paid by the postretirement benefit plan (in millions):


	Postretirement Benefit Plan
			Medicare
	Benefit		Subsidy
	Payments		Receipts
2008	$	20	$	(3	)
2009		21		(3	)
2010		22		(3	)
2011		23		(3	)
2012		23		(3	)
2013-2017		127		(19	)

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). Postemployment benefits costs were $5 million and $2 million in 2005 and 2006, respectively. The Company recorded postemployment income of less than $1 million in 2007. Included in “Benefit Obligations” in the accompanying Consolidated

Balance Sheets at December 31, 2006 and 2007 were $20 million and $18 million, respectively, relating to postemployment obligations.

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. During 2005, 2006 and 2007, the Company recorded benefit expense relating to these programs of $2 million, $1 million and $1 million, respectively. Included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2006 and 2007 was $18 million and $17 million, respectively, relating to deferred compensation plans.

(n) Other Current Assets and Liabilities

Included in other current assets in the Consolidated Balance Sheets at both December 31, 2006 and 2007 was $49 million of restricted cash related to the transition bond companies. Included in other current liabilities in the Consolidated Balance Sheets at December 31, 2006 and 2007 was $36 million and $37 million, respectively, of customer deposits.

(3) Regulatory Matters

(a) 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 in certain other respects.

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; 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; and

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

The Company and two other parties filed motions for rehearing with the court of appeals. In the event that the motions for rehearing are not resolved in a manner favorable to it, the Company intends to seek further review by the Texas Supreme Court. Although the Company believes that its true-up request is consistent with applicable statutes and regulations and accordingly that it is reasonably possible that it will be successful in its further appeals, the Company can provide no assurance as to the ultimate rulings by the courts on the issues to be considered in the various appeals or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005 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 the pending motions for rehearing or on 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 $130 million to $350 million plus interest subsequent to December 31, 2007.

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. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, in December 2005, the IRS withdrew those proposed normalization regulations and issued new proposed regulations that do not include the provision allowing a retroactive election to pass the tax benefits back to customers. CenterPoint Energy subsequently requested a Private Letter Ruling (PLR) asking the IRS whether the Texas Utility Commission’s order reducing the Company’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations. In that ruling, which was received in August 2007, the IRS concluded that such reductions would cause normalization violations with respect to the ADITC and EDFIT. As in a similar PLR issued in May 2006 to another Texas utility, the IRS did not reference its proposed regulations.

The district court affirmed the Texas Utility Commission’s ruling on the tax normalization issue, but in response to a request from the Texas Utility Commission, the court of appeals ordered that the tax normalization issue be remanded for further consideration. If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require 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. However, 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 the issuance of transition bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of the Company 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 retail electric providers 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. Effective September 13, 2005, the return on the CTC portion of the true-up balance is included in the Company’s tariff-based revenues.

Certain parties appealed the CTC Order to a district court in Travis County. In May 2006, the district court issued a judgment reversing the CTC Order in three respects. First, the court ruled that the Texas Utility Commission had improperly relied on provisions of its rule dealing with the interest rate applicable to CTC amounts. The district court reached that conclusion based on its belief that the Texas Supreme Court had previously invalidated that entire section of the rule. The 11.075% interest rate in question was applicable from the implementation of the CTC Order on September 13, 2005 until August 1, 2006, the effective date of the implementation of a new CTC in compliance with the new rule discussed below. Second, the district court reversed the Texas Utility Commission’s ruling that allows 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 disagree with the district court’s conclusions and, in May 2006, appealed the judgment to the Texas Third Court of Appeals, and if required, the Company plans to seek further review from the Texas Supreme Court. All briefs in the appeal have been filed, and oral arguments were held in December 2006. The ultimate outcome of this matter cannot be predicted at this time. However, the Company does not expect the disposition of this matter to have a material adverse effect on its financial condition, results of operations or cash flows.

In June 2006, the Texas Utility Commission adopted the revised rule governing the carrying charges on unrecovered CTC balances as recommended by its staff (Staff). The rule, which applies to the Company, reduced the allowed interest rate on the unrecovered CTC balance prospectively from 11.075% to a weighted average cost of capital of 8.06%. The annualized impact on operating income is a reduction of approximately $18 million per year for the first year with lesser impacts in subsequent years. In July 2006, the Company made a compliance filing necessary to implement the rule changes effective August 1, 2006.

During the years ended December 31, 2005, 2006 and 2007, the Company recognized approximately $19 million, $55 million and $42 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2005, 2006 and 2007, the Company recognized approximately $1 million, $13 million and $14 million, respectively, of the allowed equity return not previously recorded. As of December 31, 2007, the Company had not recorded an allowed equity return of $220 million on its 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, after taking into account the environmental refund and the fuel reconciliation settlement amounts discussed below. 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, a new special purpose subsidiary of the Company issued approximately $488 million of transition bonds pursuant to the financing order in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

(b) Final Fuel Reconciliation

The results of the Texas Utility Commission’s final decision related to the Company’s final fuel reconciliation were a component of the True-Up Order. The Company appealed certain portions of the True-Up Order involving a disallowance of approximately $67 million relating to the final fuel reconciliation in 2003 plus interest of $10 million. That decision was upheld by a Travis County district court and affirmed by the Texas Third Court of Appeals. Although it filed an appeal with the Texas Supreme Court, in February 2007 the Company asked the Texas Supreme Court to hold that appeal in abeyance pending consideration by the Texas Utility Commission of a tentative settlement reached by the parties. In October 2007 the Texas Utility Commission issued a final order consistent with the settlement, and the Texas Supreme Court ultimately vacated the lower court decisions. The settlement allows the Company recovery of $12.5 million plus interest from January 2002. As a result of the settlement, the Company recorded a regulatory asset of $17 million in 2007.

(c) Refund of Environmental Retrofit Costs

The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to the Company’s generation assets. The True-Up Order required the Company to provide evidence by January 31, 2007 that the entire $699 million was actually spent by December 31, 2006 on environmental programs and provided for the Texas Utility Commission to determine the appropriate manner to return to customers any unused portion of these funds, including interest on the funds and on stranded costs attributable to the environmental costs portion of the stranded costs recovery. In January 2007, the successor in interest to the Company’s generation assets advised that, as of December 31, 2006, it had spent only approximately $664 million. On January 31, 2007, the Company made the required filing with the Texas Utility Commission, identifying approximately $35 million in unspent funds to be refunded to customers along with approximately $7 million of interest and requesting permission to refund these amounts through a reduction of the CTC. Such amounts were recorded as regulatory liabilities as of December 31, 2006. In July 2007, the Company, the Staff and the other parties filed a settlement agreement in which it was agreed that the total amount of the refund, including all principal and interest, was $45 million as of May 31, 2007, that interest would continue to accrue after May 31, 2007 on any unrefunded balance at a rate of 5.4519% per year and that the refund should be used to offset the principal amount proposed in the Company’s application to securitize the CTC and other amounts. The offset occurred in connection with the $488 million of transition bonds issued in February 2008. In August 2007, the Texas Utility Commission issued a final order consistent with the terms of that settlement agreement. As of December 31, 2007, the Company had recorded a regulatory liability of $46 million related to this matter.

(4) 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 $117 million and $47 million at December 31, 2006 and 2007, respectively, which are included in accounts and notes payable—affiliated companies in the Consolidated Balance Sheets. At December 31, 2007, the Company’s money pool borrowings had a weighted average interest rate of 5.188%.

At December 31, 2006 and 2007, the Company had a $750 million note receivable from its parent, which bears interest at prime, 7.25% at December 31, 2007.

For the years ended December 31, 2005, 2006 and 2007, the Company had net interest income related to affiliate borrowings of $42 million, $50 million and $49 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 $110 million, $112 million and $103 million in 2005, 2006 and 2007, 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 $28 million and $8 million for 2005 and 2006, respectively, which was recorded in additional paid-in capital.

In 2005, 2006 and 2007, the Company paid a dividend of $537 million, $100 million and $100 million, respectively.

(b) Major Customers

During 2005, 2006 and 2007, revenues derived from energy delivery charges provided by the Company to subsidiaries of RRI totaled $812 million, $737 million and $661 million, respectively.

(5) Long-term Debt


	December 31, 2006					December 31, 2007
	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 3.84% to 5.63% due 2006 to 2019		2,260			147		2,101			159
Bank loans due 2012(4)		—			—		50			—
Other		(2	)		—		(1	)		—

Total long-term debt	$	3,851		$	147	$	3,743		$	159


(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, 2006 and 2007. 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.

In June 2007, the Company entered into an amended and restated bank credit facility. The amended facility is a $300 million five-year senior unsecured revolving credit facility. The facility’s first drawn cost remains at the London Interbank Offered Rate (LIBOR) plus 45 basis points based on the Company’s current credit ratings. The facility contains covenants, including a debt (excluding transition bonds) to total capitalization covenant of 65%. 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 Company’s credit rating. Borrowings under the facility are subject to customary terms and conditions. However, there is no requirement that the Company 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 the credit facility are subject to acceleration upon the occurrence of events of default that the Company considers customary.

As of December 31, 2007, the Company had $50 million of borrowings and approximately $4 million of outstanding letters of credit under its $300 million credit facility. The Company was in compliance with all debt covenants as of December 31, 2007.

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(a) for further discussion.

Maturities. The Company’s maturities of long-term debt and scheduled payments on transition bonds are $159 million in 2008, $175 million in 2009, $191 million in 2010, $206 million in 2011 and $322 million in 2012.

Liens. As of December 31, 2007, 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 2005, 2006 and 2007 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2008 is approximately $164 million, and the sinking fund requirement to be satisfied in 2008 is approximately $3 million. The Company expects to meet these 2008 obligations by certification of property additions. As of December 31, 2007, the Company’s assets were also subject to liens securing approximately $2.0 billion of general mortgage bonds which are junior to the liens of the first mortgage bonds.

(6) Income Taxes

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


	Year Ended December 31,
	2005			2006			2007
	(In millions)
Current federal	$	(8	)	$	208		$	199
Deferred federal		116			(76	)		(73	)

Income tax expense	$	108		$	132		$	126

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


	Year Ended December 31,
	2005			2006			2007
	(In millions)
Income before income taxes and extraordinary item	$	331		$	403		$	399
Federal statutory rate		35	%		35	%		35	%

Income tax expense at statutory rate		116			141			139

Decrease in tax resulting from:
Amortization of investment tax credit		(7	)		(7	)		(7	)
Other, net		(1	)		(2	)		(6	)

Total		(8	)		(9	)		(13	)

Income tax expense	$	108		$	132		$	126

Effective income tax rate		32.8	%		32.7	%		31.6	%

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


	December 31,
	2006		2007
	(In millions)
Deferred tax assets:
Non-current:
Employee benefits	$	75	$	74
Other		27		35

Total deferred tax assets		102		109

Deferred tax liabilities:
Non-current:
Depreciation		554		463
Regulatory assets, net		877		826
Other		12		9

Total deferred tax liabilities		1,443		1,298

Accumulated deferred income taxes, net	$	1,341	$	1,189

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 from January 1, 2007 to December 31, 2007 is as follows (in millions):


Balance at January 1, 2007	$	70
Tax positions related to prior years:
Additions		30
Reductions		(12	)
Tax positions related to current year:
Additions		4

Balance at December 31, 2007	$	92

The Company has $8 million of unrecognized tax benefits that, if recognized, would reduce the effective income tax rate. The Company recognizes interest and penalties as a component of income tax expense. In 2007 the Company recognized approximately $5 million of interest on uncertain income tax positions in the Statements of Consolidated Income and $3 million and $7 million in the Consolidated Balance Sheets at January 1, 2007 and December 31, 2007, respectively. The Company does not expect the amount of unrecognized tax benefits to change significantly over the next 12 months.

Tax Audits. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through the 1996 tax year. The Company is currently under examination by the IRS for tax years 1997 through 2005 and is at various stages of the examination process. 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, 2007.

(7) Commitments and Contingencies

(a) Lease Commitments

The Company’s obligations under non-cancelable long-term operating leases at December 31, 2007, which primarily consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment, is $4 million in 2008. The Company currently has no further obligations under non-cancelable long-term operating leases for the years 2009 to 2012. Total lease expense for all operating leases was

approximately $4 million, $5 million and $4 million for the years ended December 31, 2005, 2006 and 2007, 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 RRI, CenterPoint Energy and its subsidiaries, including the Company, are entitled to be indemnified by RRI for any losses, including attorneys’ fees and other costs, arising out of the lawsuits described below under “Electricity and Gas Market Manipulation Cases” and “Other Class Action Lawsuits.” Pursuant to the indemnification obligation, RRI is defending CenterPoint Energy and its subsidiaries to the extent named in these lawsuits. Although the ultimate outcome of these matters cannot be predicted at this time, CenterPoint Energy has not considered it necessary to establish reserves related to this litigation.

Electricity and Gas Market Manipulation Cases. A large number of lawsuits have been filed against numerous market participants and remain pending in federal court in Wisconsin, Missouri and Nevada and in state court in California and Nevada in connection with the operation of the electricity and natural gas markets in California and certain other states in 2000-2001, a time of power shortages and significant increases in prices. These lawsuits, many of which have been filed as class actions, are based on a number of legal theories, including violation of state and federal antitrust laws, laws against unfair and unlawful business practices, the federal Racketeer Influenced Corrupt Organization Act, false claims statutes and similar theories and breaches of contracts to supply power to governmental entities. Plaintiffs in these lawsuits, which include state officials and governmental entities as well as private litigants, are seeking a variety of forms of relief, including recovery of compensatory damages (in some cases in excess of $1 billion), a trebling of compensatory damages and punitive damages, injunctive relief, restitution, interest due, disgorgement, civil penalties and fines, costs of suit and attorneys’ fees. CenterPoint Energy’s former subsidiary, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally.

CenterPoint Energy and/or Reliant Energy have been named in approximately 35 of these lawsuits, which were instituted between 2001 and 2007 and are pending in California state court in San Diego County, in Nevada state court in Clark County, in federal district court in Nevada and before the Ninth Circuit Court of Appeals. However, the Company, CenterPoint Energy and Reliant Energy were not participants in the electricity or natural gas markets in California. CenterPoint Energy and Reliant Energy have been dismissed from certain of the lawsuits, either voluntarily by the plaintiffs or by order of the court, and CenterPoint Energy believes it is not a proper defendant in the remaining cases and will continue to seek dismissal from such remaining cases.

To date, several of the electricity complaints have been dismissed, and several of the dismissals have been affirmed by appellate courts. Others have been resolved by the settlement described in the following paragraph. Three of the gas complaints were dismissed based on defendants’ claims of the filed rate doctrine, but the Ninth Circuit Court of Appeals reversed two of those dismissals and remanded the cases back to the district court for further proceedings. In June 2005, a San Diego state court refused to dismiss other gas complaints on the same basis. In October 2006, RRI reached a tentative settlement of 11 class action natural gas cases pending in state court in California. The court approved this settlement in June 2007. In the remaining gas cases in state court in California, the Court of Appeals found that CenterPoint Energy was not a successor to the liabilities of a subsidiary of RRI and ordered the state court to dismiss CenterPoint Energy. The other gas cases remain in the early procedural stages.

In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement also resolves the claims of the three states

and the investor-owned utilities related to the 2000-2001 natural gas markets. The settlement has been approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases are pending. Two parties have appealed the courts’ approval of the settlement to the California Court of Appeals. A party in the FERC proceedings filed a motion for rehearing of the FERC’s order approving the settlement, which the FERC denied in May 2006. That party has filed for review of the FERC’s orders in the Ninth Circuit Court of Appeals. CenterPoint Energy is not a party to the settlement, but may rely on the settlement as a defense to any claims brought against it related to the time when CenterPoint Energy was an affiliate of RRI. The terms of the settlement do not require payment by CenterPoint Energy.

Other Class Action Lawsuits. In May 2002, three class action lawsuits were filed in federal district court in Houston on behalf of participants in various employee benefits plans sponsored by CenterPoint Energy. Two of the lawsuits were dismissed without prejudice. In the remaining lawsuit, CenterPoint Energy and certain current and former members of its benefits committee are defendants. That lawsuit alleged that the defendants breached their fiduciary duties to various employee benefits plans, directly or indirectly sponsored by CenterPoint Energy, in violation of the Employee Retirement Income Security Act of 1974 by permitting the plans to purchase or hold securities issued by CenterPoint Energy when it was imprudent to do so, including after the prices for such securities became artificially inflated because of alleged securities fraud engaged in by the defendants. The complaint sought monetary damages for losses suffered on behalf of the plans and a putative class of plan participants whose accounts held CenterPoint Energy or RRI securities, as well as restitution. In January 2006, the federal district judge granted a motion for summary judgment filed by CenterPoint Energy and the individual defendants. The plaintiffs appealed the ruling to the Fifth Circuit Court of Appeals, which heard oral arguments from the parties in October 2007. CenterPoint Energy believes that this lawsuit is without merit and will continue to vigorously defend the case. However, the ultimate outcome of this matter cannot be predicted at this time.

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, but most existing claims relate to facilities previously owned by CenterPoint Energy or its subsidiaries. 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 (NRG). Under the terms of the arrangements regarding separation of the generating business from CenterPoint Energy and its sale to Texas Genco LLC, ultimate financial responsibility for uninsured losses from claims relating to the generating business has been assumed by Texas Genco LLC and its successor, but 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 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.

(8) 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, 2006

December 31, 2007

Carrying

Fair

Carrying

Fair

Amount

Value

Amount

Value

(In millions)

Financial liabilities:

Long-term debt (including $151 million of long-term notes payable to parent)

4,148

4,250

4,052

4,083

(9) Unaudited Quarterly Information

Summarized quarterly financial data is as follows:


	Year Ended December 31, 2006
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In millions)
Revenues	$	385	$	456	$	533	$	407
Operating income		110		151		219		96
Net income		43		71		119		38


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

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, 2007 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, 2007 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).

Item 14. Principal Accounting Fees and Services

Aggregate fees billed to the Company during the fiscal years ending December 31, 2006 and 2007 by its principal accounting firm, Deloitte & Touche LLP, are set forth below.


	Year Ended December 31,
	2006		2007
Audit fees	$	414,400	$	404,050
Audit-related fees		34,000		48,000

Total audit and audit-related fees		448,400		452,050
Tax fees		—		—
All other fees		—		—

Total fees	$	448,400	$	452,050

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			29
Statements of Consolidated Income for the Three Years Ended December 31, 2007			31
Consolidated Balance Sheets at December 31, 2006 and 2007			32
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2007			33
Statements of Consolidated Member’s Equity for the Three Years Ended December 31, 2007			34
Notes to Consolidated Financial Statements			35

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2007.

Report of Independent Registered Public Accounting Firm			54
II— Qualifying Valuation Accounts			55

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 57.

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, 2007 and 2006, and for each of the three years in the period ended December 31, 2007, and have issued our report thereon dated March 12, 2008 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Company’s adoption of a new accounting standard for conditional asset retirement obligations in 2005); 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 12, 2008

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, 2007
(In Millions)

Column A

Column B

Column C

Column D

Column E

Additions

Balance At

Deductions

Balance At

Beginning

Charged

From

End Of

Description

of Period

to Income

Reserves(1)

Period

Year Ended December 31, 2007:

Accumulated provisions:

Uncollectible accounts receivable

Year Ended December 31, 2006:

Accumulated provisions:

Uncollectible accounts receivable

)

Year Ended December 31, 2005:

Accumulated provisions:

Uncollectible accounts receivable

—


(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.

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 12th day of March, 2008.


	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 12, 2008.


Signature		Title

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

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

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

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC

EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2007

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.


			SEC File or
Exhibit			Registration	Exhibit
Number	Description	Report or Registration Statement	Number	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


			SEC File or
Exhibit			Registration	Exhibit
Number	Description	Report or Registration Statement	Number	Reference
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)

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	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	CNP’s Form 10-K for the year ended	1-31447	4(e)(12)


			SEC File or
Exhibit			Registration	Exhibit
Number	Description	Report or Registration Statement	Number	Reference
	November 12, 2002 setting forth the form, terms and provisions of the Ninth Series of General Mortgage Bonds	December 31, 2003

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

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(e)(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(e)(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(e)(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)


			SEC File or
Exhibit			Registration	Exhibit
Number	Description	Report or Registration Statement	Number	Reference
4(b)(24)	Sixteenth Supplemental Indenture to Exhibit 4(e)(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(e)(1), dated as of March 31, 2004	CNP’s Form 10-K for the year ended December 31, 2005	1-31447	4(e)(24)

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(c)	$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

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.


			SEC File or
Exhibit			Registration	Exhibit
Number	Description	Report or Registration Statement	Number	Reference

10	City of Houston Franchise	CNP’s Form 10-Q for the quarter ended	1-31447	10.1
	Ordinance	June 30, 2005

+12	Computation of Ratios of
	Earnings to Fixed Charges

+31.1	Rule 13a-14(a)/15d-14(a)
	Certification of David M.
	McClanahan

+31.2	Rule 13a-14(a)/15d-14(a)
	Certification of Gary L.
	Whitlock

+32.1	Section 1350 Certification
	of David M. McClanahan

+32.2	Section 1350 Certification
	of Gary L. Whitlock

exv12

Exhibit 12

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES
(Millions of dollars)


	Year Ended December 31,
	2003			2004			2005			2006			2007 (1)
Income from continuing operations	$	432		$	282		$	223		$	271		$	273
Income taxes for continuing operations		230			137			108			132			126
Capitalized interest		(3	)		(2	)		(3	)		(4	)		(10	)

		659			417			328			399			389


Fixed charges, as defined:
Interest		361			345			328			240			230
Capitalized interest		3			2			3			4			10
Interest component of rentals charged to operating expense		2			1			1			2			1

Total fixed charges		366			348			332			246			241

Earnings, as defined	$	1,025		$	765		$	660		$	645		$	630

Ratio of earnings to fixed charges		2.80			2.20			1.99			2.62			2.61


(1)		Excluded from the computation of fixed charges is interest expense of $4 million in 2007, which is included in income tax expense.

exv31w1

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this annual report on Form 10-K of CenterPoint Energy Houston Electric, LLC;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 12, 2008



	/s/ David M. McClanahan
	David M. McClanahan
	Chairman (Principal Executive Officer)

exv31w2

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this annual report on Form 10-K of CenterPoint Energy Houston Electric, LLC;

	(a)		Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

	(b)		Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

	(c)		Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

	(d)		Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

	(a)		All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

	(b)		Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: March 12, 2008



	/s/ Gary L. Whitlock
	Gary L. Whitlock
	Executive Vice President and Chief Financial Officer

exv32w1

Exhibit 32.1

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Houston Electric, LLC (the “Company”) on Form 10-K for the year ended December 31, 2007 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chairman (Principal Executive Officer), certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ David M. McClanahan
David M. McClanahan Chairman (Principal Executive Officer)
March 12, 2008

exv32w2

Exhibit 32.2

CERTIFICATION PURSUANT TO
18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO SECTION 906
OF THE SARBANES-OXLEY ACT OF 2002

In connection with the Annual Report of CenterPoint Energy Houston Electric, LLC (the “Company”) on Form 10-K for the year ended December 31, 2007 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

1. The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended; and

2. The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.


/s/ Gary L. Whitlock
Gary L. Whitlock Executive Vice President and Chief Financial Officer
March 12, 2008