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, 2006


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

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

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


Title of each class		Name of each exchange on which registered

9.15% First Mortgage Bonds due 2021 6.95% General Mortgage Bonds due 2033		New York Stock Exchange 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, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer o Non-accelerated filerþ

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, 2006: None

TABLE OF CONTENTS


		Page
	PART I
Item 1.	Business		1
Item 1A.	Risk Factors		12
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		18

	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		18
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.	Controls and Procedures		51
Item 9B.	Other Information		51

	PART III
Item 10.	Directors, Executive Officers and Corporate Governance		51
Item 11.	Executive Compensation		51
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		51
Item 13.	Certain Relationships and Related Transactions, and Director Independence		51
Item 14.	Principal Accountant Fees and Services		52

	PART IV
Item 15.	Exhibits and Financial Statement Schedules		52

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 2004, 2005 and 2006.

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 4.8 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.

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 rates and services by companies providing transmission and distribution service, such as us, would continue to be rate 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 make sales of electric energy at retail or wholesale or own or operate 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 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.

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 much 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 70,500 megawatts (MW). There are only limited direct current interconnections between the ERCOT market and other power markets in the United States.

The ERCOT market operates under the reliability standards set by the North American Electric Reliability Council. 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 maintaining reliable operations of 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.

True-Up Proceeding

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 providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. We and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission’s rulings. The judgment would have 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. Oral arguments before the Texas 3rd Court of Appeals were held in January 2007, but a decision is not expected for several months. No amounts related to the district court’s judgment

have been recorded in our consolidated financial statements.

Among the issues raised in our appeal of the True-Up Order is the Texas Utility Commission’s reduction of our stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with our former electric generation assets. Such reduction was considered in our recording of an after-tax extraordinary loss of $977 million in the last half of 2004. We believe that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 related to those tax benefits. Those proposed regulations 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. In a May 2006 Private Letter Ruling (PLR) issued to a Texas utility on facts similar to ours, the IRS, without referencing its proposed regulations, ruled that a normalization violation would occur if ADITC and EDFIT were required to be returned to customers. We have requested a 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 a normalization violation. If the IRS determines that such reduction would cause a normalization violation with respect to the ADITC and the Texas Utility Commission’s order relating to such reduction is not reversed or otherwise modified, the IRS could require us 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, if a normalization violation with respect to EDFIT is deemed to have occurred and the Texas Utility Commission’s order relating to such reduction is not reversed or otherwise modified, 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. If a normalization violation should ultimately be found to exist, it could have a material adverse impact on our results of operations, financial condition and cash flows. However, we and CenterPoint Energy are vigorously pursuing the appeal of this issue and will seek other relief from the Texas Utility Commission to avoid a normalization violation. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.

Securitization

Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in August 2005 by a Travis County district court, in December 2005, one of our subsidiaries issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent 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.

Competition Transition Charge

In July 2005, we received an order from the Texas Utility Commission allowing us to implement a CTC designed to collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). The CTC Order authorizes us to impose a charge on REPs to recover the portion of the true-up balance not covered by the financing order. The CTC Order also allows 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.

seek further review from the Texas Supreme Court. All briefs in the appeal have been filed. Oral arguments were held in December 2006. Pending completion of judicial review and any action required by the Texas Utility Commission following a remand from the courts, the CTC remains in effect. The 11.075 percent 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. 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 impact 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 true-up 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 percent to a weighted average cost of capital of 8.06 percent. 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 per the settlement agreement discussed under “Rate Case” below.

During the years ended December 31, 2005 and 2006, we recognized approximately $19 million and $55 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31, 2005 and 2006, we recognized approximately $1 million and $13 million, respectively, of the allowed equity return not previously recorded. As of December 31, 2006, we had not recorded an allowed equity return of $234 million on our true-up balance because such return will be recognized as it is recovered in rates.

Refund of Environmental Retrofit Costs

The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to our former generation assets. The sale of our former generation assets was completed in early 2005. 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. The Texas Utility Commission will 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, we were notified by the successor in interest to our generation assets that, as of December 31, 2006, it had only spent 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 to the CTC, effective March 1, 2007. Such amounts are recorded in regulatory liabilities as of December 31, 2006. In February 2007, the Texas Utility Commission adopted the Staff’s recommendation for a slower procedural schedule than that requested by us. The current procedural schedule makes it unlikely that the proposed refund would be effective before May 1, 2007. At this time, we cannot predict whether any party will oppose our filing or whether the Texas Utility Commission will approve our request.

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 have 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. We have fully reserved for the disallowance and related interest accrual. A judgment was entered by a Travis County district court in May 2005 affirming the Texas Utility Commission’s decision. We filed an appeal to the Texas 3rd Court of Appeals in June 2005, and in April 2006, the Texas 3rd Court of Appeals issued a judgment affirming the Texas Utility Commission’s decision. We filed an appeal with the Texas Supreme Court in August 2006, and in October 2006, the Texas Supreme Court requested that the Texas Utility Commission and the City of Houston file written responses to our petition for review. Those responses were filed in January 2007. In February 2007, we filed an agreement with the Texas Supreme Court indicating that the parties had reached a settlement of the appeal. In order for the settlement to become final, the Texas Supreme Court must abate the pending appeal, and the Texas Utility Commission must issue a final order approving the settlement. If the Texas Utility Commission does not approve the agreement or modifies the agreement in a manner unacceptable to us, we would be entitled to ask the Texas Supreme Court to reinstate the appeal. If the Texas Utility Commission approves the agreement, the parties will

request the Texas Supreme Court to set aside the lower court decisions and remand the case for entry of an order approving that settlement. In March 2007, the Texas Supreme Court granted our request to abate the appeal. As of December 31, 2006, we have not recorded any amounts related to this decision.

Remand of 2001 Unbundled Cost of Service (UCOS) Order

The Texas 3rd Court of Appeals remanded to the Texas Utility Commission an issue that was decided by the Texas Utility Commission in our 2001 UCOS proceeding. In its remand order, the court ruled that the Texas Utility Commission had failed to adequately explain the basis for its determination of certain projected transmission capital expenditures. The Texas 3rd Court of Appeals ordered the Texas Utility Commission to reconsider that determination on the basis of the record that existed at the time of the Texas Utility Commission’s original order. In April 2006, the Texas Utility Commission opined orally that the rate base should be reduced by $57 million and instructed the Staff to quantify the effect on our rates. In the settlement of our rate case described below, the parties to the remand proceeding agreed to settle all issues that could be raised in the remand. Under the terms of that settlement, we implemented riders to our tariff rates under which we will provide rate credits to retail and wholesale customers for a total of approximately $8 million per year until a total of $32 million has been credited to customers under those tariff riders. Those riders became effective October 10, 2006. We reduced revenues and established a corresponding regulatory liability of $32 million in the second quarter of 2006 to reflect this obligation.

Rate Case

In September 2006, the Texas Utility Commission approved a settlement of a rate proceeding concerning our transmission and distribution service rates, which is discussed in “Regulation — State and Local Regulation — Rate Case.”

Customers

We serve nearly all of the Houston/Galveston metropolitan area. Our customers consist of 68 REPs, which sell electricity 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 creditworthiness criteria established by, the Texas Utility Commission. Two of the REPs in our service area are subsidiaries of Reliant Energy, Inc. (RRI). Sales to subsidiaries of RRI represented approximately 71%, 62% and 56% of our transmission and distribution revenues in 2004, 2005 and 2006, respectively. Our billed receivables balance from REPs as of December 31, 2006 was $140 million. Approximately 53% 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.

Distribution Automation (Intelligent Grid)

We are pursuing development and possible deployment of an electric distribution grid automation strategy with assistance from IBM 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 electric usage and the status of facilities on our system. Although this technology is still in the developmental stage, we believe it has the potential to enable a significant improvement in metering, grid planning, operations and maintenance of our 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. We are making a limited deployment of this technology to help in proving the technology and in validating its potential benefits prior to a full-scale implementation.

In addition to the utility applications discussed above, Intelligent Grid technology has the potential to improve the provision of data to the retail electric market in Texas to enable such enhancements as real-time pricing, real-time switching between REPs, and more timely connection and disconnection of customers. We anticipate that the Texas Utility Commission will implement guidelines for establishing minimum functionality requirements for the advanced meter in 2007, and that the Texas Utility Commission will provide a mechanism for timely recovery of costs of implementation. We will evaluate the outcome of the limited deployment and the regulatory mechanisms for cost recovery to assess what further expansions, if any, will be made later in 2007 and beyond.

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.

As of December 31, 2006, we had outstanding $2.0 billion aggregate principal amount of general mortgage bonds, including approximately $527 million held in trust to secure pollution control bonds for which 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, 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 $2.2 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, 2006. However, we are contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.

Electric Lines — Overhead. As of December 31, 2006, we owned 27,253 pole miles of overhead distribution lines and 3,603 circuit miles of overhead transmission lines, including 442 circuit miles operated at 69,000 volts, 2,084 circuit miles operated at 138,000 volts and 1,077 circuit miles operated at 345,000 volts.

Electric Lines — Underground. As of December 31, 2006, we owned 17,904 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, 2006, we owned 226 major substation sites having total installed rated transformer capacity of 50,647 megavolt amperes.

Service Centers. We operate 14 regional service centers located on a total of 304 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.

In June 2005, we accepted an ordinance granting us a new 30-year franchise to use the public rights-of-way to conduct our business in the City of Houston (New Houston Franchise Ordinance). The New Houston Franchise Ordinance took effect on July 1, 2005, and replaced the prior electricity franchise ordinance, which had been in effect since 1957. The New Houston Franchise Ordinance clarifies certain operational obligations of ours and the City of Houston and provides for streamlined payment and audit procedures and a two-year statute of limitations on claims for underpayment or overpayment under the ordinance. Under the prior electricity franchise ordinance, we paid annual franchise fees of $76.6 million to the City of Houston for the year ended December 31, 2004. For the twelve-month period ended June 30, 2006, the annual franchise fee under the New Houston Franchise Ordinance included a base amount of $88.1 million and an additional payment of $8.5 million. The base amount and the additional amount will be adjusted annually based on the increase, if any, in kilowatt-hours (kWh) delivered by us within the City of Houston. Pursuant to the New Houston Franchise Ordinance, the annual franchise fee will be reduced prospectively to reflect any portion of the annual franchise fee that is not included in our base rates in any subsequent rate case.

In connection with our most recent rate case and the settlement discussions related to that case, we offered to all of the cities in our service area an opportunity to adopt a new form of franchise (Settlement Franchise) containing terms similar to those in the New Houston Franchise Ordinance. This early renewal effort used a non-negotiable form of franchise and, except as necessary to comply with city charters, offered to all cities substantially equivalent terms and a single, simplified method of calculating and paying franchise fees. The Settlement Franchise was offered regardless of when any existing franchise was scheduled to expire. Of the 92 cities other than Houston in our service area, 60 have passed the Settlement Franchise. On December 31, 2006, we terminated our early renewal offer and will pursue new franchises with the remaining cities as their franchises near expiration.

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 Federal Energy Regulatory Commission (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 owned by us and other utilities within ERCOT. Under the legislation, the FERC is required to designate an Electric Reliability Organization (ERO) which will, under FERC oversight, promulgate standards 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 designated the North American Electric Reliability Council (NERC) as the ERO. Under the Energy Act the ERO may delegate authority to regional entities. Currently ERCOT is seeking FERC approval for an ERCOT division to be designated as the regional entity for the ERCOT region. The ERO currently is developing standards and the other aspects of the regulatory framework under the Energy Act. We do not anticipate that the transmission standards will have a material adverse impact on our operations. To the extent that we are required to make additional expenditures to comply with the ERO’s transmission 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.

Prior to repeal of the Public Utility Holding Company Act of 1935, as amended (1935 Act), effective February 8, 2006, CenterPoint Energy was a registered public utility holding company under the 1935 Act, and CenterPoint

Energy and its subsidiaries were subject to a comprehensive regulatory scheme imposed by the SEC under the 1935 Act. Although the SEC did not regulate rates and charges under the 1935 Act, it did regulate the structure, financing, lines of business and internal transactions of public utility holding companies and their system companies.

The Energy Act repealed the 1935 Act , and since that date, CenterPoint Energy and its subsidiaries have no longer been subject to restrictions imposed under the 1935 Act. The Energy Act includes a new Public Utility Holding Company Act of 2005 (PUHCA 2005) which grants to the FERC 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 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. We hold non-exclusive franchises from the incorporated municipalities in our service territory. In exchange for 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. As discussed above under “Business — Electric Transmission & Distribution — Franchises,” a new franchise ordinance for the City of Houston franchise was granted in June 2005 with a term of 30 years and 60 other cities have passed new franchise ordinances following a similar, standardized form.

All REPs in our service area pay the same rates and other charges for the same transmission and distribution services.

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. 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 (South Texas Project), 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.

Rate Case

In December 2005, the Texas Utility Commission ordered the commencement of a rate proceeding concerning the reasonableness of our existing rates for transmission and distribution service and required us to make a filing by April 15, 2006 to justify or change those rates. In April 2006, we filed cost data and other information that supported the rates then in effect.

In July 2006, we entered into a settlement agreement with the parties to the proceeding that resolved the issues raised in this matter. We filed a Stipulation and Agreement (Settlement Agreement) with the Texas Utility Commission in August 2006 to seek approval of the Settlement Agreement. In September 2006, the Texas Utility Commission issued its final order approving the Settlement Agreement. Revised base rates and other revised tariffs became effective in October 2006.

Under the terms of the Settlement Agreement, our base rate revenues were reduced by a net of approximately $58 million per year. Also, we agreed to increase our energy efficiency expenditures by an additional $10 million per year over the $13 million then included in rates. The expenditures will be made to benefit both residential and commercial customers. We also will fund $10 million per year for programs providing financial assistance to qualified low-income customers in our service territory.

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. This rate freeze is subject to adjustments for changes related to certain transmission costs, implementation of the Texas Utility Commission’s recently-adopted change to its CTC rule and certain other changes. The rate freeze does not apply to changes required to reflect the result of currently pending appeals of the True-Up Order, the pending appeal of the Texas Utility Commission’s order regarding our final fuel reconciliation, the appeal of the order implementing our CTC or the implementation of transition charges associated with current and future securitizations. In addition, we are not required to file annual earnings reports for the calendar years 2006 through 2008, but are required to file an earnings report for 2009 no later than March 1, 2010. 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 and certain cities with original jurisdiction notify us that such a filing is unnecessary.

Pursuant to the Settlement Agreement, in October 2006 we began amortizing expenditures of approximately $28 million related to Hurricane Rita over a seven-year period and regulatory expenses of approximately $7 million over a four-year period. Pursuant to the Settlement Agreement, the Texas Utility Commission determined that franchise fees payable by us under new franchise agreements with the City of Houston and certain other municipalities in our service area are deemed reasonable and necessary, along with the revised base rates.

The Settlement Agreement also resolved all issues that could be raised in the Texas Utility Commission’s proceeding to review its decision in our 2001 UCOS case discussed above under “Business — Electric Transmission & Distribution — Remand of 2001 Unbundled Cost of Service (UCOS) Order.”

These and other significant matters currently affecting our financial condition are further discussed in “Management’s Narrative Analysis of Results of Operations — Executive Summary — Significant Events in 2006” in Item 7 of this report.

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 or results of operations. 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.

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.

Nuclear Decommissioning Fund Collections

Pursuant to regulatory requirements and our tariff, we, as collection agent, collect from our transmission and distribution customers a nuclear decommissioning charge assessed with respect to our former 30.8% ownership interest in the South Texas Project, which we owned when we were part of an integrated electric utility. Amounts collected are transferred to nuclear decommissioning trusts maintained by the current owner of that interest in the South Texas Project. During 2004, 2005 and 2006, $2.9 million, $3.2 million and $3.1 million, respectively, was transferred. There are various investment restrictions imposed on owners of nuclear generating stations by the Texas Utility Commission and the U.S. Nuclear Regulatory Commission relating to nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and a final order of the Texas Utility Commission relating

to the 2005 transfer of ownership to Texas Genco LLC, now NRG, we and a subsidiary of NRG were, until July 1, 2006, jointly administering the decommissioning funds through the Nuclear Decommissioning Trust Investment Committee. On June 9, 2006, the Texas Utility Commission approved an application by us and an NRG subsidiary to name the NRG subsidiary as the sole fund administrator. As a result, we are no longer responsible for administration of decommissioning funds we collect as collection agent.

EMPLOYEES

As of December 31, 2006, we had 2,754 full-time employees, of which approximately 42% 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.

deny us the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. If a normalization violation should ultimately be found to exist, it could have an adverse impact on our results of operations, financial condition and cash flows. However, we and CenterPoint Energy are vigorously pursuing the appeal of this issue and will seek other relief from the Texas Utility Commission to avoid a normalization violation. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.

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 68 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. Reliant Energy, Inc. (RRI), through its subsidiaries, is our largest customer. Approximately 53% of our $140 million in billed receivables from REPs at December 31, 2006 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 Case” 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, 2006, we had $4.0 billion of outstanding indebtedness on a consolidated basis, which includes $2.4 billion of non-recourse transition bonds. Our future financing activities may depend, at least in part, on:

	•		the timing and amount of our recovery of the true-up components, including, in particular, the results of appeals to the courts of determination on 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 probable 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.

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, 2006, CenterPoint Energy and its subsidiaries other than us have approximately $875 million principal amount of debt required to be paid through 2009. This amount excludes amounts related to capital leases, transition bonds and indexed debt securities obligations. In addition, CenterPoint Energy has cash settlement obligations with respect to $575 million of outstanding 3.75% convertible notes on which holders could exercise their conversion rights during the first quarter of 2007 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, 2006 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 and our receivables 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%.

Risks Common to Our Business and Other Risks

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

	•		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 2005 and 2006, we paid dividends on our common shares of $537 million and $100 million, respectively, 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 3.86, 2.80, 2.20, 1.99 and 2.62 for the years ended December 31, 2002, 2003, 2004, 2005 and 2006, 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 4.8 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, Inc. (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 services are provided under tariffs approved by the Public Utility Commission of Texas (Texas Utility Commission).

Operations include construction and maintenance of electric transmission and distribution facilities, metering services, outage response services and other call center operations. Distribution services are provided under tariffs approved by the Texas Utility Commission.

EXECUTIVE SUMMARY

Significant Events in 2006

Debt Refinancing

In March 2006, we replaced our $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 45 basis points based on our current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. An additional utilization fee of 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to LIBOR fluctuates based on our credit rating.

Agreement regarding settlement of the Rate Case and the 2001 Unbundled Cost of Service (UCOS) Remand

In September 2006, the Texas Utility Commission gave final approval to a settlement agreement with the parties to the proceeding that resolved the issues raised in our 2006 rate case. Under the terms of the agreement, our base rate revenues were reduced by approximately $58 million per year. Also, we agreed to increase our energy efficiency expenditures by an additional $10 million per year over the $13 million then included in rates. The expenditures will be made to benefit both residential and commercial customers. We also will fund $10 million per year for programs providing financial assistance to qualified low-income customers in our service territory. The agreement provides for a rate freeze until June 30, 2010 under which we will not seek to increase our base rates and the other parties will not petition to decrease those rates.

The agreement also resolves all issues that could be raised in the Texas Utility Commission proceeding to review its decision in our 2001 UCOS case. Under the terms of the agreement, we added riders to our tariff rates under which we will provide rate credits to retail and wholesale customers for a total of approximately $8 million per year until a total of $32 million has been credited to customers under those tariff riders. We reduced revenues and established a corresponding regulatory liability for $32 million in the second quarter of 2006 to reflect this obligation.

Competition Transition Charge (CTC) Interest Rate Reduction

In January 2006, the Texas Utility Commission staff (Staff) proposed that the Texas Utility Commission adopt new rules governing the carrying charges on unrecovered true-up balances. In June 2006, the Texas Utility Commission adopted the revised rule as recommended by Staff. The rule, which applies to us, reduces the allowed interest rate on the unrecovered CTC balance prospectively from 11.075 percent to a weighted average cost of capital of 8.06 percent. The annualized impact on operating income is expected to be approximately $18 million per year for the first year with lesser impacts in subsequent years. In accordance with the agreement discussed above, we implemented the rule change effective August 1, 2006.

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 timing and amount of our recovery of the true-up components, including, in particular, the results of appeals to the courts of determinations on rulings obtained to date;

	•		state and federal legislative and regulatory actions or developments, including deregulation, re-regulation, changes in or application of laws or regulations applicable to other 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;

	•		changes in interest rates or rates of inflation;

	•		weather variations and other natural phenomena;

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

	•		actions by rating agencies;

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

	•		the ability of RRI to satisfy its 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 cannot be assured to be completed or beneficial to us; and

	•		other factors we discuss under “Risk Factors” in Item 1A of this report.

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, 2004, 2005 and 2006, 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,
	2004			2005			2006
	(In millions,
	except throughput and customer data)
Revenues:
Electric transmission and distribution utility	$	1,446		$	1,538		$	1,516
Transition bond companies ⁽¹⁾		75			106			265

Total Revenues		1,521			1,644			1,781

Expenses:
Operation and maintenance, excluding transition bond companies		539			618			611
Depreciation and amortization, excluding transition bond companies		248			258			243
Taxes other than income taxes		203			214			212
Transition bond companies ⁽¹⁾		37			67			139

Total Expenses		1,027			1,157			1,205

Operating Income		494			487			576
Interest and other finance charges		(307	)		(288	)		(110	)
Interest on transition bonds ⁽¹⁾		(38	)		(40	)		(130	)
Return on true-up balance		226			121			—
Other Income, net		44			51			67

Income Before Income Taxes and Extraordinary Item		419			331			403
Income Tax Expense		137			108			132

Income Before Extraordinary Item		282			223			271
Extraordinary Item, net of tax		(977	)		30			—

Net Income (Loss)	$	(695	)	$	253		$	271


Throughput (in gigawatt-hours (GWh)):
Residential		23,748			24,924			23,955
Total		73,632			74,189			75,877

Average number of metered customers:
Residential		1,639,488			1,683,100			1,732,656
Total		1,862,853			1,912,346			1,968,114


(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-.

2006 Compared to 2005. We reported operating income of $576 million for 2006, consisting of $450 million for the regulated electric transmission and distribution utility (TDU) (including $55 million arising from the CTC) and $126 million related to the transition bonds. For 2005, operating income totaled $487 million, consisting of $448 million for the TDU (including $19 million arising from the CTC) and $39 million related to the transition bonds. Increases in operating income from customer 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), the implementation of reduced base rates ($13 million) and spending on low income assistance and energy efficiency programs ($5 million) resulting from the Settlement Agreement described in “Business — Regulation — State and Local Regulation — Rate Case” in Item 1 of this report. In addition, the TDU’s operating income for 2006 includes the $32 million adverse impact of the resolution of the remand of the 2001 UCOS order recorded in the second quarter.

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 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.

2005 Compared to 2004. We reported operating income of $487 million for 2005, consisting of $448 million for the TDU and $39 million related to the transition bonds. For 2004, operating income totaled $494 million, consisting of $456 million for the TDU and $38 million for the transition bonds. Operating revenues increased primarily due to increased usage resulting from warmer weather ($13 million), continued customer growth ($33 million) with the addition of 61,000 metered customers in 2005, recovery of our 2004 true-up balance not covered by the transition bond financing order ($21 million) and higher transmission cost recovery ($13 million). The increase in operating revenues was more than offset by higher transmission costs ($24 million), the absence of a gain from a land sale recorded in 2004 ($11 million), the absence of a $15 million partial reversal of a reserve related to the final fuel reconciliation recorded in 2004, increased employee-related expenses ($20 million) and higher tree trimming expense ($6 million), partially offset by a decrease in pension expense ($14 million). Depreciation and amortization expense increased ($10 million) primarily as a result of higher plant balances. Taxes other than income taxes increased ($11 million) primarily due to higher franchise fees paid to the City of Houston.

Net income for 2005 included an after-tax extraordinary gain of $30 million recorded in the second quarter reflecting an adjustment to the after-tax extraordinary loss of $977 million recorded in the last half of 2004 to write down generation-related regulatory assets as a result of the final orders issued by the Texas Utility Commission.

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.

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 2007 include approximately $408 million of capital expenditures and $147 million of scheduled 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 2006 and estimates of our capital requirements for 2007 through 2011 (in millions):


2006	$	389
2007		408
2008		406
2009		402
2010		437
2011		435

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


									2012 and
Contractual Obligations	Total		2007		2008-2009		2010-2011		thereafter
Transition bond debt, including current portion⁽¹⁾	$	2,407	$	147	$	334	$	397	$	1,529
Other long-term debt, including current portion		1,593		—		—		—		1,593
Interest payments — transition bond debt ^{(1) (2)}		867		123		224		187		333
Interest payments — other long-term debt ⁽²⁾		1,330		95		191		191		853
Capital leases		1		—		—		—		1
Operating leases ⁽³⁾		10		6		4		—		—
Benefit obligations ⁽⁴⁾		—		—		—		—		—

Total contractual cash obligations	$	6,208	$	371	$	753	$	775	$	4,309


(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, 2006; 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 $10 million to our postretirement benefits plan in 2007 to fund a portion of our obligations in accordance with rate orders or to fund pay-as-you-go costs associated with the plan.

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 March 2006, we replaced our $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of LIBOR plus 45 basis points based on our current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. 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 10 basis points applies to borrowings any time more than 50% of the facility is utilized, and the spread to LIBOR fluctuates 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 28, 2007, we had no borrowings and approximately $4 million of outstanding letters of credit under the credit facility.

Temporary Investments. As of February 28, 2007, 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 28, 2007, we had borrowings from the money pool aggregating $147 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 February 28, 2007. Amounts are expressed in millions.


Year	Third-Party		Affiliate		Sub-Total		Transition Bonds			Total
2007	$	—	$	—	$	—	$	95	⁽¹⁾	$	95
2008		—		—		—		159			159
2009		—		—		—		175			175
2010		—		—		—		190			190
2011		—		—		—		207			207
2012		46		—		46		227			273
2013		450		—		450		245			695
2014		300		—		300		147			447
2015		—		151		151		158			309
2016		—		—		—		169			169
2017		127		—		127		181			308
2018		—		—		—		194			194
2019		—		—		—		208			208
2021		102		—		102		—			102
2023		200		—		200		—			200
2027		56		—		56		—			56
2033		312		—		312		—			312

Total	$	1,593	$	151	$	1,744	$	2,355		$	4,099


(1)		This amount reflects a principal payment of $52 million in February 2007 by Bond Company II.

As of February 28, 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 the		for CenterPoint
	to Third Parties		Company’s 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 $2.2 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, 2006. 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.


			General Mortgage
Year	First Mortgage Bonds		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, 2006, Bond Company had $575 million aggregate principal amount of outstanding transition bonds that were issued in 2001 in accordance with the Texas electric restructuring law. At December 31, 2006, Bond Company II had $1.83 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 28, 2007, Moody’s Investors Service, Inc. (Moody’s), Standard & Poor’s Ratings Services, a division of The McGraw Hill Companies (S&P), and Fitch, Inc. (Fitch) had assigned the following credit ratings to our senior debt.

Moody’s

S&P

Fitch

Instrument

Rating

Outlook⁽¹⁾

Rating

Outlook ⁽²⁾

Rating

Outlook ⁽³⁾

Senior Secured Debt (First Mortgage Bonds)

Baa2

Stable

BBB

Stable

A-

Stable


(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 February 28, 2007, CenterPoint Energy had issued six series of senior notes aggregating $1.4 billion in principal amount 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 are contractually prohibited, subject to certain exceptions, from issuing additional first mortgage bonds.

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 $304 million of recoverable electric generation-related regulatory assets as of December 31, 2006. 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 the second quarter of 2005 related to the regulatory asset. Additionally, a district court in Travis County, Texas issued a judgment that would have the effect of restoring approximately $650 million, plus interest, of disallowed costs. We and other parties appealed the district court judgment. Oral arguments before the Texas 3rd Court of Appeals were held in January 2007, but a decision is not expected for several months. No amounts related to the district court’s judgment have been recorded in our consolidated financial statements.

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, 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 Interpretation No. 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, 2006, our estimated cost of retiring these assets was approximately $18 million.

Unbilled Energy Revenues

Revenues related to the delivery of electricity are generally recorded when electricity is delivered to customers. However, the determination of electricity 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, amounts of electricity delivered 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 Plan. As discussed in Note 2(m) to the consolidated financial statements, we participate in CenterPoint Energy’s qualified non-contributory pension plan covering substantially all employees. Pension expense for 2007 is estimated to be $1 million based on an expected return on plan assets of 8.5% and a discount rate of 5.85% as of December 31, 2006. Pension expense for the year ended December 31, 2006 was $10 million. Future changes in plan asset returns, assumed discount rates and various other factors related to the pension 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

We have outstanding long-term debt, which subjects us to the risk of loss associated with movements in market interest rates.

We had no floating-rate obligations at December 31, 2005 and 2006 except for $68 million and $117 million, respectively, of money pool borrowings from our parent.

At December 31, 2005 and 2006, we had outstanding fixed-rate debt aggregating $4.2 billion and $4.1 billion, respectively, in principal amount and having a fair value of approximately $4.3 billion in both 2005 and 2006. 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 $167 million if interest rates were to decline by 10% from their levels at December 31, 2006. 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) as of December 31, 2006 and 2005, and the related consolidated statements of operations, cash flows and member’s equity for each of the three years in the period ended December 31, 2006. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of CenterPoint Energy Houston Electric, LLC and subsidiaries at December 31, 2006 and 2005, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2006, 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 9, 2007

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

STATEMENTS OF CONSOLIDATED OPERATIONS


	Year Ended December 31,
	2004			2005			2006
	(In Millions)

Revenues	$	1,521		$	1,644		$	1,781


Expenses:
Operation and maintenance		541			621			614
Depreciation and amortization		283			322			379
Taxes other than income taxes		203			214			212

Total		1,027			1,157			1,205


Operating Income		494			487			576


Other Income (Expense):
Interest and other finance charges		(307	)		(288	)		(110	)
Interest on transition bonds		(38	)		(40	)		(130	)
Return on true-up balance		226			121			—
Other, net		44			51			67

Total		(75	)		(156	)		(173	)


Income Before Income Taxes and Extraordinary Item		419			331			403
Income Tax Expense		137			108			132


Income Before Extraordinary Item		282			223			271
Extraordinary Item, net of tax		(977	)		30			—


Net Income (Loss)	$	(695	)	$	253		$	271

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,
	2005		2006
	(In Millions)
ASSETS
Current Assets:
Cash and cash equivalents	$	40	$	122
Accounts and notes receivable, net		150		165
Accounts and notes receivable—affiliated companies		—		49
Accrued unbilled revenues		108		95
Inventory		60		63
Taxes receivable		—		34
Deferred tax asset		1		—
Other		34		69

Total current assets		393		597

Property, Plant and Equipment, net		4,077		4,257

Other Assets:
Regulatory assets		2,902		2,820
Notes receivable—affiliated companies		750		750
Other		105		39

Total other assets		3,757		3,609

Total Assets	$	8,227	$	8,463

LIABILITIES AND MEMBER’S EQUITY
Current Liabilities:
Current portion of long-term debt	$	73	$	147
Accounts payable		57		72
Accounts and notes payable—affiliated companies		79		141
Taxes accrued		139		105
Interest accrued		50		85
Other		43		67

Total current liabilities		441		617

Other Liabilities:
Accumulated deferred income taxes, net		1,400		1,341
Unamortized investment tax credits		42		35
Benefit obligations		139		197
Regulatory liabilities		294		336
Notes payable—affiliated companies		151		151
Other		44		53

Total other liabilities		2,070		2,113

Long-Term Debt		3,998		3,851

Commitments And Contingencies (Note 7)
Member’s Equity		1,718		1,882

Total Liabilities and Member’s Equity	$	8,227	$	8,463

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,
	2004			2005			2006
				(In Millions)

Cash Flows from Operating Activities:
Net income (loss)	$	(695	)	$	253		$	271
Extraordinary item, net of tax		977			(30	)		—

Income before extraordinary item		282			223			271
Adjustments to reconcile income before extraordinary item to net cash provided by operating activities:
Depreciation and amortization		283			322			379
Deferred income taxes		86			123			(69	)
Amortization of deferred financing costs		31			31			12
Investment tax credit		(7	)		(7	)		(7	)
Changes in other assets and liabilities:
Accounts and notes receivable, net		(36	)		(59	)		14
Accounts receivable/payable, affiliates		39			61			(36	)
Taxes receivable		235			(79	)		(6	)
Inventory		3			(7	)		(3	)
Accounts payable		4			6			8
Interest and taxes accrued		25			16			1
Net regulatory assets and liabilities		(518	)		(181	)		56
Clawback payment from RRI		177			—			—
Other current assets		2			(10	)		(2	)
Other current liabilities		(6	)		(15	)		17
Other assets		(2	)		(3	)		9
Other liabilities		(35	)		(17	)		17
Other, net		—			—			(6	)

Net cash provided by operating activities		563			404			655

Cash Flows from Investing Activities:
Capital expenditures		(226	)		(267	)		(381	)
Decrease in notes receivable from affiliates		—			73			—
Increase in restricted cash of transition bond companies		—			(12	)		(32	)
Other, net		—			—			1

Net cash used in investing activities		(226	)		(206	)		(412	)

Cash Flows from Financing Activities:
Proceeds from long-term debt		229			3,161			—
Payments of long-term debt		(42	)		(2,668	)		(74	)
Increase (decrease) in short-term notes payable with affiliates		(186	)		68			49
Decrease in long-term payable with affiliates		(229	)		(303	)		—
Debt issuance costs		(16	)		(16	)		—
Contribution from (to) parent		—			113			(36	)
Dividend to parent		(100	)		(537	)		(100	)
Other, net		1			(1	)		—

Net cash used in financing activities		(343	)		(183	)		(161	)


Net Increase (Decrease) in Cash and Cash Equivalents		(6	)		15			82
Cash and Cash Equivalents at Beginning of the Year		31			25			40

Cash and Cash Equivalents at End of the Year	$	25		$	40		$	122

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	315		$	319		$	198
Income taxes (refunds)		(74	)		155			304
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


	2004					2005					2006
	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				2,190					2,278					1,719
Contribution from (to) parent				113					(28	)				(8	)
Dividend to parent				—					(528	)				—
Other				(25	)				(3	)				1

Balance, end of year				2,278					1,719					1,712

Retained Earnings (Deficit)
Balance, beginning of year				550					(245	)				(1	)
Net income (loss)				(695	)				253					271
Dividend to parent				(100	)				(9	)				(100	)

Balance, end of year				(245	)				(1	)				170

Total Member’s Equity			$	2,033				$	1,718				$	1,882

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 created on August 31, 2002 as part of a corporate restructuring of Reliant Energy, Incorporated (Reliant Energy) that implemented certain requirements of the 1999 Texas Electric Choice Law (Texas electric restructuring law).

(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)		2005			2006
			(In millions)
Transmission		37	$	1,327		$	1,427
Distribution		25		4,453			4,643
Other		17		683			753

Total				6,463			6,823
Accumulated depreciation				(2,386	)		(2,566	)

Property, plant and equipment, net			$	4,077		$	4,257

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, 2005 and 2006:


	December 31,
	2005			2006
	(In millions)
Recoverable electric generation-related regulatory assets (1)	$	332		$	304
Securitized regulatory asset		2,420			2,285
Unamortized loss on reacquired debt		91			85
Pension and postretirement related regulatory asset (2)		—			60
Other long-term regulatory assets/liabilities		21			23

Subtotal		2,864			2,757
Estimated removal costs		(256	)		(273	)

Total	$	2,608		$	2,484


(1)		Excludes $248 million and $234 million of allowed equity return on the true-up balance as of December 31, 2005 and 2006, respectively.

(2)		Upon adoption of SFAS No. 158, “Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans — An Amendment of FASB Statements No. 87, 88, 106 and 132(R)” (SFAS No. 158), the Company recorded a regulatory asset for its unrecognized costs because it has historically recovered and currently recovers pension and postretirement expenses in rates. See Note 2(l).

If events were to occur that would make the recovery of these assets and liabilities no longer probable, the Company would be required to write off or write down these regulatory assets and liabilities. During 2004, the Company wrote off net regulatory assets of $1.5 billion ($977 million after-tax) as an extraordinary loss in response to the Texas Utility Commission’s order 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, 2005 and 2006, these removal costs of $256 million and $273 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. At December 31, 2005 and 2006, the Company had recorded asset retirement obligations of $11 million and $18 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. Other amortization expense includes amortization of regulatory assets and other intangibles.

The following table presents depreciation and amortization expense for 2004, 2005 and 2006:


	Year Ended December 31,
	2004		2005		2006
	(In millions)
Depreciation expense	$	229	$	237	$	245
Amortization expense of transition bond companies		35		65		135
Other amortization expense		19		20		(1	)

Total depreciation and amortization	$	283	$	322	$	379

(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 through depreciation provisions included in rates. AFUDC is capitalized as a component of projects under construction and will be amortized over the assets’ estimated useful lives. During 2004, 2005 and 2006, the Company capitalized AFUDC of $2 million, $3 million and $4 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 liability method of accounting for deferred income taxes and measures deferred income taxes for all significant income tax temporary differences in accordance with SFAS No. 109, “Accounting for Income Taxes,” (SFAS No. 109). 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. Management evaluates uncertain tax positions and accrues for those which management believes are probable of an unfavorable outcome. 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 $5 million and $1 million at December 31, 2005 and 2006, respectively. The provision for doubtful accounts in the Company’s Statements of Consolidated Operations for 2004, 2005 and 2006 was $1 million, $3 million and $(2) million, respectively.

(j) Inventory

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

(k) Statements of Consolidated Cash Flows

For purposes of reporting cash flows, the Company considers cash equivalents to be short-term, highly liquid investments with maturities of three months or less from the date of purchase. In connection with the issuance of transition bonds in October 2001 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 $17 million and $49 million at December 31, 2005 and 2006, respectively. For additional information regarding the December 2005 securitization financing, see Notes 3(a) and 5. Cash and cash equivalents includes $40 million and $123 million at December 31, 2005 and 2006, respectively, that is held by the Company’s transition bond subsidiaries for their operations related to servicing the transition bonds.

(l) New Accounting Pronouncements

In July 2006, the FASB issued FIN No. 48, “Accounting for Uncertainty in Income Taxes— An Interpretation of FASB Statement No. 109” (FIN 48). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. FIN 48 also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. The Company estimates the cumulative effect of adopting FIN 48 to be immaterial to the consolidated financial statements.

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 does not expect the adoption of this statement to have a material impact on its financial position, results of operations and cash flows.

In September 2006, the FASB issued SFAS No. 158. SFAS No. 158 requires the Company, as the sponsor of a plan, to (a) recognize on its Balance Sheets as an asset a plan’s over-funded status or as a liability such plan’s underfunded status, (b) measure a plan’s assets and obligations as of the end of the Company’s fiscal year and (c) recognize changes in the funded status of its plans in the year in which changes occur through adjustments to other comprehensive income. Additional minimum liabilities are also derecognized upon adoption of the new standard. The Company adopted SFAS No. 158 as of December 31, 2006. The following table summarizes the effect of the adjustments to record the adoption of SFAS No. 158:


	Before Adoption		Change due to		After Adoption of
	of SFAS No. 158		SFAS No. 158		SFAS No. 158

Other Assets:
Regulatory asset	$	—	$	60	$	60

Other Liabilities:
Benefit obligations		96		60		156

Upon adoption of SFAS No. 158, the Company recorded a regulatory asset for its unrecognized costs because it has historically recovered and currently recovers pension and postretirement expenses in rates. The adoption of SFAS No. 158 did not impact the Company’s compliance with debt covenants.

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statements 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. The Company does not expect the adoption of this statement to 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 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 $23 million, $9 million and $10 million for the years ended December 31, 2004, 2005 and 2006, respectively.

In addition to the 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, 2004, 2005 and 2006.

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 $12 million, $13 million and $12 million for the years ended December 31, 2004, 2005 and 2006, 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.

In January 2005, the Department of Health and Human Services’ Centers for Medicare and Medicaid Services released final regulations governing the Medicare prescription drug benefit and other key elements of the Medicare Modernization Act. Under the final regulations, a greater portion of benefits offered under CenterPoint Energy’s plans meets the definition of actuarial equivalence and therefore qualifies for federal subsidies equal to 28% of allowable drug costs. As a result, the Company has remeasured its obligations and costs to take into account the new regulations. The Medicare subsidy reduced net periodic postretirement benefit costs by approximately $2 million and $7 million for 2005 and 2006, respectively.

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,
	2004			2005			2006
	(In millions)
Service cost— benefits earned during the period	$	1		$	1		$	1
Interest cost on projected benefit obligation		16			17			16
Expected return on plan assets		(10	)		(11	)		(11	)
Amortization of transition obligation		9			6			6

Net postretirement benefit cost	$	16		$	13		$	12

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


	Year Ended December 31,
	2004			2005			2006
Discount rate		6.25	%		5.75	%		5.70	%
Expected return on plan assets		8.50	%		8.00	%		8.50	%

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 2005 and 2006. The measurement dates for plan assets and obligations were December 31, 2005 and 2006.


	Year Ended December 31,
	2005			2006
	(In millions)
Change in Benefit Obligation
Accumulated benefit obligation, beginning of year	$	316		$	296
Service cost		1			1
Interest cost		17			16
Benefits paid		(17	)		(19	)
Participant contributions		1			1
Plan amendment		—			1
Actuarial gain		(22	)		(2	)

Accumulated benefit obligation, end of year	$	296		$	294

Change in Plan Assets
Plan assets, beginning of year	$	135		$	134
Benefits paid		(17	)		(19	)
Employer contributions		9			9
Participant contributions		1			1
Actual investment return		6			13

Plan assets, end of year	$	134		$	138

Reconciliation of Funded Status
Funded status	$	(162	)	$	(156	)
Unrecognized transition obligation		51			—
Unrecognized prior service cost		(4	)		—
Unrecognized actuarial loss		22			—

Net amount recognized in balance sheets	$	(93	)	$	(156	)

Actuarial Assumptions
Discount rate		5.70	%		5.85	%
Expected long-term return on assets		8.50	%		8.00	%
Healthcare cost trend rate assumed for the next year		9.00	%		7.00	%
Prescription drug cost trend rate assumed for the next year		—			13.00	%
Rate to which the cost trend rate is assumed to decline (ultimate trend rate)		5.50	%		5.50	%
Year that the rate reaches the ultimate trend rate		2011			2014

The Company does not have amounts recognized in accumulated other comprehensive income as of December 31, 2005 and 2006 related to its postretirement benefit plans. As of December 31, 2005, unrecognized costs were included as a component of benefits obligations. Upon the adoption of SFAS No. 158 as of December 31, 2006, unrecognized costs were recorded a regulatory asset because it has historically recovered and currently recovers postretirement expenses in rates. For additional background relating to the accounting pronouncement and its impacts, see Note 2(l).

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		14		11
Effect on total of service and interest cost	$	1	$	1

The following table displays the weighted average asset allocations as of December 31, 2005 and 2006 for the Company’s postretirement benefit plans:


	December 31,
	2005			2006
Domestic equity securities		30	%		31	%
International equity securities		10			12
Debt securities		60			57

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 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.

The Company expects to contribute $10 million to its postretirement benefits plan in 2007. The following benefit payments are expected to be paid by the postretirement benefit plan (in millions):


	Postretirement Benefit Plan
			Medicare
	Benefit Payments		Subsidy Receipts
2007	$	21	$	(3	)
2008		22		(3	)
2009		23		(3	)
2010		24		(4	)
2011		25		(4	)
2012-2016		134		(20	)

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 $3 million, $5 million and $2 million in 2004, 2005 and 2006, respectively.

Included in “Benefit Obligations” in the accompanying consolidated balance sheets at December 31, 2005 and 2006 was $20 million each year 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 2004, 2005 and 2006, the Company recorded benefit expense relating to these programs of $2 million, $2 million and $1 million, respectively.

Included in “Benefit Obligations” in the accompanying Consolidated Balance Sheets at December 31, 2005 and 2006 was $21 million and $18 million, respectively, relating to deferred compensation plans.

(n) Other Current Assets and Liabilities

Included in other current assets on the Consolidated Balance Sheets at December 31, 2005 and 2006 was $17 million and $49 million, respectively, of restricted cash related to the transition bond companies. Included in other current liabilities on the Consolidated Balance Sheets at December 31, 2005 and 2006 was $4 million and $36 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 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 providing for adjustment of the amount to be recovered to include interest on the balance until recovery, the principal portion of additional excess mitigation credits returned to customers after August 31, 2004 and certain other matters. The Company and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, the court issued its final judgment on the various appeals. In its judgment, the court affirmed most aspects of the True-Up Order, but reversed two of the Texas Utility Commission’s rulings. The judgment would have the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from the Company’s initial request. The Company and other parties appealed the district court’s judgment. Oral arguments before the Texas 3rd Court of Appeals were held in January 2007, but a decision is not expected for several months. No amounts related to the district court’s judgment have been recorded in the Company’s consolidated financial statements.

Among the issues raised in the Company’s appeal of the True-Up Order is the Texas Utility Commission’s reduction of the Company’s stranded cost recovery by approximately $146 million for the present value of certain deferred tax benefits associated with its former electric generation assets. Such reduction was considered in the Company’s recording of an after-tax extraordinary loss of $977 million in the last half of 2004. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 related to those tax benefits. Those proposed regulations 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. In a May 2006 Private Letter Ruling (PLR) issued to a Texas utility on facts similar to the Company’s, the IRS, without referencing its proposed regulations, ruled that a normalization violation would occur if ADITC and EDFIT were required to be returned to customers. The Company has requested a 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 a normalization violation. If the IRS determines that such reduction would cause a normalization violation with respect to the ADITC and the Texas Utility Commission’s order relating to such

reduction is not reversed or otherwise modified, 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, if a normalization violation with respect to EDFIT is deemed to have occurred and the Texas Utility Commission’s order relating to such reduction is not reversed or otherwise modified, 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. If a normalization violation should ultimately be found to exist, it could have a material adverse impact on the Company’s results of operations, financial condition and cash flows. However, the Company and CenterPoint Energy are vigorously pursuing the appeal of this issue and will seek other relief from the Texas Utility Commission to avoid a normalization violation. The Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation.

Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in August 2005 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 percent to 5.30 percent 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 competition transition charge (CTC) designed to collect approximately $596 million over 14 years plus interest at an annual rate of 11.075 percent (CTC Order). The CTC Order authorizes the Company to impose a charge on retail electric providers to recover the portion of the true-up balance not covered by the financing order. The CTC Order also allows 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 on the grounds that the Texas Supreme Court had previously invalidated that entire section of the rule. 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 the Company’s 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 3rd Court of Appeals, and if required, plan to seek further review from the Texas Supreme Court. All briefs in the appeal have been filed. Oral arguments were held in December 2006. Pending completion of judicial review and any action required by the Texas Utility Commission following a remand from the courts, the CTC remains in effect. The 11.075 percent 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. 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 the Company’s financial condition, results of operations or cash flows.

In June 2006, the Texas Utility Commission adopted the revised rule governing the carrying charges on unrecovered true-up 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 percent to a weighted average cost of capital of 8.06 percent. 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 per the settlement agreement discussed in Note 3(e) below under “Rate Case”.

During the years ended December 31, 2005 and 2006, the Company recognized approximately $19 million and $55 million, respectively, in operating income from the CTC. Additionally, during the years ended December 31,

2005 and 2006, the Company recognized approximately $1 million and $13 million, respectively, of the allowed equity return not previously recorded. As of December 31, 2006, the Company had not recorded an allowed equity return of $234 million on its true-up balance because such return will be recognized as it is recovered in rates.

(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 has 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. The Company has fully reserved for the disallowance and related interest accrual. A judgment was entered by a Travis County district court in May 2005 affirming the Texas Utility Commission’s decision. The Company filed an appeal to the Texas 3rd Court of Appeals in June 2005, and in April 2006, the Texas 3rd Court of Appeals issued a judgment affirming the Texas Utility Commission’s decision. The Company filed an appeal with the Texas Supreme Court in August 2006, and in October 2006, the Texas Supreme Court requested that the Texas Utility Commission and the City of Houston file written responses to the Company’s petition for review. Those responses were filed in January 2007. In February 2007, the Company filed an agreement with the Texas Supreme Court indicating that the parties had reached a tentative settlement of the appeal. In order for the settlement to become final, the Texas Supreme Court must abate the pending appeal, and the Texas Utility Commission must issue a final order approving the settlement. If the Texas Utility Commission does not approve the agreement or modifies the agreement in a manner unacceptable to the Company, the Company would be entitled to ask the Texas Supreme Court to reinstate the appeal. If the Texas Utility Commission approves the agreement, the parties will request the Texas Supreme Court to set aside the lower court decisions and remand the case for entry of an order approving that settlement. In March 2007, the Texas Supreme Court granted the Company’s request to abate the appeal. As of December 31, 2006, the Company has not recorded any amounts related to this decision.

(c) Remand of 2001 Unbundled Cost of Service Order

The Texas 3rd Court of Appeals remanded to the Texas Utility Commission an issue that was decided by the Texas Utility Commission in the Company’s 2001 UCOS proceeding. In its remand order, the court ruled that the Texas Utility Commission had failed to adequately explain the basis for its determination of certain projected transmission capital expenditures. The Texas 3rd Court of Appeals ordered the Texas Utility Commission to reconsider that determination on the basis of the record that existed at the time of the Texas Utility Commission’s original order. In April 2006, the Texas Utility Commission opined orally that the rate base should be reduced by $57 million and instructed the Staff to quantify the effect on the Company’s rates. In the settlement of the Company’s rate case described in Note 3(e) below, the parties to the remand proceeding agreed to settle all issues that could be raised in the remand. Under the terms of that settlement, the Company implemented riders to its tariff rates under which it will provide rate credits to retail and wholesale customers for a total of approximately $8 million per year until a total of $32 million has been credited to customers under those tariff riders. Those riders became effective October 10, 2006. The Company reduced revenues and established a corresponding regulatory liability of $32 million in the second quarter of 2006 to reflect this obligation.

(d) Refund of Environmental Retrofit Costs

The True-Up Order allowed recovery of approximately $699 million of environmental retrofit costs related to the Company’s former generation assets. The sale of the Company’s former generation assets was completed in early 2005. 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. The Texas Utility Commission will 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, CenterPoint Energy was notified by the successor in interest to the Company’s generation assets that, as of December 31, 2006, it had only spent 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 to the CTC, effective March 1, 2007. Such amounts are recorded in regulatory liabilities as of December 31, 2006. In February 2007, the Texas Utility Commission adopted the Staff’s recommendation for a slower procedural schedule than that requested by the Company. The procedural schedule as

proposed by the Staff would make it unlikely that the proposed refund would be effective before May 1, 2007. At this time, the Company cannot predict whether any party will oppose its filing or whether the Texas Utility Commission will approve its request.

(e) Rate Case

In December 2005, the Texas Utility Commission ordered the commencement of a rate proceeding concerning the reasonableness of the Company’s existing rates for transmission and distribution service and required the Company to make a filing by April 15, 2006 to justify or change those rates. In April 2006, the Company filed cost data and other information that supported the rates then in effect.

In July 2006, the Company entered into a settlement agreement with the parties to the proceeding that resolved the issues raised in this matter. The Company filed a Stipulation and Agreement (Settlement Agreement) with the Texas Utility Commission in August 2006 to seek approval of the Settlement Agreement. In September 2006, the Texas Utility Commission issued its final order approving the Settlement Agreement. Revised base rates and other revised tariffs became effective in October 2006.

Under the terms of the Settlement Agreement, the Company’s base rate revenues were reduced by a net of approximately $58 million per year. Also, the Company agreed to increase its energy efficiency expenditures by an additional $10 million per year over the $13 million then included in rates. The expenditures will be made to benefit both residential and commercial customers. The Company also will fund $10 million per year for programs providing financial assistance to qualified low-income customers in its service territory.

The Settlement Agreement provides that until June 30, 2010 the Company will not seek to increase its base rates and the other parties will not petition to decrease those rates. This rate freeze is subject to adjustments for changes related to certain transmission costs, implementation of the Texas Utility Commission’s recently-adopted change to its CTC rule and certain other changes. The rate freeze does not apply to changes required to reflect the result of currently pending appeals of the True-Up Order, the pending appeal of the Texas Utility Commission’s order regarding the Company’s final fuel reconciliation, the appeal of the order implementing the Company’s CTC or the implementation of transition charges associated with current and future securitizations. In addition, the Company is not required to file annual earnings reports for the calendar years 2006 through 2008, but is required to file an earnings report for 2009 no later than March 1, 2010. The Company must make a new base rate filing not later than June 30, 2010, based on a test year ended December 31, 2009, unless the Texas Utility Commission staff and certain cities with original jurisdiction notify the Company that such a filing is unnecessary.

Pursuant to the Settlement Agreement, in October 2006 the Company began amortizing expenditures of approximately $28 million related to Hurricane Rita over a seven-year period and regulatory expenses of approximately $7 million over a four-year period. Pursuant to the Settlement Agreement, the Texas Utility Commission determined that franchise fees payable by the Company under new franchise agreements with the City of Houston and certain other municipalities in its service area are deemed reasonable and necessary, along with the revised base rates.

The Settlement Agreement also resolves all issues that could be raised in the Texas Utility Commission’s proceeding to review its decision in the Company’s 2001 UCOS case. See Note 3(c) above.

(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’s money pool borrowings of $117 million at December 31, 2006 had a weighted average interest rate of 5.37%.

At December 31, 2005 and 2006, the Company had a $750 million note receivable from its parent, which bears interest at prime, 8.25% at December 31, 2006.

For the years ended December 31, 2004, 2005 and 2006, the Company had net interest income related to affiliate borrowings of $18 million, $42 million and $50 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 $102 million, $110 million and $112 million in 2004, 2005 and 2006, 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 benefit (expense) of $113 million, ($28) million and ($8) million for 2004, 2005 and 2006, respectively, which was recorded in additional paid-in capital.

In 2004, 2005 and 2006, the Company paid a dividend of $100 million, $537 million and $100 million, respectively.

(b) Major Customers

During 2004, 2005 and 2006, revenues derived from energy delivery charges provided by the Company to subsidiaries of Reliant Energy, Inc. (RRI) totaled $882 million, $812 million and $737 million, respectively.

(5) Long-term Debt


	December 31, 2005					December 31, 2006
	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		2,407			73		2,260			147
Other		(2	)		—		(2	)		—

Total long-term debt	$	3,998		$	73	$	3,851		$	147


(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, 2005 and 2006. 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.

In March 2006, the Company replaced its $200 million five-year revolving credit facility with a $300 million five-year revolving credit facility. The facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 45 basis points based on the Company’s current credit ratings, as compared to LIBOR plus 75 basis points for borrowings under the facility it replaced. The facility contains covenants, including a debt (excluding transition bonds) to total capitalization covenant of 65%.

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, 2006, the Company had no borrowings and approximately $4 million of outstanding letters of credit under its $300 million credit facility. The Company was in compliance with all covenants as of December 31, 2006.

Transition Bonds. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed in all respects in August 2005 by the same Travis County District Court considering the appeal of the True-Up Order, in December 2005 a subsidiary of the Company issued $1.85 billion in transition bonds with interest rates ranging from 4.84 percent to 5.30 percent and final maturity dates ranging from February 2011 to August 2020. Scheduled payment dates range from August 2006 to August 2019. 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. The proceeds received from the issuance of the transition bonds were used to repay the Company’s $1.3 billion credit facility, which was utilized in November 2005 to repay the Company’s $1.3 billion term loan upon its maturity.

Maturities. The Company’s maturities of long-term debt (including scheduled payments on transition bonds), are $147 million in 2007, $159 million in 2008, $175 million in 2009, $190 million in 2010 and $207 million in 2011.

Liens. As of December 31, 2006, 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 2004, 2005 and 2006 have been satisfied by certification of property additions. The replacement fund requirement to be satisfied in 2007 is approximately $160 million, and the sinking fund requirement to be satisfied in 2007 is approximately $3 million. The Company expects to meet these 2007 obligations by certification of property additions. As of December 31, 2006, 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 Company’s current and deferred components of income tax expense are as follows:


	Year Ended December 31,
	2004		2005			2006
	(In millions)
Current
Federal	$	57	$	(8	)	$	208
State		2		—			—

Total current		59		(8	)		208

Deferred
Federal		78		116			(76	)

Total deferred		78		116			(76	)

Income tax expense	$	137	$	108		$	132

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


	Year Ended December 31,
	2004			2005			2006
	(In millions)
Income before income taxes and extraordinary item	$	419		$	331		$	403
Federal statutory rate		35	%		35	%		35	%

Income tax expense at statutory rate		147			116			141

Increase (decrease) in tax resulting from:
Amortization of investment tax credit		(7	)		(7	)		(7	)
Excess deferred taxes		(4	)		(3	)		(2	)
Other, net		1			2			—

Total		(10	)		(8	)		(9	)

Income tax expense	$	137		$	108		$	132

Effective Rate		32.7	%		32.8	%		32.7	%

Following are the Company’s tax effects of temporary differences between the carrying amounts of assets and liabilities in the financial statements and their respective tax bases:


	December 31,
	2005		2006
	(In millions)
Deferred tax assets:
Current:
Allowance for doubtful accounts	$	1	$	—

Total current deferred tax assets		1		—

Non-current:
Employee benefits		49		75
Other		19		27

Total non-current deferred tax assets		68		102

Total deferred tax assets		69		102

Deferred tax liabilities:
Non-current:
Depreciation		559		554
Regulatory assets, net		901		877
Other		8		12

Total deferred tax liabilities		1,468		1,443

Accumulated deferred income taxes, net	$	1,399	$	1,341

The Company is included in the consolidated income tax returns of CenterPoint Energy. CenterPoint Energy’s consolidated federal income tax returns have been audited and settled through the 1996 tax year. The 1997 through 2003 consolidated federal income tax returns are currently under audit.

Tax Contingencies. The Company has established reserves for certain tax positions, primarily with respect to certain items related to employee benefits. The total amount reserved for these tax items was approximately $12 million and $17 million as of December 31, 2005 and 2006, respectively.

(7) Commitments and Contingencies

(a) Lease Commitments

The following table sets forth information concerning the Company’s obligations under non-cancelable long-term operating leases at December 31, 2006, which primarily consist of rental agreements for building space, data processing equipment and vehicles, including major work equipment (in millions).


2007	$	6
2008		4
2009		—
2010		—
2011		—

Total	$	10

Total lease expense for all operating leases was approximately $4 million, $4 million and $5 million for the years ended December 31, 2004, 2005 and 2006, respectively.

(b) Legal and Environmental Matters

Legal Matters

RRI Indemnified Litigation

The Company, CenterPoint Energy or their predecessor, 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. The ultimate outcome of these matters cannot be predicted at this time.

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 Colorado and Nevada and in state court in California, Wisconsin 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 2006 and are pending in California state court in San Diego County, in Nevada state court in Clark County, in Wisconsin state court in Dane County, in federal district court in Colorado and 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. Five of the gas complaints have also been dismissed based on defendants’ claims of federal preemption and the filed rate doctrine, and these dismissals have been appealed. 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 the 12 class action natural gas cases pending in state court in California. This settlement remains subject to final court approval. The other gas cases remain in the early procedural stages.

In August 2005, RRI reached a settlement with the 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 on May 30, 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. 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.

Nuclear Decommissioning Fund Collections

Pursuant to regulatory requirements and its tariff, the Company, as collection agent, collects from its transmission and distribution customers a nuclear decommissioning charge assessed with respect to its former 30.8% ownership interest in the South Texas Project, which it owned when it was part of an integrated electric utility. Amounts collected are transferred to nuclear decommissioning trusts maintained by the current owner of that interest in the South Texas Project. During 2004, 2005 and 2006, $2.9 million, $3.2 million and $3.1 million, respectively, was transferred. There are various investment restrictions imposed on owners of nuclear generating stations by the Texas Utility Commission and the U.S. Nuclear Regulatory Commission relating to nuclear decommissioning trusts. Pursuant to the provisions of both a separation agreement and a final order of the Texas Utility Commission relating to the 2005 transfer of ownership to Texas Genco LLC, now NRG, the Company and a subsidiary of NRG were, until July 1, 2006, jointly administering the decommissioning funds through the Nuclear Decommissioning Trust Investment Committee. In June 2006, the Texas Utility Commission approved an application by the Company and an NRG subsidiary to name the NRG subsidiary as the sole fund administrator. As a result, the Company is no longer responsible for administration of decommissioning funds it collects as collection agent.

(8) Estimated Fair Value of Financial Instruments

The fair values of cash and cash equivalents and short-term borrowings are estimated to be equivalent to carrying amounts and have been excluded from the table below.

December 31, 2005

December 31, 2006

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)

4,221

4,330

4,148

4,250

(9) Unaudited Quarterly Information

Summarized quarterly financial data is as follows:


	Year Ended December 31, 2005
	First		Second		Third		Fourth
	Quarter		Quarter		Quarter		Quarter
	(In millions)
Revenues	$	345	$	414	$	484	$	401
Operating income		80		122		183		102
Income before extraordinary item		28		55		95		45
Extraordinary item, net of tax		—		30		—		—
Net income		28		85		95		45


	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

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

None.

Item 9A. 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, 2006 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, 2006 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 Accountant Fees and Services

Aggregate fees billed to the Company during the fiscal years ending December 31, 2005 and 2006 by its principal accounting firm, Deloitte & Touche LLP, are set forth below. These fees do not include certain fees related to general corporate matters, financial reporting, tax and other fees which have not been allocated to the Company by CenterPoint Energy.


	Year Ended December 31,
	2005		2006
Audit fees	$	365,225	$	414,400
Audit-related fees		165,000		34,000

Total audit and audit-related fees		530,225		448,400
Tax fees		—		—
All other fees		—		—

Total fees	$	530,225	$	448,400

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 Operations for the Three Years Ended December 31, 2006			30
Consolidated Balance Sheets at December 31, 2005 and 2006			31
Statements of Consolidated Cash Flows for the Three Years Ended December 31, 2006			32
Statements of Consolidated Member’s Equity for the Three Years Ended December 31, 2006			33
Notes to Consolidated Financial Statements			34

(a)(2) Financial Statement Schedules for the Three Years Ended December 31, 2006.

Report of Independent Registered Public Accounting Firm			53
II— Qualifying Valuation Accounts			54

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 56.

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) as of December 31, 2006 and 2005, and for each of the three years in the period ended December 31, 2006, and have issued our report thereon dated March 9, 2007 (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 9, 2007

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, 2006
(In Millions)

Column A

Column B

Column C

Column D

Column E

Balance At

Additions

Deductions

Balance At

Beginning

Charged

From

End Of

Description

of Period

to Income

Reserves(1)

Period

Year Ended December 31, 2006:

Accumulated provisions:

Uncollectible accounts receivable

)

Year Ended December 31, 2005:

Accumulated provisions:

Uncollectible accounts receivable

—

Year Ended December 31, 2004:

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 9th day of March, 2007.


	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 9, 2007.


Signature		Title

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

(David M. McClanahan)

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

(Gary L. Whitlock)

/s/ JAMES S. BRIAN		Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)

(James S. Brian)

CENTERPOINT ENERGY HOUSTON ELECTRIC, LLC

EXHIBITS TO THE ANNUAL REPORT ON FORM 10-K
For Fiscal Year Ended December 31, 2006

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)


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

4(b)(11)	Officer’s Certificate dated November 12, 2002 setting forth the form, terms and privisions of the Ninth Series of General Mortgage Bonds	CNP’s Form 10-K for the year ended December 31, 2003	1-31447		4(e)(12)

4(b)(12)	Tenth Supplemental Indenture to Exhibit 4(b)(1), dated as of March 18, 2003	Form 8-K dated March 13, 2003	1-3187		4.1

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 Amended and Restated Credit Agreement dated as of March 31, 2006 among CenterPoint Houston, as Borrower, and the banks named therein	Form 8-K dated March 31, 2006	1-3187		4.2

Pursuant to Item 601(b)(4)(iii)(A) of Regulation S-K, CenterPoint Houston 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 CenterPoint Houston and its subsidiaries on a consolidated basis. CenterPoint Houston 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 Ordinance	CNP’s Form 10-Q for the quarter ended June 30, 2005	1-31447		10.1

+12	Computation of Ratios of Earnings to Fixed Charges

+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,
	2002			2003			2004			2005			2006
Income from continuing operations	$	547		$	432		$	282		$	223		$	271
Income taxes for continuing operations		286			230			137			108			132
Capitalized interest		(3	)		(3	)		(2	)		(3	)		(4	)

		830			659			417			328			399

Fixed charges, as defined:
Interest		285			361			345			328			240
Capitalized interest		3			3			2			3			4
Interest component of rentals charged to operating expense		2			2			1			1			2

Total fixed charges		290			366			348			332			246

Earnings, as defined	$	1,120		$	1,025		$	765		$	660		$	645

Ratio of earnings to fixed charges		3.86			2.80			2.20			1.99			2.62

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)) 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)		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

	(c)		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 9, 2007



	/s/ David M. McClanahan
	David M. McClanahan
	Chairman

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)		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

	(c)		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 9, 2007



	/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, 2006 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, 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
March 9, 2007

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, 2006 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, 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 9, 2007