CENTERPOINT ENERGY INC (Form: 10-Q, Received: 11/05/2008 08:02:09)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

(Mark One)

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

FOR THE QUARTERLY PERIOD ENDED SEPTEMBER 30, 2008

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

FOR THE TRANSITION PERIOD FROM ______________ TO _______________.

______________________________

Commission file number 1-31447

CENTERPOINT ENERGY, INC.

(Exact name of registrant as specified in its charter)

Texas	74-0694415
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

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

____________________________

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

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

Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes £ No R

As of October 31, 2008, CenterPoint Energy, Inc. had 344,160,694 shares of common stock outstanding, excluding 166 shares held as treasury stock.

CENTERPOINT ENERGY, INC.

QUARTERLY REPORT ON FORM 10-Q

FOR THE QUARTER ENDED SEPTEMBER 30, 2008

TABLE OF CONTENTS

PART I.	FINANCIAL INFORMATION

Item 1.	Financial Statements	1

	Condensed Statements of Consolidated Income
	Three and Nine Months Ended September 30, 2007 and 2008 (unaudited)	1

	Condensed Consolidated Balance Sheets
	December 31, 2007 and September 30, 2008 (unaudited)	2

	Condensed Statements of Consolidated Cash Flows
	Nine Months Ended September 30, 2007 and 2008 (unaudited)	4

	Notes to Unaudited Condensed Consolidated Financial Statements	5

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	25

Item 3.	Quantitative and Qualitative Disclosures about Market Risk	38

Item 4.	Controls and Procedures	39

PART II.	OTHER INFORMATION

Item 1.	Legal Proceedings	40

Item 1A.	Risk Factors	40

Item 5.	Other Information	41

Item 6.	Exhibits	42

Table of Contents

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.

The following are some of the factors that could cause actual results to differ materially from those expressed or implied in forward-looking statements:

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

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

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

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

cost overruns on major capital projects that cannot be recouped in prices;

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

the timing and extent of changes in commodity prices, particularly natural gas;

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

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

weather variations and other natural phenomena;

changes in interest rates or rates of inflation;

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

actions by rating agencies;

effectiveness of our risk management activities;

inability of various counterparties to meet their obligations to us;

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

Table of Contents

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

the outcome of litigation brought by or against us;

our ability to control costs;

the investment performance of our employee benefit plans;

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

acquisition and merger activities involving us or our competitors; and

other factors we discuss in “Risk Factors” in Item 1A of Part I of our Annual Report on Form 10-K for the year ended December 31, 2007, which is incorporated herein by reference, and other reports we file from time to time with the Securities and Exchange Commission.

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

iii

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. FINANCIAL STATEMENTS

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED INCOME

(Millions of Dollars, Except Per Share Amounts)

(Unaudited)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008

Revenues	$	1,882		$	2,515		$	7,021		$	8,548

Expenses:
Natural gas		991			1,532			4,349			5,675
Operation and maintenance		349			371			1,031			1,078
Depreciation and amortization		170			194			475			540
Taxes other than income taxes		85			81			284			285
Total		1,595			2,178			6,139			7,578
Operating Income		287			337			882			970

Other Income (Expense):
Loss on Time Warner investment		(58	)		(36	)		(74	)		(73	)
Gain on indexed debt securities		56			33			70			66
Interest and other finance charges		(126	)		(116	)		(368	)		(344	)
Interest on transition bonds		(30	)		(34	)		(93	)		(102	)
Distribution from AOL-Time Warner litigation settlement		32			—			32			—
Additional distribution to ZENS holders		(27	)		—			(27	)		—
Other, net		11			29			23			56
Total		(142	)		(124	)		(437	)		(397	)

Income Before Income Taxes		145			213			445			573
Income tax expense		(54	)		(77	)		(154	)		(213	)
Net Income	$	91		$	136		$	291		$	360

Basic Earnings Per Share	$	0.29		$	0.40		$	0.91		$	1.08

Diluted Earnings Per Share	$	0.27		$	0.39		$	0.85		$	1.05

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Millions of Dollars)

(Unaudited)

ASSETS

	December 31, 2007		September 30, 2008
Current Assets:
Cash and cash equivalents	$	129	$	84
Investment in Time Warner common stock		357		284
Accounts receivable, net		910		784
Accrued unbilled revenues		558		243
Natural gas inventory		395		598
Materials and supplies		95		120
Non-trading derivative assets		38		75
Taxes receivable		—		289
Prepaid expenses and other current assets		306		360
Total current assets		2,788		2,837

Property, Plant and Equipment:
Property, plant and equipment		13,250		13,766
Less accumulated depreciation and amortization		3,510		3,617
Property, plant and equipment, net		9,740		10,149

Other Assets:
Goodwill		1,696		1,696
Regulatory assets		2,993		3,219
Non-trading derivative assets		11		9
Notes receivable from unconsolidated affiliates		148		323
Other		496		799
Total other assets		5,344		6,046

Total Assets	$	17,872	$	19,032

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS – (continued)

(Millions of Dollars)

(Unaudited)

LIABILITIES AND SHAREHOLDERS’ EQUITY

	December 31, 2007			September 30, 2008
Current Liabilities:
Short-term borrowings	$	232		$	150
Current portion of transition bond long-term debt		159			208
Current portion of other long-term debt		1,156			123
Indexed debt securities derivative		261			195
Accounts payable		726			1,130
Taxes accrued		316			148
Interest accrued		170			166
Non-trading derivative liabilities		61			49
Accumulated deferred income taxes, net		350			328
Other		360			375
Total current liabilities		3,791			2,872

Other Liabilities:
Accumulated deferred income taxes, net		2,235			2,687
Unamortized investment tax credits		31			26
Non-trading derivative liabilities		14			20
Benefit obligations		499			482
Regulatory liabilities		828			808
Other		300			281
Total other liabilities		3,907			4,304

Long-term Debt:
Transition bonds		2,101			2,381
Other		6,263			7,416
Total long-term debt		8,364			9,797

Commitments and Contingencies (Note 10)

Shareholders’ Equity:
Common stock (322,718,785 shares and 342,967,485 shares outstanding at December 31, 2007 and September 30, 2008, respectively)		3			3
Additional paid-in capital		3,023			3,099
Accumulated deficit		(1,172	)		(994	)
Accumulated other comprehensive loss		(44	)		(49	)
Total shareholders’ equity		1,810			2,059

Total Liabilities and Shareholders’ Equity	$	17,872		$	19,032

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

CONDENSED STATEMENTS OF CONSOLIDATED CASH FLOWS

(Millions of Dollars)

(Unaudited)

	Nine Months Ended September 30,
	2007			2008
Cash Flows from Operating Activities:
Net income	$	291		$	360
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		475			540
Amortization of deferred financing costs		44			20
Deferred income taxes		23			471
Unrealized loss on Time Warner investment		74			73
Unrealized gain on indexed debt securities		(70	)		(66	)
Write-down of natural gas inventory		11			24
Changes in other assets and liabilities:
Accounts receivable and unbilled revenues, net		540			441
Inventory		(160	)		(252	)
Taxes receivable		—			(289	)
Accounts payable		(460	)		(119	)
Fuel cost recovery		(90	)		(11	)
Non-trading derivatives, net		13			(28	)
Margin deposits, net		49			(96	)
Interest and taxes accrued		(150	)		(173	)
Net regulatory assets and liabilities		57			(48	)
Other current assets		(29	)		(2	)
Other current liabilities		(49	)		(6	)
Other assets		(39	)		(60	)
Other liabilities		(50	)		(20	)
Other, net		12			(35	)
Net cash provided by operating activities		492			724

Cash Flows from Investing Activities:
Capital expenditures		(851	)		(632	)
Increase in restricted cash of transition bond companies		—			(8	)
Increase in notes receivable from unconsolidated affiliates		(51	)		(175	)
Investment in unconsolidated affiliates		(40	)		(207	)
Other, net		9			31
Net cash used in investing activities		(933	)		(991	)

Cash Flows from Financing Activities:
Decrease in short-term borrowings, net		(37	)		(82	)
Long-term revolving credit facilities, net		580			737
Proceeds from commercial paper, net		76			—
Proceeds from long-term debt		400			1,088
Payments of long-term debt		(509	)		(1,373	)
Debt issuance costs		(4	)		(11	)
Payment of common stock dividends		(164	)		(183	)
Proceeds from issuance of common stock, net		20			45
Other		6			1
Net cash provided by financing activities		368			222

Net Decrease in Cash and Cash Equivalents		(73	)		(45	)
Cash and Cash Equivalents at Beginning of Period		127			129
Cash and Cash Equivalents at End of Period	$	54		$	84

Supplemental Disclosure of Cash Flow Information:
Cash Payments:
Interest, net of capitalized interest	$	447		$	447
Income taxes		195			188
Non-cash transactions:
Accounts payable related to capital expenditures		78			218

See Notes to the Company’s Interim Condensed Consolidated Financial Statements

Table of Contents

CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

NOTES TO UNAUDITED CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(1)	Background and Basis of Presentation

General. Included in this Quarterly Report on Form 10-Q (Form 10-Q) of CenterPoint Energy, Inc. are the condensed consolidated interim financial statements and notes (Interim Condensed Financial Statements) of CenterPoint Energy, Inc. and its subsidiaries (collectively, CenterPoint Energy, or the Company). The Interim Condensed Financial Statements are unaudited, omit certain financial statement disclosures and should be read with the Annual Report on Form 10-K of CenterPoint Energy for the year ended December 31, 2007 (CenterPoint Energy Form 10-K).

Background. CenterPoint Energy, Inc. is a public utility holding company. The Company’s operating subsidiaries own and operate electric transmission and distribution facilities, natural gas distribution facilities, interstate pipelines and natural gas gathering, processing and treating facilities. As of September 30, 2008, the Company’s indirect wholly owned subsidiaries included:

CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), which engages in the electric transmission and distribution business in a 5,000-square mile area of the Texas Gulf Coast that includes Houston; and

CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC), which owns and operates natural gas distribution systems in six states. Subsidiaries of CERC own interstate natural gas pipelines and gas gathering systems and provide various ancillary services. A wholly owned subsidiary of CERC Corp. offers variable and fixed-price physical natural gas supplies primarily to commercial and industrial customers and electric and gas utilities.

Basis of Presentation. The preparation of financial statements in conformity with generally accepted accounting principles (GAAP) 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.

The Company’s Interim Condensed Financial Statements reflect all normal recurring adjustments that are, in the opinion of management, necessary to present fairly the financial position, results of operations and cash flows for the respective periods. Amounts reported in the Company’s Condensed Statements of Consolidated Income are not necessarily indicative of amounts expected for a full-year period due to the effects of, among other things, (a) seasonal fluctuations in demand for energy and energy services, (b) changes in energy commodity prices, (c) timing of maintenance and other expenditures and (d) acquisitions and dispositions of businesses, assets and other interests.

For a description of the Company’s reportable business segments, reference is made to Note 13.

(2)	New Accounting Pronouncements

In April 2007, the Financial Accounting Standards Board (FASB) issued Staff Position No. FIN 39-1, “Amendment of FASB Interpretation No. 39” (FIN 39-1), which permits companies that enter into master netting arrangements to offset cash collateral receivables or payables with net derivative positions under certain circumstances. The Company adopted FIN 39-1 effective January 1, 2008 and began netting cash collateral receivables and payables and also its derivative assets and liabilities with the same counterparty subject to master netting agreements.

In February 2007, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities, including an amendment of FASB Statement No. 115” (SFAS No. 159). SFAS No. 159 permits the Company to choose, at specified election dates, to measure eligible items at fair value (the “fair value option”). The Company would report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting period. This accounting

Table of Contents

standard is effective as of the beginning of the first fiscal year that begins after November 15, 2007 but is not required to be applied. The Company currently has no plans to apply SFAS No. 159.

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

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

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

Level 1: Inputs are unadjusted quoted prices in active markets for identical assets or liabilities at the measurement date. The types of assets carried at Level 1 fair value generally are financial derivatives, investments and equity securities listed in active markets.

Level 2: Inputs, other than quoted prices included in Level 1, are observable for the asset or liability, either directly or indirectly. Level 2 inputs include quoted prices for similar instruments in active markets, and inputs other than quoted prices that are observable for the asset or liability. Fair value assets and liabilities that are generally included in this category are derivatives with fair values based on inputs from actively quoted markets.

Level 3: Inputs are unobservable for the asset or liability, and include situations where there is little, if any, market activity for the asset or liability. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, the level in the fair value hierarchy within which the fair value measurement in its entirety falls has been determined based on the lowest level input that is significant to the fair value measurement in its entirety. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment, and considers factors specific to the asset. Generally, assets and liabilities carried at fair value and included in this category are financial derivatives.

The following table presents information about the Company’s assets and liabilities (including derivatives that are presented net) measured at fair value on a recurring basis as of September 30, 2008, and indicates the fair value hierarchy of the valuation techniques utilized by the Company to determine such fair value.

Table of Contents

	Quoted Prices in Active Markets for Identical Assets (Level 1)			Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)		Netting Adjustments (1)			Balance as of September 30, 2008
	(in millions)
Assets
Corporate equities		$	286	$	—	$	—	$	—			$	286
Investments			67		—		—		—				67
Derivative assets			24		111		38		(89	)			84
Total assets		$	377	$	111	$	38	$	(89	)		$	437
Liabilities
Indexed debt securities derivative		$	—	$	195	$	—	$	—			$	195
Derivative liabilities			31		124		97		(183	)			69
Total liabilities		$	31	$	319	$	97	$	(183	)		$	264

(1)	Amounts represent the impact of legally enforceable master netting agreements that allow the Company to settle positive and negative positions and also cash collateral held or placed with the same counterparties.

The following table presents additional information about assets or liabilities, including derivatives that are measured at fair value on a recurring basis for which the Company has utilized Level 3 inputs to determine fair value, for the three months ended September 30, 2008:

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning asset (liability) balance as of July 1, 2008	$	6
Total gains or (losses) (realized and unrealized):
Included in deferred fuel cost recovery		(59	)
Included in earnings		(2	)
Purchases, sales, other settlements, net		(4	)
Ending asset (liability) balance as of September 30, 2008	$	(59	)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	4

	Fair Value Measurements Using Significant Unobservable Inputs (Level 3)
	Derivative assets and liabilities, net
	(in millions)
Beginning asset (liability) balance as of July 1, 2008	$	(3	)
Total gains or (losses) (realized and unrealized):
Included in deferred fuel cost recovery		(59	)
Included in earnings		7
Purchases, sales, other settlements, net		(4	)
Ending asset (liability) balance as of September 30, 2008	$	(59	)
The amount of total gains or (losses) for the period included in earnings attributable to the change in unrealized gains or losses relating to assets still held at the reporting date	$	9

Table of Contents

In March 2008, the FASB issued SFAS No. 161, “ Disclosures about Derivative Instruments and Hedging Activities - an amendment of FASB Statement No. 133” (SFAS No. 161). SFAS No. 161 amends SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities” (SFAS No. 133) and requires enhanced disclosures of derivative instruments and hedging activities such as the fair value of derivative instruments and presentation of their gains or losses in tabular format, as well as disclosures regarding credit risks and strategies and objectives for using derivative instruments. SFAS No. 161 is effective for fiscal years and interim periods beginning after November 15, 2008. The Company is currently evaluating the potential impact the adoption of SFAS No. 161 will have on its consolidated financial statements.

In May 2008, the FASB issued FASB Staff Position (“FSP”) No. APB 14-1 “Accounting for Convertible Debt Instruments That May Be Settled in Cash Upon Conversion (Including Partial Cash Settlement)”, which will change the accounting treatment for convertible securities that the issuer may settle fully or partially in cash. Under the final FSP, cash settled convertible securities will be separated into their debt and equity components. The value assigned to the debt component will be the estimated fair value, as of the issuance date, of a similar debt instrument without the conversion feature, and the difference between the proceeds for the convertible debt and the amount reflected as a debt liability will be recorded as additional paid-in capital. As a result, the debt will be recorded at a discount reflecting its below market coupon interest rate. The debt will subsequently be accreted to its par value over its expected life, with the rate of interest that reflects the market rate at issuance being reflected on the income statement. The FSP is effective for financial statements issued for fiscal years beginning after December 15, 2008, and interim periods within those fiscal years. The Company currently has no convertible debt that is within the scope of this FSP, but this FSP will be applied retrospectively and will affect net income for prior periods and the consolidated balance sheets when the Company had contingently convertible debt outstanding. The Company is currently evaluating the effect of these retrospective adjustments, but does not expect the retrospective adjustments to be material.

(3)	Employee Benefit Plans

The Company’s net periodic cost includes the following components relating to pension and postretirement benefits:

	Three Months Ended September 30,
	2007						2008
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(in millions)
Service cost	$	9		$	—		$	8		$	—
Interest cost		25			7			25			6
Expected return on plan assets		(38	)		(2	)		(37	)		(3	)
Amortization of prior service cost		(1	)		—			(2	)		—
Amortization of net loss		8			—			6			—
Amortization of transition obligation		—			2			—			2
Net periodic cost	$	3		$	7		$	—		$	5

	Nine Months Ended September 30,
	2007						2008
	Pension Benefits			Postretirement Benefits			Pension Benefits			Postretirement Benefits
	(in millions)
Service cost	$	27		$	1		$	23		$	1
Interest cost		75			20			76			20
Expected return on plan assets		(112	)		(8	)		(111	)		(9	)
Amortization of prior service cost		(5	)		2			(5	)		3
Amortization of net loss		26			—			18			—
Amortization of transition obligation		—			5			—			4
Net periodic cost	$	11		$	20		$	1		$	19

Table of Contents

The Company expects to contribute approximately $8 million to its non-qualified pension plans in 2008, of which $2 million and $6 million, respectively, was contributed during the three and nine months ended September 30, 2008.

The Company expects to contribute approximately $21 million to its postretirement benefits plan in 2008, of which $4 million and $16 million, respectively, was contributed during the three and nine months ended September 30, 2008.

(4)	Regulatory Matters

(a)	Hurricane Ike

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

CenterPoint Houston estimates that total costs to restore the electric delivery facilities damaged as a result of Hurricane Ike will be in the range of $650 million to $750 million. As is common with electric utilities serving coastal regions, the poles, towers, wires, street lights and pole mounted equipment that comprise CenterPoint Houston’s transmission and distribution system are not covered by property insurance, but office buildings and warehouses and their contents and substations are covered by insurance that provides for a maximum deductible of $10 million. Current estimates are that total losses to property covered by this insurance were approximately $25 million.

CenterPoint Houston is deferring the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. As a result, storm restoration costs will not affect the Company’s or CenterPoint Houston’s reported net income for 2008. As of September 30, 2008, CenterPoint Houston recorded an increase of $141 million in construction work in progress and $434 million in regulatory assets, for restoration costs incurred through September 30, 2008. Approximately $503 million of these costs are based on estimates and are included in accounts payable as of September 30, 2008. Additional restoration costs will continue to be incurred during the fourth quarter of 2008 and possibly during the first quarter of 2009.

Assuming necessary enabling legislation is enacted by the Texas Legislature in the session that begins in January 2009, CenterPoint Houston expects to obtain recovery of its storm restoration costs through the issuance of non-recourse securitization bonds similar to the storm recovery bonds issued by another Texas utility following Hurricane Rita. Assuming those bonds are issued, CenterPoint Houston will recover the amount of storm restoration costs approved by the Public Utility Commission of Texas (Texas Utility Commission) out of the bond proceeds, with the bonds being repaid over time through a charge imposed on customers. Alternatively, if securitization is not available, recovery of those costs would be sought through traditional regulatory mechanisms. Under its 2006 rate case settlement, CenterPoint Houston is entitled to seek an adjustment to rates in this situation, even though in most instances its rates are frozen until 2010.

The natural gas distribution business of CERC (Gas Operations) also suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana. As of September 30, 2008, Gas Operations has deferred approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

(b)	Recovery of True-up Balance

In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas Electric Choice Plan (Texas electric restructuring law). In December 2004, the Texas Utility Commission issued its final order (True-Up Order) allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional excess mitigation credits (EMCs) returned to customers after August 31, 2004 and certain other adjustments.

Table of Contents

CenterPoint Houston and other parties filed appeals of the True-Up Order to a district court in Travis County, Texas. In August 2005, that court issued its judgment on the various appeals. In its judgment, the district court:

reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to retail electric providers; and

affirmed the True-Up Order in all other respects.

The district court’s decision would have had the effect of restoring approximately $650 million, plus interest, of the $1.7 billion the Texas Utility Commission had disallowed from CenterPoint Houston’s initial request.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to Reliant Energy, Inc. (RRI);

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

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

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

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

Review by the Texas Supreme Court of the court of appeals decision is at the discretion of the court. There is no prescribed time in which the Texas Supreme Court must determine whether to grant review or, if review is granted, for a decision by that court. Although the Company and CenterPoint Houston believe that CenterPoint Houston’s true-up request is consistent with applicable statutes and regulations and, accordingly, that it is reasonably possible that it will be successful in its appeal to the Texas Supreme Court, the Company can provide no assurance as to the ultimate court rulings on the issues to be considered in the appeal or with respect to the ultimate decision by the Texas Utility Commission on the tax normalization issue described below.

To reflect the impact of the True-Up Order, in 2004 and 2005, the Company recorded a net after-tax extraordinary loss of $947 million. No amounts related to the district court’s judgment or the decision of the court of appeals have been recorded in the Company’s consolidated financial statements. However, if the court of appeals

Table of Contents

decision is not reversed or modified as a result of further review by the Texas Supreme Court, the Company anticipates that it would be required to record an additional loss to reflect the court of appeals decision. The amount of that loss would depend on several factors, including ultimate resolution of the tax normalization issue described below and the calculation of interest on any amounts CenterPoint Houston ultimately is authorized to recover or is required to refund beyond the amounts recorded based on the True-up Order, but could range from $130 million to $350 million (pre-tax) plus interest subsequent to December 31, 2007.

In the True-Up Order, the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. The Company believes that the Texas Utility Commission based its order on proposed regulations issued by the Internal Revenue Service (IRS) in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of Accumulated Deferred Investment Tax Credits (ADITC) and Excess Deferred Federal Income Taxes (EDFIT) back to customers. However, the IRS subsequently withdrew those proposed normalization regulations and in March 2008 adopted final regulations that would not permit utilities like CenterPoint Houston to pass the tax benefits back to customers without creating normalization violations. In addition, the Company received a Private Letter Ruling (PLR) from the IRS in August 2007, prior to adoption of the final regulations, that confirmed that the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations with respect to the ADITC and EDFIT.

If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require the Company to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment, if required by the IRS, could have a material adverse impact on the Company’s results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. In its opinion, the court of appeals ordered that this issue be remanded to the Texas Utility Commission, as that commission requested. No party, in the petitions for review filed with the Texas Supreme Court, has challenged that order by the court of appeals, though the Texas Supreme Court, if it grants review, will have authority to consider all aspects of the rulings above, not just those challenged specifically by the appellants. The Company and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

The Texas electric restructuring law allowed the amounts awarded to CenterPoint Houston in the Texas Utility Commission’s True-Up Order to be recovered either through the issuance of transition bonds or through implementation of a competition transition charge (CTC) or both. Pursuant to a financing order issued by the Texas Utility Commission in March 2005 and affirmed by a Travis County district court, in December 2005 a subsidiary of CenterPoint Houston issued $1.85 billion in transition bonds with interest rates ranging from 4.84% to 5.30% and final maturity dates ranging from February 2011 to August 2020. Through issuance of the transition bonds, CenterPoint Houston recovered approximately $1.7 billion of the true-up balance determined in the True-Up Order plus interest through the date on which the bonds were issued.

In July 2005, CenterPoint Houston received an order from the Texas Utility Commission allowing it to implement a CTC designed to collect the remaining $596 million from the True-Up Order over 14 years plus interest at an annual rate of 11.075% (CTC Order). The CTC Order authorized CenterPoint Houston to impose a charge on retail electric providers to recover the portion of the true-up balance not recovered through a financing order. The CTC Order also allowed CenterPoint Houston to collect approximately $24 million of rate case expenses over three years without a return through a separate tariff rider (Rider RCE). CenterPoint Houston implemented the CTC and Rider RCE effective September 13, 2005 and began recovering approximately $620 million. The return on the CTC portion of the true-up balance was included in CenterPoint Houston’s tariff-based revenues beginning September 13, 2005. Effective August 1, 2006, the interest rate on the unrecovered balance of the CTC was reduced from 11.075% to 8.06% pursuant to a revised rule adopted by the Texas Utility Commission in June 2006. Recovery of rate case expenses under Rider RCE was completed in September 2008.

Table of Contents

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

During the three months ended September 30, 2007 and 2008, CenterPoint Houston recognized approximately $11 million and $-0-, respectively, in operating income from the CTC, which was terminated in February 2008 when the transition bonds described below were issued. Additionally, during the three months ended September 30, 2007 and 2008, CenterPoint Houston recognized approximately $5 million and $4 million, respectively, of the allowed equity return not previously recorded.

During the nine months ended September 30, 2007 and 2008, CenterPoint Houston recognized approximately $32 million and $5 million, respectively, in operating income from the CTC, which was terminated in February 2008 when the transition bonds described below were issued. Additionally, during the nine months ended September 30, 2007 and 2008, CenterPoint Houston recognized approximately $11 million and $10 million, respectively, of the allowed equity return not previously recorded.

During the 2007 legislative session, the Texas legislature amended statutes prescribing the types of true-up balances that can be securitized by utilities and authorized the issuance of transition bonds to recover the balance of the CTC. In June 2007, CenterPoint Houston filed a request with the Texas Utility Commission for a financing order that would allow the securitization of the remaining balance of the CTC, adjusted to refund certain unspent environmental retrofit costs and to recover the amount of the final fuel reconciliation settlement. CenterPoint Houston reached substantial agreement with other parties to this proceeding, and a financing order was approved by the Texas Utility Commission in September 2007. In February 2008, pursuant to the financing order, a new special purpose subsidiary of CenterPoint Houston issued approximately $488 million of transition bonds in two tranches with interest rates of 4.192% and 5.234% and final maturity dates of February 2020 and February 2023, respectively. Contemporaneously with the issuance of those bonds, the CTC was terminated and a transition charge was implemented.

As of September 30, 2008, the Company had not recorded an allowed equity return of $209 million on CenterPoint Houston’s true-up balance because such return will be recognized as it is recovered in rates.

(c)	Rate Proceedings

Texas. In March 2008, Gas Operations filed a request to change its rates with the Railroad Commission of Texas (Railroad Commission) and the 47 cities in its Texas Coast service territory, an area consisting of approximately 230,000 customers in cities and communities on the outskirts of Houston. The request sought to establish uniform rates, charges and terms and conditions of service for the cities and environs of the Texas Coast service territory. Of the 47 cities, 23 either affirmatively approved or allowed the filed rates to go into effect by operation of law. Nine other cities are represented by the Texas Coast Utilities Coalition (TCUC) and 15 cities are represented by the Gulf Coast Coalition of Cities (GCCC). The TCUC cities denied the rate change request and Gas Operations appealed the denial of rates to the Railroad Commission. The Railroad Commission issued an order in October 2008, which, if implemented across the entire Texas Coast service territory, would result in an annual revenue increase of $3.7 million. In July 2008, Gas Operations reached a settlement agreement with the GCCC.

Table of Contents

That settlement agreement, if implemented across the entire Texas Coast service territory, would allow Gas Operations a $3.4 million annual increase in revenues. Both the Railroad Commission order and the settlement provide for an annual rate adjustment mechanism to reflect changes in operating expenses and revenues as well as changes in capital investment and associated changes in revenue-related taxes. The impact of the Railroad Commission’s order on the settled rates is still under review, and how rates will be conformed among all cities in the Texas Coast service territory is unknown at this time.

In September 2008, CenterPoint Houston filed an application with the Texas Utility Commission requesting an interim update to its wholesale transmission rate. The filing results in a revenue requirement increase of $22.5 million over rates that are currently in effect. Approximately 74% will be paid by distribution companies other than CenterPoint Houston. The remaining 26% represents CenterPoint Houston’s share. That amount cannot be included in rates until 2010 under the terms of the rate freeze implemented in the settlement of CenterPoint Houston’s 2006 rate proceeding. In September 2008, the Texas Utility Commission staff recommended approval of CenterPoint Houston’s request. The new rates are expected to go into effect in early November 2008.

Minnesota. In November 2006, the Minnesota Public Utilities Commission (MPUC) denied a request filed by Gas Operations for a waiver of MPUC rules in order to allow Gas Operations to recover approximately $21 million in unrecovered purchased gas costs related to periods prior to July 1, 2004. Those unrecovered gas costs were identified as a result of revisions to previously approved calculations of unrecovered purchased gas costs. Following that denial, Gas Operations recorded a $21 million adjustment to reduce pre-tax earnings in the fourth quarter of 2006 and reduced the regulatory asset related to these costs by an equal amount. In March 2007, following the MPUC’s denial of reconsideration of its ruling, Gas Operations petitioned the Minnesota Court of Appeals for review of the MPUC’s decision, and in May 2008 that court ruled that the MPUC had been arbitrary and capricious in denying Gas Operations a waiver. The court ordered the case remanded to the MPUC for reconsideration under the same principles the MPUC had applied in previously granted waiver requests. The MPUC sought further review of the court of appeals decision from the Minnesota Supreme Court, and in July 2008, the Minnesota Supreme Court agreed to review the decision. However, a decision from the court is not expected until the first half of 2009. No prediction can be made as to the ultimate outcome of this matter.

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

(5)	Derivative Instruments

The Company is exposed to various market risks. These risks arise from transactions entered into in the normal course of business. The Company utilizes derivative instruments such as physical forward contracts, swaps and options to mitigate the impact of changes in commodity prices, weather and interest rates on its operating results and cash flows.

(a)	Non-Trading Activities

Cash Flow Hedges. The Company has entered into certain derivative instruments that qualify as cash flow hedges under SFAS No. 133. The objective of these derivative instruments is to hedge the price risk associated with natural gas purchases and sales to reduce cash flow variability related to meeting the Company’s wholesale and retail customer obligations. During each of the three and nine months ended September 30, 2007 and 2008, hedge ineffectiveness was less than $1 million from derivatives that qualify for and are designated as cash flow hedges. No component of the derivative instruments’ gain or loss was excluded from the assessment of effectiveness. If it becomes probable that an anticipated transaction being hedged will not occur, the Company realizes in net income the deferred gains and losses previously recognized in accumulated other comprehensive loss. When an anticipated

Table of Contents

transaction being hedged affects earnings, the accumulated deferred gain or loss recognized in accumulated other comprehensive loss is reclassified and included in the Statements of Consolidated Income under the “Expenses” caption “Natural gas.” Cash flows resulting from these transactions in non-trading energy derivatives are included in the Statements of Consolidated Cash Flows in the same category as the item being hedged. As of September 30, 2008, the Company expects less than $1 million in accumulated other comprehensive income to be reclassified as a decrease in natural gas expense during the next twelve months.

The length of time the Company is hedging its exposure to the variability in future cash flows using derivative instruments that have been designated and have qualified as cash flow hedging instruments is less than one year. The Company’s policy is not to exceed ten years in hedging its exposure.

Hedging of Future Debt Issuances. In May 2008, the Company settled its treasury rate lock derivative instruments (treasury rate locks) for a payment of $7 million. The treasury rate locks, which expired in June 2008, had an aggregate notional amount of $300 million and a weighted-average locked U.S. treasury rate on ten-year debt of 4.05%. These treasury rate locks were executed to hedge the ten-year U.S. treasury rate expected to be used in pricing the $300 million of fixed-rate debt the Company planned to issue in 2008, because changes in the U.S treasury rate would cause variability in the Company’s forecasted interest payments. These treasury rate locks qualified as cash flow hedges under SFAS No. 133. The $7 million loss recognized upon settlement of the treasury rate locks was recorded as a component of accumulated other comprehensive loss and will be recognized as a component of interest expense over the ten-year life of the related $300 million senior notes issued in May 2008. Amortization of amounts deferred in accumulated other comprehensive loss for the three and nine months ended September 30, 2008 was less than $1 million. During the three months and nine months ended September 30, 2008, the Company recognized $-0- and a loss of $5 million, respectively, for these treasury rate locks in accumulated other comprehensive loss. Ineffectiveness for the treasury rate locks was not material during the three and nine months ended September 30, 2008.

Other Derivative Instruments. The Company enters into certain derivative instruments to manage physical commodity price risks that do not qualify or are not designated as cash flow or fair value hedges under SFAS No. 133. The Company utilizes these financial instruments to manage physical commodity price risks and does not engage in proprietary or speculative commodity trading. During the three months ended September 30, 2007, the Company decreased natural gas expense from unrealized net gains of $2 million. During the nine months ended September 30, 2007, the Company increased natural gas expense from unrealized net losses of $12 million. During the three months ended September 30, 2008, the Company increased revenues from unrealized net gains of $80 million and increased natural gas expense from unrealized net losses of $34 million, a net unrealized gain of $46 million. During the nine months ended September 30, 2008, the Company increased revenues from unrealized net gains of $51 million and increased natural gas expense from unrealized net losses of $37 million, a net unrealized gain of $14 million.

Weather Derivatives. The Company has weather normalization or other rate mechanisms that mitigate the impact of weather in Arkansas, Louisiana, Oklahoma and a portion of Texas. The remaining Gas Operations jurisdictions, Minnesota, Mississippi and most of Texas, do not have such mechanisms. As a result, fluctuations from normal weather may have a significant positive or negative effect on the results of these operations.

In 2007, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2007/2008 winter heating season. The swaps were based on ten-year normal weather and provided for a maximum payment by either party of $18 million. During the three and nine months ended September 30, 2008, the Company recognized losses of $-0- and $13 million, respectively, related to these swaps. The loss for the nine months ended September 30, 2008 was offset in part by increased revenues due to colder than normal weather. These weather derivative losses are included in revenues in the Condensed Statements of Consolidated Income.

In July 2008, the Company entered into heating-degree day swaps to mitigate the effect of fluctuations from normal weather on its financial position and cash flows for the 2008/2009 winter heating season. The swaps are based on ten-year normal weather and provide for a maximum payment by either party of $11 million.

Table of Contents

(6)

Goodwill

Goodwill by reportable business segment as of both December 31, 2007 and September 30, 2008 is as follows (in millions):

Natural Gas Distribution	$	746
Interstate Pipelines		579
Competitive Natural Gas Sales and Services		335
Field Services		25
Other Operations		11
Total	$	1,696

The Company performs its goodwill impairment tests at least annually and evaluates goodwill when events or changes in circumstances indicate that the carrying value of these assets may not be recoverable. The impairment evaluation for goodwill is performed by using a two-step process. In the first step, the fair value of each reporting unit is compared with the carrying amount of the reporting unit, including goodwill. The estimated fair value of the reporting unit is generally determined on the basis of discounted future cash flows. If the estimated fair value of the reporting unit is less than the carrying amount of the reporting unit, then a second step must be completed in order to determine the amount of the goodwill impairment that should be recorded. In the second step, the implied fair value of the reporting unit’s goodwill is determined by allocating the reporting unit’s fair value to all of its assets and liabilities other than goodwill (including any unrecognized intangible assets) in a manner similar to a purchase price allocation. The resulting implied fair value of the goodwill that results from the application of this second step is then compared to the carrying amount of the goodwill and an impairment charge is recorded for the difference.

The Company performed the test at July 1, 2008, the Company’s annual impairment testing date, and determined that no impairment charge for goodwill was required.

(7)	Comprehensive Income

The following table summarizes the components of total comprehensive income (net of tax):

	For the Three Months Ended September 30,					For the Nine Months Ended September 30,
	2007		2008			2007			2008
	(in millions)
Net income	$	91	$	136		$	291		$	360
Other comprehensive income (loss):
Adjustment to pension and other postretirement plans (net of tax of $1, $2, $4 and $3)		1		—			5			3
Net deferred gain (loss) from cash flow hedges (net of tax of $3, $-0-, $6 and $2)		6		(1	)		11			(4	)
Reclassification of deferred loss (gain) from cash flow hedges realized in net income (net of tax of $1, $-0-, $10 and $2)		3		—			(14	)		(4	)
Total		10		(1	)		2			(5	)
Comprehensive income	$	101	$	135		$	293		$	355

The following table summarizes the components of accumulated other comprehensive loss:

	December 31, 2007			September 30, 2008
	(in millions)
SFAS No. 158 incremental effect	$	(48	)	$	(45	)
Net deferred gain (loss) from cash flow hedges		4			(4	)
Total accumulated other comprehensive loss	$	(44	)	$	(49	)

Table of Contents

(8)	Capital Stock

CenterPoint Energy has 1,020,000,000 authorized shares of capital stock, comprised of 1,000,000,000 shares of $0.01 par value common stock and 20,000,000 shares of $0.01 par value preferred stock. At December 31, 2007, 322,718,951 shares of CenterPoint Energy common stock were issued and 322,718,785 shares of CenterPoint Energy common stock were outstanding. At September 30, 2008, 342,967,651 shares of CenterPoint Energy common stock were issued and 342,967,485 shares of CenterPoint Energy common stock were outstanding. Outstanding common shares exclude 166 treasury shares at both December 31, 2007 and September 30, 2008. See Note 9(b) describing the conversion of the 3.75% convertible senior notes in 2008.

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

(a)	Short-term Borrowings

CERC’s receivables facility terminated on October 28, 2008. The facility size ranged from $150 million to $375 million during the period from September 30, 2007 to the October 28, 2008 termination date. The variable size of the facility tracked the seasonal pattern of receivables in CERC’s natural gas businesses. At September 30, 2008, the facility size was $150 million. As of December 31, 2007 and September 30, 2008, $232 million and $150 million, respectively, was advanced for the purchase of receivables under this receivables facility. Advances under the receivables facility of $150 million were repaid upon termination of the facility. CERC is currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

(b)	Long-term Debt

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

In May 2008, CERC Corp. issued $300 million aggregate principal amount of senior notes due in May 2018 with an interest rate of 6.00%. The proceeds from the sale of the senior notes were used for general corporate purposes, including capital expenditures, working capital and loans to or investments in affiliates. Pending application of the net proceeds from this offering for these purposes, CERC Corp. repaid borrowings under its senior unsecured revolving credit facility and borrowings from its affiliates.

Revolving Credit Facilities. As of December 31, 2007 and September 30, 2008, the following loan balances were outstanding under the Company’s revolving credit facilities (in millions):

	December 31, 2007		September 30, 2008
CenterPoint Energy $1.2 billion credit facility borrowings	$	131	$	152
CenterPoint Houston $300 million credit facility borrowings		50		171
CERC Corp. $950 million credit facility borrowings		150		745
Total credit facility borrowings outstanding	$	331	$	1,068

In addition, as of both December 31, 2007 and September 30, 2008, the Company had approximately $28 million of outstanding letters of credit under its $1.2 billion credit facility and CenterPoint Houston had approximately $4 million of outstanding letters of credit under its $300 million credit facility. There was no commercial paper outstanding that would have been backstopped by the Company’s $1.2 billion credit facility or CERC Corp.’s $950 million credit facility at December 31, 2007 and September 30, 2008. The Company, CenterPoint Houston and CERC Corp. were in compliance with all debt covenants as of September 30, 2008.

Convertible Debt. In April 2008, the Company announced a call for redemption of its 3.75% convertible senior notes on May 30, 2008. At the time of the announcement, the notes were convertible at the option of the holders, and substantially all of the notes were submitted for conversion on or prior to the May 30, 2008 redemption date. During the nine months ended September 30, 2008, the Company issued 16.9 million shares of its common stock and paid

Table of Contents

cash of approximately $532 million to settle conversions of approximately $535 million principal amount of its 3.75% convertible senior notes.

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

(10)	Commitments and Contingencies

(a)	Natural Gas Supply Commitments

Natural gas supply commitments include natural gas contracts related to the Company’s Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, which have various quantity requirements and durations, that are not classified as non-trading derivative assets and liabilities in the Company’s Consolidated Balance Sheets as of December 31, 2007 and September 30, 2008 as these contracts meet the SFAS No. 133 exception to be classified as “normal purchases contracts” or do not meet the definition of a derivative. Natural gas supply commitments also include natural gas transportation contracts that do not meet the definition of a derivative. As of September 30, 2008, minimum payment obligations for natural gas supply commitments are approximately $301 million for the remaining three months in 2008, $631 million in 2009, $302 million in 2010, $293 million in 2011, $283 million in 2012 and $1.1 billion after 2012.

(b)	Legal, Environmental and Other Regulatory Matters

Legal Matters

RRI Indemnified Litigation

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

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

Table of Contents

federal district court in Nevada. The Company believes it is not a proper defendant in the remaining cases and will continue to pursue dismissal from those cases.

Electricity Market Manipulation Cases . A large number of lawsuits were filed against numerous market participants in connection with the operation of the California electricity markets in 2000-2001. The Company’s former affiliate, RRI, was a participant in the California markets, owning generating plants in the state and participating in both electricity and natural gas trading in that state and in western power markets generally. The Company was a defendant in approximately five of these suits. These lawsuits, many of which were filed as class actions, were 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. In August 2005, RRI reached a settlement with the Federal Energy Regulatory Commission (FERC) enforcement staff, the states of California, Washington and Oregon, California’s three largest investor-owned utilities, classes of consumers from California and other western states, and a number of California city and county government entities that resolves their claims against RRI related to the operation of the electricity markets in California and certain other western states in 2000-2001. The settlement has been approved by the FERC, by the California Public Utilities Commission and by the courts in which the electricity class action cases were pending. Two parties appealed the courts’ approval of the settlement to the California Court of Appeals, but that appeal was denied and the deadline to appeal to the California Supreme Court has passed. A party in the FERC proceedings filed a motion for rehearing of the FERC’s order approving the settlement, which the FERC denied in May 2006. That party has filed for review of the FERC’s orders in the Ninth Circuit Court of Appeals. The Company is not a party to the settlement, but may rely on the settlement as a defense to any claims.

Other Legal Matters

Natural Gas Measurement Lawsuits. CERC Corp. and certain of its subsidiaries are defendants in a lawsuit filed in 1997 under the Federal False Claims Act alleging mismeasurement of natural gas produced from federal and Indian lands. The suit seeks undisclosed damages, along with statutory penalties, interest, costs and fees. The complaint is part of a larger series of complaints filed against 77 natural gas pipelines and their subsidiaries and affiliates. An earlier single action making substantially similar allegations against the pipelines was dismissed by the federal district court for the District of Columbia on grounds of improper joinder and lack of jurisdiction. As a result, the various individual complaints were filed in numerous courts throughout the country. This case has been consolidated, together with the other similar False Claims Act cases, in the federal district court in Cheyenne, Wyoming. In October 2006, the judge considering this matter granted the defendants’ motion to dismiss the suit on the ground that the court lacked subject matter jurisdiction over the claims asserted. The plaintiff has sought review of that dismissal from the Tenth Circuit Court of Appeals, where the matter remains pending.

In addition, CERC Corp. and certain of its subsidiaries are defendants in two mismeasurement lawsuits brought against approximately 245 pipeline companies and their affiliates pending in state court in Stevens County, Kansas. In one case (originally filed in May 1999 and amended four times), the plaintiffs purport to represent a class of royalty owners who allege that the defendants have engaged in systematic mismeasurement of the volume of natural gas for more than 25 years. The plaintiffs amended their petition in this suit in July 2003 in response to an order from the judge denying certification of the plaintiffs’ alleged class. In the amendment the plaintiffs dismissed their claims against certain defendants (including two CERC Corp. subsidiaries), limited the scope of the class of plaintiffs they purport to represent and eliminated previously asserted claims based on mismeasurement of the British thermal unit (Btu) content of the gas. The same plaintiffs then filed a second lawsuit, again as representatives of a putative class of royalty owners, in which they assert their claims that the defendants have engaged in systematic mismeasurement of the Btu content of natural gas for more than 25 years. In both lawsuits, the plaintiffs seek compensatory damages, along with statutory penalties, treble damages, interest, costs and fees. CERC believes that there has been no systematic mismeasurement of gas and that the lawsuits are without merit. CERC does not expect the ultimate outcome of the lawsuits to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Gas Cost Recovery Litigation. In October 2002, a lawsuit was filed on behalf of certain CERC ratepayers in state district court in Wharton County, Texas against the Company, CERC Corp., Entex Gas Marketing Company (EGMC), and certain non-affiliated companies alleging fraud, violations of the Texas Deceptive Trade Practices Act, violations of the Texas Utilities Code, civil conspiracy and violations of the Texas Free Enterprise and Antitrust

Table of Contents

Act with respect to rates charged to certain consumers of natural gas in the State of Texas. The plaintiffs initially sought certification of a class of Texas ratepayers, but subsequently dropped their request for class certification. The plaintiffs later added as defendants CenterPoint Energy Marketing Inc., CenterPoint Energy Pipeline Services, Inc. (CEPS), and certain other subsidiaries of CERC, and other non-affiliated companies. In February 2005, the case was removed to federal district court in Houston, Texas, and in March 2005, the plaintiffs voluntarily dismissed the case and agreed not to refile the claims asserted unless the Miller County case described below is not certified as a class action or is later decertified.

In October 2004, a lawsuit was filed by certain CERC ratepayers in Texas and Arkansas in circuit court in Miller County, Arkansas against the Company, CERC Corp., EGMC, CenterPoint Energy Gas Transmission Company (CEGT), CenterPoint Energy Field Services (CEFS), CEPS, Mississippi River Transmission Corp. (MRT) and other non-affiliated companies alleging fraud, unjust enrichment and civil conspiracy with respect to rates charged to certain consumers of natural gas in Arkansas, Louisiana, Minnesota, Mississippi, Oklahoma and Texas. Subsequently, the plaintiffs dropped CEGT and MRT as defendants. Although the plaintiffs in the Miller County case sought class certification, no class was certified. In June 2007, the Arkansas Supreme Court determined that the Arkansas claims were within the sole and exclusive jurisdiction of the Arkansas Public Service Commission (APSC). In response to that ruling, in August 2007 the Miller County court stayed but refused to dismiss the Arkansas claims. In February 2008, the Arkansas Supreme Court directed the Miller County court to dismiss the entire case for lack of jurisdiction. The Miller County court subsequently dismissed the case in accordance with the Arkansas Supreme Court’s mandate and all appellate deadlines have expired.

In June 2007, the Company, CERC Corp., EGMC and other defendants in the Miller County case filed a petition in a district court in Travis County, Texas seeking a determination that the Railroad Commission has exclusive original jurisdiction over the Texas claims asserted in the Miller County case. In October 2007, CEFS and CEPS joined the petition in the Travis County case. In October 2008, the district court ruled that the Railroad Commission had exclusive original jurisdiction over the Texas claims asserted against the Company, CERC Corp., EGMC and the other defendants in the Miller County case. The time has not yet run for an appeal of this ruling.

In August 2007, the Arkansas plaintiff in the Miller County litigation initiated a complaint at the APSC seeking a decision concerning the extent of the APSC’s jurisdiction over the Miller County case and an investigation into the merits of the allegations asserted in his complaint with respect to CERC. That complaint remains pending at the APSC.

In February 2003, a lawsuit was filed in state court in Caddo Parish, Louisiana against CERC with respect to rates charged to a purported class of certain consumers of natural gas and gas service in the State of Louisiana. In February 2004, another suit was filed in state court in Calcasieu Parish, Louisiana against CERC seeking to recover alleged overcharges for gas or gas services allegedly provided by CERC to a purported class of certain consumers of natural gas and gas service without advance approval by the Louisiana Public Service Commission (LPSC). At the time of the filing of each of the Caddo and Calcasieu Parish cases, the plaintiffs in those cases filed petitions with the LPSC relating to the same alleged rate overcharges. The Caddo and Calcasieu Parish lawsuits were stayed pending the resolution of the petitions filed with the LPSC. In August 2007, the LPSC issued an order approving a Stipulated Settlement in the review initiated by the plaintiffs in the Calcasieu Parish litigation. In the LPSC proceeding, CERC’s gas purchases were reviewed back to 1971. The review concluded that CERC’s gas costs were “reasonable and prudent,” but CERC agreed to credit to jurisdictional customers approximately $920,000, including interest, related to certain off-system sales. The refund will be completed in the fourth quarter of 2008. A similar review by the LPSC related to the Caddo Parish litigation was resolved without additional payment by CERC. In October 2008, the courts considering the Caddo and Calcasieu Parish cases dismissed these cases pursuant to motions to dismiss. Although the time for appeal of that dismissal has not run, CERC believes these proceedings have been substantially concluded.

Storage Facility Litigation. In February 2007, an Oklahoma district court in Coal County, Oklahoma, granted a summary judgment against CEGT in a case, Deka Exploration, Inc. v. CenterPoint Energy, filed by holders of oil and gas leaseholds and some mineral interest owners in lands underlying CEGT’s Chiles Dome Storage Facility. The dispute concerns “native gas” that may have been in the Wapanucka formation underlying the Chiles Dome facility when that facility was constructed in 1979 by a CERC entity that was the predecessor in interest of CEGT. The court ruled that the plaintiffs own native gas underlying those lands, since neither CEGT nor its predecessors had condemned those ownership interests. The court rejected CEGT’s contention that the claim should be barred by

Table of Contents

t he statute of limitations, since the suit was filed over 25 years after the facility was constructed. The court also rejected CEGT’s contention that the suit is an impermissible attack on the determinations the FERC and Oklahoma Corporation Commission made regarding the absence of native gas in the lands when the facility was constructed. The summary judgment ruling was only on the issue of liability, though the court did rule that CEGT has the burden of proving that any gas in the Wapanucka formation is gas that has been injected and is not native gas. Further hearings and orders of the court are required to specify the appropriate relief for the plaintiffs. CEGT plans to appeal through the Oklahoma court system any judgment that imposes liability on CEGT in this matter. The Company and CERC do not expect the outcome of this matter to have a material impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Environmental Matters

Manufactured Gas Plant Sites. CERC and its predecessors operated manufactured gas plants (MGP) in the past. In Minnesota, CERC has completed remediation on two sites, other than ongoing monitoring and water treatment. There are five remaining sites in CERC’s Minnesota service territory. CERC believes that it has no liability with respect to two of these sites.

At September 30, 2008, CERC had accrued $14 million for remediation of these Minnesota sites and the estimated range of possible remediation costs for these sites was $4 million to $35 million based on remediation continuing for 30 to 50 years. The cost estimates are based on studies of a site or industry average costs for remediation of sites of similar size. The actual remediation costs will be dependent upon the number of sites to be remediated, the participation of other potentially responsible parties (PRP), if any, and the remediation methods used. CERC has utilized an environmental expense tracker mechanism in its rates in Minnesota to recover estimated costs in excess of insurance recovery. As of September 30, 2008, CERC had collected $13 million from insurance companies and rate payers to be used for future environmental remediation.

In addition to the Minnesota sites, the United States Environmental Protection Agency and other regulators have investigated MGP sites that were owned or operated by CERC or may have been owned by one of its former affiliates. CERC has been named as a defendant in a lawsuit filed in the United States District Court, District of Maine, under which contribution is sought by private parties for the cost to remediate former MGP sites based on the previous ownership of such sites by former affiliates of CERC or its divisions. CERC has also been identified as a PRP by the State of Maine for a site that is the subject of the lawsuit. In June 2006, the federal district court in Maine ruled that the current owner of the site is responsible for site remediation but that an additional evidentiary hearing is required to determine if other potentially responsible parties, including CERC, would have to contribute to that remediation. The Company is investigating details regarding the site and the range of environmental expenditures for potential remediation. However, CERC believes it is not liable as a former owner or operator of the site under the Comprehensive Environmental, Response, Compensation and Liability Act of 1980, as amended, and applicable state statutes, and is vigorously contesting the suit and its designation as a PRP.

Mercury Contamination. The Company’s pipeline and distribution operations have in the past employed elemental mercury in measuring and regulating equipment. It is possible that small amounts of mercury may have been spilled in the course of normal maintenance and replacement operations and that these spills may have contaminated the immediate area with elemental mercury. The Company has found this type of contamination at some sites in the past, and the Company has conducted remediation at these sites. It is possible that other contaminated sites may exist and that remediation costs may be incurred for these sites. Although the total amount of these costs is not known at this time, based on the Company’s experience and that of others in the natural gas industry to date and on the current regulations regarding remediation of these sites, the Company believes that the costs of any remediation of these sites will not be material to the Company’s financial condition, results of operations or cash flows.

Asbestos. Some facilities owned by the Company contain or have contained asbestos insulation and other asbestos-containing materials. The Company or its subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a number of individuals who claim injury due to exposure to asbestos. Some of the claimants have worked at locations owned by the Company, but most existing claims relate to facilities previously owned by the Company or its subsidiaries. The Company anticipates that additional claims like those received may be asserted in the future. In 2004, the Company 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

Table of Contents

separation of the generating business from the Company 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 the Company has agreed to continue to defend such claims to the extent they are covered by insurance maintained by the Company, subject to reimbursement of the costs of such defense from the purchaser. Although their ultimate outcome cannot be predicted at this time, the Company intends to continue vigorously contesting claims that it does not consider to have merit and 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.

Groundwater Contamination Litigation. Predecessor entities of CERC, along with several other entities, are defendants in litigation, St. Michel Plantation, LLC, et al, v. White, et al ., pending in civil district court in Orleans Parish, Louisiana. In the lawsuit, the plaintiffs allege that their property in Terrebonne Parish, Louisiana suffered salt water contamination as a result of oil and gas drilling activities conducted by the defendants. Although a predecessor of CERC held an interest in two oil and gas leases on a portion of the property at issue, neither it nor any other CERC entities drilled or conducted other oil and gas operations on those leases. In July 2008, experts for the plaintiffs filed a report in this litigation in which they claimed that it would cost approximately $105 million to remediate the alleged contamination on property covered by the leases in which the defendants, including CERC’s predecessor company, held interests. CERC’s experts, however, believe that the claims of plaintiffs’ experts are greatly exaggerated and that actual costs for remediation would be materially less than the amounts asserted in the report of the plaintiffs’ experts. CERC is disputing responsibility for remediation of this property and does not expect the outcome of this litigation to have a material adverse impact on the financial condition, results of operations or cash flows of either the Company or CERC.

Other Environmental. From time to time the Company has received notices from regulatory authorities or others regarding its status as a PRP 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.

Guaranties

Prior to the Company’s distribution of its ownership in RRI to its shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, the Company, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

The potential exposure of CERC under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, the Company and CERC believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in

Table of Contents

the event market conditions change adversely, the Company would retain exposure to the counterparty under the guaranty.

(11)	Income Taxes

During the three months and nine months ended September 30, 2007, the effective tax rate was 37% and 35%, respectively. During the three months and nine months ended September 30, 2008, the effective tax rate was 36% and 37%, respectively. The most significant item affecting the comparability of the effective tax rate is the 2008 classification of approximately $2 million and $9 million for the three and nine months ended September 30, 2008, respectively, of Texas margin tax as an income tax for CenterPoint Houston.

The following table summarizes the Company’s liability for uncertain tax positions in accordance with FASB Interpretation No. (FIN) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109,” at December 31, 2007 and September 30, 2008 (in millions):

	December 31, 2007		September 30, 2008
Liability for uncertain tax positions	$	82	$	102
Portion of liability for uncertain tax positions that, if recognized, would reduce the effective income tax rate		10		13
Interest accrued on uncertain tax positions		4		8

(12)	Earnings Per Share

The following table reconciles numerators and denominators of the Company’s basic and diluted earnings per share calculations:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
	2007		2008		2007		2008
	(in millions, except share and per share amounts)
Basic earnings per share calculation:
Net income	$	91	$	136	$	291	$	360

Weighted average shares outstanding		321,192,000		342,228,000		320,071,000		333,652,000

Basic earnings per share	$	0.29	$	0.40	$	0.91	$	1.08

Diluted earnings per share calculation:
Net income	$	91	$	136	$	291	$	360

Weighted average shares outstanding		321,192,000		342,228,000		320,071,000		333,652,000
Plus: Incremental shares from assumed conversions:
Stock options (1)		1,027,000		841,000		1,104,000		846,000
Restricted stock units		1,713,000		1,515,000		1,713,000		1,515,000
2.875% convertible senior notes		—		—		389,000		—
3.75% convertible senior notes		17,042,000		—		18,945,000		6,174,000
Weighted average shares assuming dilution		340,974,000		344,584,000		342,222,000		342,187,000

Diluted earnings per share	$	0.27	$	0.39	$	0.85	$	1.05

__________

(1)

Options to purchase 3,474,562 shares were outstanding for both the three and nine months ended September 30, 2007, and options to purchase 2,720,083 shares were outstanding for both the three and nine months ended September 30, 2008, but were not included in the computation of diluted earnings per share because the options’ exercise price was greater than the average market price of the common shares for the respective periods.

Substantially all of the Company’s 3.75% contingently convertible senior notes provided for settlement of the principal portion in cash rather than stock. In accordance with Emerging Issues Task Force Issue No. 04-8, “Accounting Issues related to Certain Features of Contingently Convertible Debt and the Effect on Diluted Earnings

Table of Contents

Per Share,” the portion of the conversion value of such notes that must be settled in cash rather than stock is excluded from the computation of diluted earnings per share from continuing operations. The Company included the conversion spread in the calculation of diluted earnings per share when the average market price of the Company’s common stock in the respective reporting period exceeded the conversion price. In April 2008, the Company announced a call for redemption of its 3.75% convertible senior notes on May 30, 2008. At the time of the announcement, the notes were convertible at the option of the holders, and substantially all of the notes were submitted for conversion on or prior to the May 30, 2008 redemption date. During the nine months ended September 30, 2008, the Company issued 16.9 million shares of its common stock and paid cash of approximately $532 million to settle conversions of approximately $535 million principal amount of its 3.75% convertible senior notes.

(13)	Reportable Business Segments

The Company’s determination of reportable business segments considers the strategic operating units under which the Company manages sales, allocates resources and assesses performance of various products and services to wholesale or retail customers in differing regulatory environments. The accounting policies of the business segments are the same as those described in the summary of significant accounting policies except that some executive benefit costs have not been allocated to business segments. The Company uses operating income as the measure of profit or loss for its business segments.

The Company’s reportable business segments include the following: Electric Transmission & Distribution, Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines, Field Services and Other Operations. The electric transmission and distribution function (CenterPoint Houston) is reported in the Electric Transmission & Distribution business segment. Natural Gas Distribution consists of intrastate natural gas sales to, and natural gas transportation and distribution for, residential, commercial, industrial and institutional customers. Competitive Natural Gas Sales and Services represents the Company’s non-rate regulated gas sales and services operations, which consist of three operational functions: wholesale, retail and intrastate pipelines. The Interstate Pipelines business segment includes the interstate natural gas pipeline operations. The Field Services business segment includes the natural gas gathering operations. Other Operations consists primarily of other corporate operations which support all of the Company’s business operations.

Financial data for business segments and products and services are as follows (in millions):

	For the Three Months Ended September 30, 2007
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	528	(1)	$	—		$	196
Natural Gas Distribution		457			1			(8	)
Competitive Natural Gas Sales and Services		758			12			4
Interstate Pipelines		100			37			70
Field Services		36			8			26
Other Operations		3			—			(1	)
Eliminations		—			(58	)		—
Consolidated	$	1,882		$	—		$	287

	For the Three Months Ended September 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income (Loss)
Electric Transmission & Distribution	$	552	(1)	$	—		$	202
Natural Gas Distribution		548			2			(6	)
Competitive Natural Gas Sales and Services		1,256			13			35
Interstate Pipelines		96			47			55
Field Services		60			11			44
Other Operations		3			—			7
Eliminations		—			(73	)		—
Consolidated	$	2,515		$	—		$	337

Table of Contents

	For the Nine Months Ended September 30, 2007
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of December 31, 2007
Electric Transmission & Distribution	$	1,399	(1)	$	—		$	457		$	8,358
Natural Gas Distribution		2,594			7			129			4,332
Competitive Natural Gas Sales and Services		2,679			36			56			1,221
Interstate Pipelines		247			101			166			3,007
Field Services		94			31			75			669
Other Operations		8			—			(1	)		1,956	(2)
Eliminations		—			(175	)		—			(1,671	)
Consolidated	$	7,021		$	—		$	882		$	17,872

	For the Nine Months Ended September 30, 2008
	Revenues from External Customers			Net Intersegment Revenues			Operating Income			Total Assets as of September 30, 2008
Electric Transmission & Distribution	$	1,471	(1)	$	—		$	457	(3)	$	9,141
Natural Gas Distribution		2,969			7			119			4,354
Competitive Natural Gas Sales and Services		3,599			33			36			1,193
Interstate Pipelines		337			131			227	(4)		3,539
Field Services		164			27			121	(5)		792
Other Operations		8			—			10			1,736	(2)
Eliminations		—			(198	)		—			(1,723	)
Consolidated	$	8,548		$	—		$	970		$	19,032

________

(1)

Sales to subsidiaries of RRI in each of the three months ended September 30, 2007 and 2008 represented approximately $196 million and $199 million, respectively, of CenterPoint Houston’s transmission and distribution revenues. Sales to subsidiaries of RRI in the nine months ended September 30, 2007 and 2008 represented approximately $496 million and $492 million, respectively.

(2)

Included in total assets of Other Operations as of December 31, 2007 and September 30, 2008 are pension assets of $231 million and $247 million, respectively. Also included in total assets of Other Operations as of December 31, 2007 and September 30, 2008, are pension-related regulatory assets of $319 million and $311 million, respectively, which resulted from the Company’s 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).”

(3)	Included in operating income of Electric Transmission & Distribution for the nine months ended September 30, 2008 is a $9 million gain on sale of land.

(4)

Included in operating income of Interstate Pipelines for the three and nine months ended September 30, 2008 is a $7 million loss on pipeline assets removed from service. Also included in operating income of Interstate Pipelines for the nine months ended September 30, 2008 is an $18 million gain on the sale of two storage development projects.

(5)	Included in operating income of Field Services for the nine months ended September 30, 2008 is an $11 million gain related to a settlement and contract buyout of one of its customers and a $6 million gain on the sale of assets.

(14)	Subsequent Event

On October 30, 2008, the Company’s board of directors declared a regular quarterly cash dividend of $0.1825 per share of common stock payable on December 10, 2008, to shareholders of record as of the close of business on November 14, 2008.

Table of Contents

Item 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS OF CENTERPOINT ENERGY, INC. AND SUBSIDIARIES

The following discussion and analysis should be read in combination with our Interim Condensed Financial Statements contained in this Form 10-Q and our Annual Report on Form 10-K for the year ended December 31, 2007 (2007 Form 10-K).

EXECUTIVE SUMMARY

Recent Events

Hurricane Ike

The electric delivery system of our electric transmission and distribution subsidiary, CenterPoint Energy Houston Electric, LLC (CenterPoint Houston), suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast early Saturday, September 13, 2008.

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

In addition to storm restoration costs, CenterPoint Houston estimates that it lost approximately $17 million in revenue through September 30, 2008, and will continue to lose minor amounts of revenue that would otherwise have been anticipated from those customers whose service will not be restored for a longer period. Within the first 18 days after the storm, CenterPoint Houston had restored power to all customers capable of receiving it.

CenterPoint Houston is deferring the uninsured storm restoration costs as management believes it is probable that such costs will be recovered through the regulatory process. As a result, storm restoration costs will not affect our or CenterPoint Houston’s reported net income for 2008. As of September 30, 2008, CenterPoint Houston recorded an increase of $141 million in construction work in progress and $434 million in regulatory assets for restoration costs incurred through September 30, 2008. Approximately $503 million of these costs are based on estimates and are included in accounts payable as of September 30, 2008. Additional restoration costs will continue to be incurred during the fourth quarter of 2008 and possibly during the first quarter of 2009.

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

The natural gas distribution business (Gas Operations) of CenterPoint Energy Resources Corp. (CERC Corp., and, together with its subsidiaries, CERC) also suffered some damage to its system in Houston, Texas and in other portions of its service territory across Texas and Louisiana. As of September 30, 2008, Gas Operations has deferred

Table of Contents

approximately $3 million of costs related to Hurricane Ike for recovery as part of future natural gas distribution rate proceedings.

CERC Receivables Facility

CERC’s receivables facility terminated on October 28, 2008. Advances under the receivables facility of $150 million were repaid upon termination of the facility. CERC is currently negotiating a new receivables facility to replace the expired facility, but there can be no assurance that a new facility with acceptable terms can be obtained.

Interstate Pipeline Expansion

Southeast Supply Header. The Southeast Supply Header (SESH) pipeline project, a joint venture between CenterPoint Energy Gas Transmission, a wholly owned subsidiary of CERC Corp., and Spectra Energy Corp., received Federal Energy Regulatory Commission (FERC) approval to begin operation with limited exclusions in August 2008. The pipeline was placed into commercial service on September 6, 2008. This new 270-mile pipeline, which extends from the Perryville Hub, near Perryville, Louisiana, to an interconnection with the Gulf Stream Natural Gas System near Mobile, Alabama, has a maximum design capacity of approximately 1 billion cubic feet per day. The pipeline represents a new source of natural gas supply for the Southeast United States and offers greater supply diversity to this region. We now expect our share of SESH’s net costs to be approximately $620 million.

CONSOLIDATED RESULTS OF OPERATIONS

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

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Revenues	$	1,882		$	2,515		$	7,021		$	8,548
Expenses		1,595			2,178			6,139			7,578
Operating Income		287			337			882			970
Interest and Other Finance Charges		(126	)		(116	)		(368	)		(344	)
Interest on Transition Bonds		(30	)		(34	)		(93	)		(102	)
Other Income, net		14			26			24			49
Income Before Income Taxes		145			213			445			573
Income Tax Expense		(54	)		(77	)		(154	)		(213	)
Net Income	$	91		$	136		$	291		$	360

Basic Earnings Per Share	$	0.29		$	0.40		$	0.91		$	1.08

Diluted Earnings Per Share	$	0.27		$	0.39		$	0.85		$	1.05

Table of Contents

Three months ended September 30, 2008 compared to three months ended September 30, 2007

We reported consolidated net income of $136 million ($0.39 per diluted share) for the three months ended September 30, 2008 as compared to $91 million ($0.27 per diluted share) for the same period in 2007. The increase in net income of $45 million was primarily due to increased operating income of $31 million in our Competitive Natural Gas Sales and Services business segment, increased operating income of $18 million in our Field Services business segment, decreased interest expense of $10 million, excluding transition bonds, and increased equity earnings of $18 million included in Other Income, net, partially offset by decreased operating income of $15 million in our Interstate Pipelines business segment.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

We reported consolidated net income of $360 million ($1.05 per diluted share) for the nine months ended September 30, 2008 as compared to $291 million ($0.85 per diluted share) for the same period in 2007. The increase in net income of $69 million was primarily due to increased operating income of $61 million in our Interstate Pipelines business segment, increased operating income of $46 million in our Field Services business segment, increased equity earnings of $36 million included in Other Income, net, and decreased interest expense of $24 million, excluding interest on transition bonds, partially offset by decreased operating income of $20 million in our Competitive Natural Gas Sales and Services business segment, decreased operating income of $10 million in our Natural Gas Distribution business segment and decreased operating income of $10 million from our electric transmission and distribution utility, excluding the transition bond companies.

Income Tax Expense

RESULTS OF OPERATIONS BY BUSINESS SEGMENT

The following table presents operating income (in millions) for each of our business segments for the three and nine months ended September 30, 2007 and 2008.

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Electric Transmission & Distribution	$	196		$	202		$	457		$	457
Natural Gas Distribution		(8	)		(6	)		129			119
Competitive Natural Gas Sales and Services		4			35			56			36
Interstate Pipelines		70			55			166			227
Field Services		26			44			75			121
Other Operations		(1	)		7			(1	)		10
Total Consolidated Operating Income	$	287		$	337		$	882		$	970

Electric Transmission & Distribution

For information regarding factors that may affect the future results of operations of our Electric Transmission & Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Electric Transmission & Distribution Business,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

Table of Contents

The following tables provide summary data of our Electric Transmission & Distribution business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues:
Electric transmission and distribution utility	$	445	$	455	$	1,187	$	1,220
Transition bond companies		83		97		212		251
Total revenues		528		552		1,399		1,471
Expenses:
Operation and maintenance, excluding transition bond companies		163		167		467		502
Depreciation and amortization, excluding transition bond companies		58		71		182		208
Taxes other than income taxes		58		48		171		153
Transition bond companies		53		64		122		151
Total expenses		332		350		942		1,014
Operating Income	$	196	$	202	$	457	$	457

Operating Income:
Electric transmission and distribution utility	$	155	$	169	$	335	$	352
Competition transition charge		11		—		32		5
Transition bond companies (1)		30		33		90		100
Total segment operating income	$	196	$	202	$	457	$	457

Throughput (in gigawatt-hours (GWh)):
Residential		8,381		8,446		19,060		19,623
Total		22,726		21,594		58,561		58,523

Average number of metered customers:
Residential		1,782,281		1,822,351		1,767,431		1,812,821
Total		2,022,448		2,066,538		2,006,344		2,055,723

___________

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

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Electric Transmission & Distribution business segment reported operating income of $202 million for the three months ended September 30, 2008, consisting of $169 million from the regulated electric transmission and distribution utility (TDU) and $33 million related to transition bond companies. For the three months ended September 30, 2007, operating income totaled $196 million, consisting of $155 million from the TDU, exclusive of an additional $11 million from the competition transition charge (CTC), and $30 million related to transition bond companies. Revenues for the TDU increased due to increased usage ($13 million), continued customer growth ($8 million), with over 42,000 metered customers added since September 30, 2007, and increased transmission-related revenues ($5 million), partially offset by the loss of revenues due to Hurricane Ike ($17 million). Operation and maintenance expense increased primarily due to higher transmission costs ($6 million) and increased support services ($2 million), partially offset by normal operating and maintenance expenses that were postponed as a result of Hurricane Ike restoration efforts ($5 million). Depreciation and amortization increased $13 million primarily due to amounts related to the CTC, which were offset by similar amounts in revenues ($11 million). Taxes other than income taxes declined $10 million as a result of Texas margin taxes being classified as an income tax for financial reporting purposes in 2008 ($5 million) and a refund of prior year state franchise taxes ($5 million).

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Electric Transmission & Distribution business segment reported operating income of $457 million for the nine months ended September 30, 2008, consisting of $352 million from the TDU, exclusive of an additional $5 million from the CTC, and $100 million related to transition bond companies. For the nine months ended

Table of Contents

September 30, 2007, operating income totaled $457 million, consisting of $335 million from the TDU, exclusive of an additional $32 million from the CTC, and $90 million related to transition bond companies. Revenues for the TDU increased due to customer growth, with over 42,000 metered customers added since September 30, 2007 ($20 million), increased usage ($18 million) primarily caused by favorable weather experienced in 2008 net of conservation, increased transmission-related revenues ($14 million) and increased ancillary services ($6 million), partially offset by the reduced revenues due to Hurricane Ike ($17 million) and the settlement of the final fuel reconciliation in 2007 ($4 million). Operation and maintenance expense increased primarily due to higher transmission costs ($22 million), the settlement of the final fuel reconciliation in 2007 ($13 million) and increased support services ($10 million), partially offset by a gain on sale of land ($9 million) and normal operating and maintenance expenses that were postponed as a result of Hurricane Ike restoration efforts ($5 million). Depreciation and amortization increased $26 million primarily due to amounts related to the CTC, which were offset by similar amounts in revenues ($21 million). Taxes other than income taxes declined $18 million primarily as a result of the Texas margin tax being classified as an income tax for financial reporting purposes in 2008 ($16 million) and a refund of prior year state franchise taxes ($5 million).

Natural Gas Distribution

For information regarding factors that may affect the future results of operations of our Natural Gas Distribution business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

The following table provides summary data of our Natural Gas Distribution business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007		2008
Revenues	$	458		$	550		$	2,601	$	2,976
Expenses:
Natural gas		267			351			1,845		2,196
Operation and maintenance		139			139			421		436
Depreciation and amortization		38			40			114		118
Taxes other than income taxes		22			26			92		107
Total expenses		466			556			2,472		2,857
Operating Income (Loss)	$	(8	)	$	(6	)	$	129	$	119

Throughput (in Bcf):
Residential		12			13			118		117
Commercial and industrial		42			41			168		171
Total Throughput		54			54			286		288

Average number of customers:
Residential		2,910,041			2,937,618			2,927,122		2,956,500
Commercial and industrial		246,021			245,514			246,382		248,759
Total		3,156,062			3,183,132			3,173,504		3,205,259

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Natural Gas Distribution business segment reported an operating loss of $6 million for the three months ended September 30, 2008 compared to an operating loss of $8 million for the three months ended September 30, 2007. Operating margin (revenues less the cost of gas) increased $8 million primarily as a result of rate increases ($2 million), growth ($1 million), with the addition of almost 26,000 customers since September 2007, increased other revenues ($3 million), and recovery of higher gross receipts taxes ($3 million), which are offset in other tax expense. Operation and maintenance expenses remained flat. Depreciation and amortization and taxes other than income taxes both increased primarily as a result of an increase in the investment in property, plant and equipment.

Table of Contents

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Natural Gas Distribution business segment reported operating income of $119 million for the nine months ended September 30, 2008 compared to operating income of $129 million for the nine months ended September 30, 2007. Operating margin improved $24 million primarily as a result of rate increases ($14 million), growth from the addition of nearly 26,000 customers since September 30, 2007 ($5 million), and recovery of higher gross receipts taxes ($13 million) and energy-efficiency costs ($4 million), both of which are offset by the related expenses. These margin increases were partially offset by a combination of lower usage and the cost of the weather hedge ($12 million). Operation and maintenance expenses increased $15 million primarily as a result of increased bad debt expense ($4 million), higher customer-related costs and support services costs ($9 million) and increased costs of materials and supplies ($3 million), partially offset by lower employee benefits costs ($3 million). Depreciation and amortization and taxes other than income taxes both increased primarily as a result of an increase in the investment in property, plant and equipment.

Competitive Natural Gas Sales and Services

For information regarding factors that may affect the future results of operations of our Competitive Natural Gas Sales and Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

The following table provides summary data of our Competitive Natural Gas Sales and Services business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput and customer data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues	$	770	$	1,269	$	2,715	$	3,632
Expenses:
Natural gas		756		1,225		2,631		3,567
Operation and maintenance		7		8		23		26
Depreciation and amortization		3		1		4		2
Taxes other than income taxes		—		—		1		1
Total expenses		766		1,234		2,659		3,596
Operating Income	$	4	$	35	$	56	$	36

Throughput (in Bcf)		119		125		393		392

Average number of customers		6,976		9,245		7,014		8,974

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of $35 million for the three months ended September 30, 2008 compared to operating income of $4 million for the three months ended September 30, 2007. The increase in operating income of $31 million in the third quarter of 2008 was primarily due to higher margins (revenues less natural gas costs) ($7 million) compared to the same period last year. In addition, the third quarter of 2008 included a positive mark-to-market for non-trading financial derivatives ($46 million) described below and a write-down of natural gas inventory to the lower of average cost or market ($24 million), compared to the gain from mark-to-market accounting ($2 million) and an inventory write-down ($5 million) for the same period of 2007. Natural gas that is purchased for inventory is accounted for at the lower of average cost or market price at each balance sheet date.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Competitive Natural Gas Sales and Services business segment reported operating income of $36 million for the nine months ended September 30, 2008 compared to $56 million for the nine months ended September 30, 2007,

Table of Contents

a decrease in operating income of $20 million. The nine months ended September 30, 2008, included $24 million in inventory write-downs compared to $11 million in inventory write-downs for the same period of 2007. Additionally, the nine months ended September 30, 2008, included $6 million in gains on sales of gas from previously written down inventory compared to $32 million for the same period of 2007. Our Competitive Natural Gas Sales and Services business segment purchases and stores natural gas to meet certain future sales requirements and enters into derivative contracts to hedge the economic value of the future sales. The favorable mark-to-market accounting for non-trading financial derivatives for the first nine months of 2008 of $14 million versus the unfavorable mark-to-market accounting of $12 million for the same period in 2007 accounted for a net $26 million increase in operating margins. The additional decrease in operating income of $7 million for the first nine months ended September 30, 2008 compared to the same period last year was primarily due to a reduction in operating margin as basis and summer/winter spreads narrowed.

Interstate Pipelines

For information regarding factors that may affect the future results of operations of our Interstate Pipelines business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

The following table provides summary data of our Interstate Pipelines business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput data):

	Three Months Ended September 30,				Nine Months Ended September 30,
	2007		2008		2007		2008
Revenues	$	137	$	143	$	348	$	468
Expenses:
Natural gas		27		24		55		97
Operation and maintenance		29		47		85		93
Depreciation and amortization		11		11		32		34
Taxes other than income taxes		—		6		10		17
Total expenses		67		88		182		241
Operating Income	$	70	$	55	$	166	$	227

Transportation throughput (in Bcf) :		312		360		880		1,145

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Interstate Pipelines business segment reported operating income of $55 million for the three months ended September 30, 2008 compared to $70 million for the three months ended September 30, 2007. The decrease in operating income is due to higher operation and maintenance expense ($18 million), including a write-down associated with pipeline assets removed from service ($7 million), and higher taxes other than income taxes ($6 million) largely due to tax refunds in 2007 related to certain state tax issues. These increases in expenses are partially offset by higher margins (revenues less natural gas costs) primarily driven by the Carthage to Perryville pipeline ($7 million) and increased other transportation services ($6 million) which are partially offset by reduced margins on ancillary services ($4 million).

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Interstate Pipelines business segment reported operating income of $227 million for the nine months ended September 30, 2008 compared to $166 million for the nine months ended September 30, 2007. The increase in operating income is primarily driven by increased margins (revenues less natural gas costs) on the Carthage to Perryville pipeline that went into service in May 2007 ($43 million), increased transportation and ancillary services ($35 million). These increases are partially offset by higher operation and maintenance expenses ($8 million), including a write-down associated with pipeline assets removed from service ($7 million) and a gain on the sale of two storage development projects ($18 million). Increased depreciation expense ($2 million) and higher taxes other than income taxes ($7 million), largely due to tax refunds in 2007, also offset increased margins.

Table of Contents

Field Services

For information regarding factors that may affect the future results of operations of our Field Services business segment, please read “Risk Factors — Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses,” “— Risk Factors Associated with Our Consolidated Financial Condition” and “— Risks Common to Our Business and Other Risks” in Item 1A of Part I of our 2007 Form 10-K and “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

The following table provides summary data of our Field Services business segment for the three and nine months ended September 30, 2007 and 2008 (in millions, except throughput data):

	Three Months Ended September 30,					Nine Months Ended September 30,
	2007			2008		2007			2008
Revenues	$	44		$	71	$	125		$	191
Expenses:
Natural gas		(2	)		5		(9	)		11
Operation and maintenance		17			19		49			48
Depreciation and amortization		2			3		8			9
Taxes other than income taxes		1			—		2			2
Total expenses		18			27		50			70
Operating Income	$	26		$	44	$	75		$	121

Gathering throughput (in Bcf) :		104			109		297			311

Three months ended September 30, 2008 compared to three months ended September 30, 2007

Our Field Services business segment reported operating income of $44 million for the three months ended September 30, 2008 compared to $26 million for the three months ended September 30, 2007. The increase in operating income of $18 million was primarily driven by higher margins (revenues less natural gas costs) from gas gathering and ancillary services ($20 million), offset by increased operation and maintenance expenses ($2 million).

In addition, this business segment recorded equity income of $2 million and $4 million in the three months ended September 30, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other, net under the Other Income (Expense) caption.

Nine months ended September 30, 2008 compared to nine months ended September 30, 2007

Our Field Services business segment reported operating income of $121 million for the nine months ended September 30, 2008 compared to $75 million for the nine months ended September 30, 2007. The increase in operating income of $46 million resulted from higher margins (revenue less natural gas costs) from gas gathering, ancillary services and higher commodity prices ($35 million) and a one-time gain related to a settlement and contract buyout of one of our customers ($11 million). Operating expenses remain constant from 2007 to 2008 with the increases in expenses associated with new assets and general cost increases offset by a one-time gain related to the sale of assets recognized in the first quarter of 2008 ($6 million).

In addition, this business segment recorded equity income of $6 million and $12 million in the nine months ended September 30, 2007 and 2008, respectively, from its 50 percent interest in a jointly-owned gas processing plant. These amounts are included in Other, net under the Other Income (Expense) caption.

Table of Contents

Other Operations

The following table shows the operating income of our Other Operations business segment for the three and nine months ended September 30, 2007 and 2008 (in millions):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2007			2008			2007			2008
Revenues	$	3		$	3		$	8		$	8
Expenses		4			(4	)		9			(2	)
Operating Income (Loss)	$	(1	)	$	7		$	(1	)	$	10

CERTAIN FACTORS AFFECTING FUTURE EARNINGS

For information on other developments, factors and trends that may have an impact on our future earnings, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Certain Factors Affecting Future Earnings” in Item 7 of Part II and “Risk Factors” in Item 1A of Part I of our 2007 Form 10-K, “Cautionary Statement Regarding Forward-Looking Information” and “Risk Factors” in this Quarterly Report on Form 10-Q.

LIQUIDITY AND CAPITAL RESOURCES

Historical Cash Flows

The following table summarizes the net cash provided by (used in) operating, investing and financing activities for the nine months ended September 30, 2007 and 2008:

	Nine Months Ended September 30,
	2007			2008
	(in millions)
Cash provided by (used in):
Operating activities	$	492		$	724
Investing activities		(933	)		(991	)
Financing activities		368			222

Cash Provided by Operating Activities

Net cash provided by operating activities in the first nine months of 2008 increased $232 million compared to the same period in 2007 primarily due to increased cash provided by net accounts receivable/payable ($242 million), increased fuel cost recovery ($79 million), increased net income ($69 million) and decreased tax payments ($7 million), partially offset by increased net margin deposits ($145 million), increased net regulatory assets and liabilities ($105 million) and increased gas storage inventory ($33 million).

Cash Used in Investing Activities

Net cash used in investing activities increased $58 million in the first nine months of 2008 as compared to the same period in 2007 primarily due to increased investment in unconsolidated affiliates ($167 million) and increased notes receivable from unconsolidated affiliates ($124 million) primarily related to the SESH pipeline project, and increased restricted cash of transition bond companies ($8 million), offset by decreased capital expenditures ($219 million) primarily related to the completion of certain pipeline projects for our Interstate Pipelines business segment.

Cash Provided by Financing Activities

Net cash provided by financing activities in the first nine months of 2008 decreased $146 million compared to the same period in 2007 primarily due to decreased short-term borrowings ($45 million), decreased net proceeds from commercial paper ($76 million), increased repayments of long-term debt ($864 million), which were partially

Table of Contents

offset by increased proceeds from long-term debt ($688 million), and increased net borrowings under long-term revolving credit facilities ($157 million).

Future Sources and Uses of Cash

Our liquidity and capital requirements are affected primarily by our results of operations, capital expenditures, debt service requirements, tax payments, working capital needs, various regulatory actions and appeals relating to such regulatory actions. Our principal cash requirements for the remaining three months of 2008 include the following:

approximately $385 million of capital requirements;

estimated restoration costs related to Hurricane Ike of approximately $600 million;

investment in and advances to SESH of approximately $30 million; and

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

In addition to these cash requirements, we expect to receive a tax refund of approximately $75 million in the remaining three months of 2008.

We expect that borrowings under our credit facilities, tax refunds and anticipated cash flows from operations will be sufficient to meet our cash needs in 2008. Cash needs or discretionary financing or refinancing may also result in the issuance of equity or debt securities in the capital markets or the arrangement of additional credit facilities. Issuances of equity or debt in the capital markets and additional credit facilities may not, however, be available to us on acceptable terms.

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

Off-Balance Sheet Arrangements. Other than operating leases and the guaranties described below, we have no off-balance sheet arrangements.

Prior to the distribution of our ownership in Reliant Energy, Inc. (RRI) to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for CERC’s benefit, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In December 2007, we, CERC and RRI amended that agreement and CERC released the letters of credit it held as security. Under the revised agreement RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

The potential exposure of CERC under the guaranties relates to payment of demand charges related to transportation contracts. RRI continues to meet its obligations under the contracts, and, on the basis of current market conditions, we and CERC believe that additional security is not needed at this time. However, if RRI should fail to perform its obligations under the contracts or if RRI should fail to provide adequate security in the event market conditions change adversely, we would retain exposure to the counterparty under the guaranty.

Table of Contents

Credit and Receivables Facilities. As of October 31, 2008, we had the following facilities (in millions):

Date Executed	Company	Type of Facility	Size of Facility			Amount Utilized at October 31, 2008			Termination Date
June 29, 2007	CenterPoint Energy	Revolver	$	1,200	(1)	$	308	(2)	June 29, 2012
June 29, 2007	CenterPoint Houston	Revolver		300	(1)		247	(3)	June 29, 2012
June 29, 2007	CERC Corp.	Revolver		950	(1)		919		June 29, 2012

________

(1) Lehman Brothers Bank, FSB, which had an approximately four percent participation in our credit facility and each of the credit facilities of CenterPoint Houston and CERC Corp., stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a reduction to the total available capacity of $44 million under our facility, $8 million under CenterPoint Houston's facility and $20 million under CERC Corp.'s facility. Effective November 7, 2008, we are terminating Lehman Brothers Bank, FSB, as a participating lender under our facility and CenterPoint Houston's facility, thereby causing a permanent reduction in the capacity of those facilities from the amounts shown in this column.

(2) Includes $281 million of borrowings and $27 million of outstanding letters of credit.

(3) Includes $243 million of borrowings and $4 million of outstanding letters of credit.

Our $1.2 billion credit facility has a first drawn cost of London Interbank Offered Rate (LIBOR) plus 55 basis points based on our current credit ratings. The facility contains a debt (excluding transition bonds) to earnings before interest, taxes, depreciation and amortization (EBITDA) covenant, which was modified in August 2008 so that the permitted ratio of debt to EBITDA will continue at its current level for the remaining term of the facility.

CenterPoint Houston’s $300 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CenterPoint Houston’s current credit ratings. The facility contains a debt (excluding transition bonds) to total capitalization covenant.

CERC Corp.’s $950 million credit facility’s first drawn cost is LIBOR plus 45 basis points based on CERC Corp.’s current credit ratings. The facility contains a debt to total capitalization covenant.

Under each of the credit facilities, an additional utilization fee of 5 basis points applies to borrowings any time more than 50% of the facility is utilized. The spread to LIBOR and the utilization fee fluctuate based on the borrower’s credit rating. Borrowings under each of the facilities are subject to customary terms and conditions. However, there is no requirement that we, CenterPoint Houston or CERC Corp. 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 each of the credit facilities are subject to acceleration upon the occurrence of events of default that we, CenterPoint Houston or CERC Corp. consider customary.

We, CenterPoint Houston and CERC Corp. are currently in compliance with the various business and financial covenants contained in the respective credit facilities.

Our $1.2 billion credit facility backstops a $1.0 billion CenterPoint Energy commercial paper program under which we began issuing commercial paper in June 2005. The $950 million CERC Corp. credit facility backstops a $950 million commercial paper program under which CERC Corp. began issuing commercial paper in February 2008. The CenterPoint Energy commercial paper is rated “Not Prime” by Moody’s Investors Service, Inc. (Moody’s), “A-2” by Standard & Poor’s Rating Services (S&P), a division of The McGraw-Hill Companies, and “F3” by Fitch, Inc. (Fitch). The CERC Corp. commercial paper is rated “P-3” by Moody’s, “A-2” by S&P, and “F2” by Fitch. As a result of the credit ratings on the two commercial paper programs, we do not expect to be able to rely on the sale of commercial paper to fund all of our short-term borrowing requirements. We cannot assure you that these ratings, or the credit ratings set forth below in “— Impact on Liquidity of a Downgrade in Credit 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

Table of Contents

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.

Securities Registered with the SEC. In October 2008, CenterPoint Energy and CenterPoint Houston jointly registered indeterminate principal amounts of CenterPoint Houston’s general mortgage bonds and CenterPoint Energy’s senior debt securities and junior subordinated debt securities and an indeterminate number of CenterPoint Energy’s shares of common stock, shares of preferred stock, as well as stock purchase contracts and equity units. In addition, CERC Corp. has a shelf registration statement covering $500 million principal amount of senior debt securities as a result of its registration statement filed in August 2008.

Temporary Investments. As of October 31, 2008, we had no external temporary investments.

Money Pool. We have a money pool through which the holding company and participating subsidiaries 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 our commercial paper.

Impact on Liquidity of a Downgrade in Credit Ratings. As of October 31, 2008, Moody’s, S&P, and Fitch had assigned the following credit ratings to senior debt of CenterPoint Energy and certain subsidiaries:

Moody’s

S&P

Fitch

Company/Instrument

Rating

Outlook(1)

Rating

Outlook(2)

Rating

Outlook(3)

CenterPoint Energy Senior Unsecured

Debt

Ba1

Stable

BBB-

Stable

BBB-

Stable

CenterPoint Houston Senior Secured

Debt (First Mortgage Bonds)

Baa2

Stable

BBB+

Stable

A-

Stable

CenterPoint Houston Senior Secured

Debt (General Mortgage Bonds)

Baa2

Stable

BBB+

Stable

BBB+

Stable

CERC Corp. Senior Unsecured Debt

Baa3

Stable

BBB

Stable

BBB

Stable

__________

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

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

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

In October 2008, Moody’s affirmed the credit ratings and stable outlook for CenterPoint Energy, CenterPoint Houston and CERC Corp. In October 2008, S&P published a report which confirmed the credit rating and stable outlook of CenterPoint Energy.

A decline in credit ratings could increase borrowing costs under our $1.2 billion credit facility, CenterPoint Houston’s $300 million credit facility and CERC Corp.’s $950 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. Additionally, a decline in credit ratings could increase cash collateral requirements of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments.

In September 1999, we issued 2.0% Zero-Premium Exchangeable Subordinated Notes due 2029 (ZENS) having an original principal amount of $1.0 billion of which $840 million remain outstanding. Each ZENS note is exchangeable at the holder’s option at any time for an amount of cash equal to 95% of the market value of the reference shares of Time Warner Inc. common stock (TW Common) attributable to each ZENS note. If our creditworthiness were to drop such that ZENS note holders thought our liquidity was adversely affected or the market for the ZENS notes were to become illiquid, some ZENS note holders might decide to exchange their ZENS notes for cash. Funds for the payment of cash upon exchange could be obtained from the sale of the shares of TW Common that we own or from other sources. We own shares of TW Common equal to approximately 100% of the

Table of Contents

reference shares used to calculate our obligation to the holders of the ZENS notes. ZENS note exchanges result in a cash outflow because deferred tax liabilities related to the ZENS notes and TW Common shares become current tax obligations when ZENS notes are exchanged or otherwise retired and TW Common shares are sold. A tax obligation of approximately $174 million relating to our “original issue discount” deductions on the ZENS would have been payable if all of the ZENS had been exchanged for cash on September 30, 2008. The ultimate tax obligation related to the ZENS notes continues to increase by the amount of the tax benefit realized each year and there could be a significant cash outflow when the taxes are paid as a result of the retirement of the ZENS notes.

CenterPoint Energy Services, Inc. (CES), a wholly owned subsidiary of CERC Corp. operating in our Competitive Natural Gas Sales and Services business segment, provides comprehensive natural gas sales and services primarily to commercial and industrial customers and electric and gas utilities throughout the central and eastern United States. In order to economically hedge its exposure to natural gas prices, CES uses derivatives with provisions standard for the industry, including those pertaining to credit thresholds. Typically, the credit threshold negotiated with each counterparty defines the amount of unsecured credit that such counterparty will extend to CES. To the extent that the credit exposure that a counterparty has to CES at a particular time does not exceed that credit threshold, CES is not obligated to provide collateral. Mark-to-market exposure in excess of the credit threshold is routinely collateralized by CES. As of September 30, 2008, the amount posted as collateral amounted to approximately $143 million. Should the credit ratings of CERC Corp. (the credit support provider for CES) fall below certain levels, CES would be required to provide additional collateral on two business days’ notice up to the utilized amount of its previously unsecured credit limit. We estimate that as of September 30, 2008, unsecured credit limits extended to CES by counterparties aggregate $175 million; however, utilized credit capacity is significantly lower. In addition, CERC Corp. and its subsidiaries purchase natural gas under supply agreements that contain an aggregate credit threshold of $100 million based on CERC Corp.’s S&P Senior Unsecured Long-Term Debt rating of BBB. Upgrades and downgrades from this BBB rating will increase and decrease the aggregate credit threshold accordingly.

In connection with the development of SESH’s 270-mile pipeline project, CERC Corp. advanced funds to the joint venture for its 50% share of the cost to construct the pipeline. As of September 30, 2008, subsidiaries of CERC Corp. have advanced approximately $582 million to SESH, of which $266 million was in the form of an equity contribution and $316 million was in the form of a loan.

Cross Defaults. Under our revolving credit facility, a payment default on, or a non-payment default that permits acceleration of, any indebtedness exceeding $50 million by us or any of our significant subsidiaries will cause a default. In addition, four outstanding series of our senior notes, aggregating $950 million in principal amount as of September 30, 2008, provide that a payment default by us, CERC Corp. or CenterPoint Houston in respect of, or an acceleration of, borrowed money and certain other specified types of obligations, in the aggregate principal amount of $50 million, will cause a default. A default by CenterPoint Energy would not trigger a default under our subsidiaries’ debt instruments or bank credit facilities.

Possible acquisitions, divestitures and joint ventures . From time to time, we consider the acquisition or the disposition of assets or businesses or possible joint ventures or other joint ownership arrangements with respect to assets or businesses. Any determination to take any action in this regard will be based on market conditions and opportunities existing at the time, and accordingly, the timing, size or success of any efforts and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt and/or equity issuances. Debt or equity financing may not, however, be available to us at that time due to a variety of events, including, among others, maintenance of our credit ratings, industry conditions, general economic conditions, market conditions and market perceptions.

Pension Plan Costs . Net periodic pension costs will likely increase in 2009 due to decreases in pension plan assets as a result of recent declines in global equity and fixed income markets. Pension expense increases approximately $12 million for every 5% decline in plan assets.

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

cash collateral requirements that could exist in connection with certain contracts, including gas purchases, gas price hedging and gas storage activities of our Natural Gas Distribution and Competitive Natural Gas Sales and Services business segments, particularly given gas price levels and volatility;

Table of Contents

acceleration of payment dates on certain gas supply contracts under certain circumstances, as a result of increased gas prices and concentration of natural gas suppliers;

increased costs related to the acquisition of natural gas;

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

various regulatory actions;

the ability of RRI and its subsidiaries to satisfy their obligations as the principal customers of CenterPoint Houston and in respect of RRI’s indemnity obligations to us and our subsidiaries or in connection with the contractual obligations to a third party pursuant to which CERC is a guarantor;

slower customer payments and increased write-offs of receivables due to higher gas prices or changing economic conditions;

the outcome of litigation brought by and against us;

contributions to benefit plans;

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

various other risks identified in “Risk Factors” in Item 1A of our 2007 Form 10-K and in “Risk Factors” in Item 1A of Part II of this Quarterly Report on Form 10-Q.

Certain Contractual Limits on Our Ability to Issue Securities and Borrow Money. CenterPoint Houston’s credit facility limits CenterPoint Houston’s debt (excluding transition bonds) as a percentage of its total capitalization to 65%. CERC Corp.’s bank facility and its receivables facility limit CERC’s debt as a percentage of its total capitalization to 65%. Our $1.2 billion credit facility contains a debt, excluding transition bonds, to EBITDA covenant. Additionally, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

NEW ACCOUNTING PRONOUNCEMENTS

See Note 2 to our Interim Condensed Financial Statements for a discussion of new accounting pronouncements that affect us.

Item 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Commodity Price Risk From Non-Trading Activities

We use derivative instruments as economic hedges to offset the commodity price exposure inherent in our businesses. The stand-alone commodity risk created by these instruments, without regard to the offsetting effect of the underlying exposure these instruments are intended to hedge, is described below. We measure the commodity risk of our non-trading energy derivatives using a sensitivity analysis. The sensitivity analysis performed on our non-trading energy derivatives measures the potential loss in fair value based on a hypothetical 10% movement in energy prices. At September 30, 2008, the recorded fair value of our non-trading energy derivatives was a net liability of $79 million (before collateral). The net liability consisted of a net liability of $121 million associated with price stabilization activities of our Natural Gas Distribution business segment and a net asset of $42 million related to our Competitive Natural Gas Sales and Services business segment. Net assets or liabilities related to the price stabilization activities correspond directly with net over/under recovered gas cost liabilities or assets on the balance sheet. A decrease of 10% in the market prices of energy commodities from their September 30, 2008 levels would have decreased the fair value of our non-trading energy derivatives net liability by $75 million. However, the

Table of Contents

consolidated income statement impact of this same 10% decrease in market prices would be a reduction in income of $5 million.

The above analysis of the non-trading energy derivatives utilized for commodity price risk management purposes does not include the favorable impact that the same hypothetical price movement would have on our physical purchases and sales of natural gas to which the hedges relate. Furthermore, the non-trading energy derivative portfolio is managed to complement the physical transaction portfolio, reducing overall risks within limits. Therefore, the adverse impact to the fair value of the portfolio of non-trading energy derivatives held for hedging purposes associated with the hypothetical changes in commodity prices referenced above is expected to be substantially offset by a favorable impact on the underlying hedged physical transactions.

Interest Rate Risk

As of September 30, 2008, we had outstanding long-term debt, bank loans, lease obligations and obligations under our ZENS that subject us to the risk of loss associated with movements in market interest rates.

Our floating-rate obligations aggregated $1.2 billion at September 30, 2008. If the floating interest rates were to increase by 10% from September 30, 2008 rates, our combined interest expense would increase by approximately $4 million annually.

At September 30, 2008, we had outstanding fixed-rate debt (excluding indexed debt securities) aggregating $8.9 billion in principal amount and having a fair value of $8.7 billion. 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 9 to our consolidated financial statements). However, the fair value of these instruments would increase by approximately $331 million if interest rates were to decline by 10% from their levels at September 30, 2008. In general, such an increase in fair value would impact earnings and cash flows only if we were to reacquire all or a portion of these instruments in the open market prior to their maturity.

Upon adoption of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” effective January 1, 2001, the ZENS obligation was bifurcated into a debt component and a derivative component. The debt component of $117 million at September 30, 2008 was a fixed-rate obligation and, therefore, did not expose us to the risk of loss in earnings due to changes in market interest rates. However, the fair value of the debt component would increase by approximately $19 million if interest rates were to decline by 10% from levels at September 30, 2008. Changes in the fair value of the derivative component, a $195 million recorded liability at September 30, 2008, are recorded in our Statements of Consolidated Income and, therefore, we are exposed to changes in the fair value of the derivative component as a result of changes in the underlying risk-free interest rate. If the risk-free interest rate were to increase by 10% from September 30, 2008 levels, the fair value of the derivative component liability would increase by approximately $4 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

Equity Market Value Risk

We are exposed to equity market value risk through our ownership of 21.6 million shares of TW Common, which we hold to facilitate our ability to meet our obligations under the ZENS. A decrease of 10% from the September 30, 2008 market value of TW Common would result in a net loss of approximately $5 million, which would be recorded as an unrealized loss in our Statements of Consolidated Income.

Item 4. 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 September 30, 2008 to provide assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms and such

Table of Contents

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 September 30, 2008 that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

Item 1. LEGAL PROCEEDINGS

For a description of certain legal and regulatory proceedings affecting CenterPoint Energy, please read Notes 4 and 10 to our Interim Condensed Financial Statements, each of which is incorporated herein by reference. See also “Business — Regulation” and “— Environmental Matters” in Item 1 and “Legal Proceedings” in Item 3 of our 2007 Form 10-K.

Item 1A. RISK FACTORS

Other than with respect to the risk factors set forth below, there have been no material changes from the risk factors disclosed in our 2007 Form 10-K.

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

CenterPoint Houston’s electric delivery system suffered substantial damage as a result of Hurricane Ike, which struck the upper Texas coast on September 13, 2008. The total cost for the restoration of the system is currently estimated to be in the range of $650 million to $750 million, but that estimate is preliminary and costs ultimately incurred could vary from that estimate.

CenterPoint Houston believes it is entitled to recover prudently incurred storm costs in accordance with applicable regulatory and legal principles. CenterPoint Houston plans to seek passage of legislation to allow securitization of the storm restoration costs through the issuance of dedicated bonds, which would be repaid over time through a charge imposed on customers. Alternatively, CenterPoint Houston has the right to seek recovery of these costs under traditional rate making principles. CenterPoint Houston’s failure to recover costs incurred as a result of Hurricane Ike could adversely affect its liquidity and financial condition.

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

CenterPoint Houston’s receivables from the distribution of electricity are collected from retail electric providers that supply the electricity CenterPoint Houston distributes to their customers. As of September 30, 2008, CenterPoint Houston did business with 80 retail electric providers. Adverse economic conditions, structural problems in the market served by the Electric Reliability Council of Texas, Inc. or financial difficulties of one or more retail electric providers could impair the ability of these retail providers to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these retail electric providers to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. Applicable Texas Utility Commission regulations limit the extent to which CenterPoint Houston can demand credit protection from retail electric providers for payments not made prior to the shift to the provider of last resort. RRI, through its subsidiaries, is CenterPoint Houston’s largest customer. Approximately 48% of CenterPoint Houston’s $182 million in billed receivables from retail electric providers at September 30, 2008 was owed by subsidiaries of RRI. Any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations. RRI’s unsecured debt ratings are currently below investment grade. If RRI were unable to meet its obligations, it could consider, among various options, restructuring under the bankruptcy laws, in which event RRI’s subsidiaries might seek to avoid honoring their obligations and claims might be made by creditors involving payments CenterPoint Houston has received from RRI’s subsidiaries.

Table of Contents

Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.

We currently have general liability and property insurance in place to cover certain of our facilities in amounts that we consider appropriate. Such policies are subject to certain limits and deductibles and do not include business interruption coverage. Insurance coverage may not be available in the future at current costs or on commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. CenterPoint Houston may not be able to recover the losses and damages to its transmission and distribution properties as a result of Hurricane Ike, or any such losses or damages sustained in the future, through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

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

The continued credit crisis and related turmoil in the global financial system may have an impact on our business and our financial condition. Our ability to access the capital markets may be severely restricted at a time when we would like, or need, to access those markets, which could have an impact on our flexibility to react to changing economic and business conditions. In addition, the cost of debt financing and the proceeds of equity financing may be materially adversely impacted by these market conditions. With respect to our existing debt arrangements, Lehman Brothers Bank, FSB, which had an approximately four percent participation in our credit facility and each of the credit facilities of our subsidiaries, stopped funding its commitments following the bankruptcy filing of its parent in September 2008, effectively causing a minor reduction to the total available capacity under the three facilities. The credit crisis could have an impact on our remaining lenders or our customers, causing them to fail to meet their obligations to us. Additionally, the crisis could have a broader impact on business in general in ways that could lead to reduced electricity and gas usage, which could have a negative impact on our revenues.

Item 5 . OTHER INFORMATION

The ratio of earnings to fixed charges for the nine months ended September 30, 2007 and 2008 was 1.87 and 2.21, respectively. We do not believe that the ratios for these nine-month periods are necessarily indicators of the ratios for the twelve-month periods due to the seasonal nature of our business. The ratios were calculated pursuant to applicable rules of the Securities and Exchange Commission.

Table of Contents

Item 6. EXHIBITS

The following exhibits are filed herewith:

Exhibits not incorporated by reference to a prior filing are designated by a cross (+); all exhibits not so designated are incorporated by reference to a prior filing of CenterPoint Energy, Inc.

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	—	$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
+4.4	—	First Amendment to Amended and Restated Credit Agreement dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein.
4.5	—	$300,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.6	—	$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+10.1	—	Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan effective as of January 1, 2009
+10.2	—	Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+10.3	—	First Amendment dated October 17, 2008 to Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+12	—	Computation of Ratios of Earnings to Fixed Charges

Table of Contents

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+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
+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”

Table of Contents

SIGNATURES

Pursuant to the requirements 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.

	CENTERPOINT ENERGY, INC.


	By: /s/ Walter L. Fitzgerald
	Walter L. Fitzgerald
	Senior Vice President and Chief Accounting Officer

Date: November 5, 2008

Table of Contents

Index to Exhibits

The following exhibits are filed herewith:

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

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
3.1.1	—	Restated Articles of Incorporation of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.1
3.2	—	Amended and Restated Bylaws of CenterPoint Energy	CenterPoint Energy’s Form 8-K dated July 24, 2008	1-31447	3.2
4.1	—	Form of CenterPoint Energy Stock Certificate	CenterPoint Energy’s Registration Statement on Form S-4	3-69502	4.1
4.2	—	Rights Agreement dated January 1, 2002, between CenterPoint Energy and JPMorgan Chase Bank, as Rights Agent	CenterPoint Energy’s Form 10-K for the year ended December 31, 2001	1-31447	4.2
4.3	—	$1,200,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Energy, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.3
+4.4	—	First Amendment to Amended and Restated Credit Agreement dated as of August 20, 2008, among CenterPoint Energy, as Borrower, and the banks named therein.
4.5	—	$300,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CenterPoint Houston, as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.4
4.6	—	$950,000,000 Second Amended and Restated Credit Agreement dated as of June 29, 2007, among CERC Corp., as Borrower, and the banks named therein	CenterPoint Energy’s Form 10-Q for the quarter ended June 30, 2007	1-31447	4.5
+10.1	—	Amended and Restated CenterPoint Energy 2005 Deferred Compensation Plan effective as of January 1, 2009
+10.2	—	Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+10.3	—	First Amendment dated October 17, 2008 to Amended and Restated Houston Light & Power Company Executive Incentive Compensation Plan effective as of January 1, 1985
+12	—	Computation of Ratios of Earnings to Fixed Charges

Table of Contents

Exhibit Number		Description	Report or Registration Statement	SEC File or Registration Number	Exhibit Reference
+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
+99.1	—	Items incorporated by reference from the CenterPoint Energy Form 10-K. Item 1A “Risk Factors”

Exhibit 4.4

FIRST AMENDMENT TO AMENDED AND RESTATED CREDIT AGREEMENT

FIRST AMENDMENT, dated as of August 20, 2008 (this “ Amendment ”), to the Amended and Restated Credit Agreement, dated as of June 29, 2007 (as heretofore amended, supplemented or otherwise modified, the “ Credit Agreement ”), among CENTERPOINT ENERGY, INC., a Texas corporation (“ Borrower ”), the banks and other financial institutions from time to time parties thereto (the “ Banks ”), CITIBANK, N.A., as syndication agent (in such capacity, the “ Syndication Agent ”), BARCLAYS BANK PLC, BANK OF AMERICA, N.A. and CREDIT SUISSE, CAYMAN ISLANDS BRANCH, as co-documentation agents, (in such capacities, the “ Co-Documentation Agent ”), and JPMORGAN CHASE BANK, N.A., as administrative agent (in such capacity, the “ Administrative Agent ”).

W I T N E S S E T H :

WHEREAS, the Borrower, the Banks, the Syndication Agent, the Co-Documentation Agents and the Administrative Agent are parties to the Credit Agreement;

WHEREAS, the Borrower has requested that the Banks agree to amend a certain provision contained in the Credit Agreement, and the Banks and the Administrative Agent are agreeable to such request upon the terms and subject to the conditions set forth herein;

NOW, THEREFORE, in consideration of the premises herein contained and for other good and valuable consideration, the receipt of which is hereby acknowledged, the parties hereto agree as follows:

1. Defined Terms . Unless otherwise defined herein, capitalized terms used herein which are defined in the Credit Agreement are used herein as therein defined.

2. Amendments to Section 7.2(a) of the Credit Agreement (Financial Ratios) . Section 7.2(a) of the Credit Agreement is hereby amended by deleting the chart set forth there in its entirety and inserting in lieu thereof the following new chart:

Period	Ratio
Closing Date through December 31, 2007	5.25:1.00
January 1, 2008 through the Maturity Date	5.00:1.00

3. Conditions to Effectiveness . This Amendment shall become effective as of the date set forth above upon satisfaction of the following conditions precedent:

(a ) the Administrative Agent shall have received counterparts of this Amendment executed by Borrower and the Majority Banks in accordance with Section 10.1 of the Credit Agreement;

(b) the Administrative Agent shall have received an amendment fee in an amount equal to 0.05% of the Commitment of each Bank which delivers its signature page to this Amendment on or before 5:00 P.M., New York time, on Wednesday, August 20, 2008; and

(c) all corporate and other proceedings, and all documents, instruments and other legal matters in connection with this Amendment shall be in form and substance reasonably satisfactory to the Administrative Agent.

4. Reference to and Effect on the Loan Documents; Limited Effect . On and after the date hereof and the satisfaction of the conditions contained in Section 4 of this Amendment, each reference in the Credit Agreement to “this Agreement”, “hereunder”, “hereof” or words of like import referring to the Credit Agreement, and each reference in the other Loan Documents to “the Credit Agreement”, “thereunder”, “thereof” or words of like import referring to the Credit Agreement, shall mean and be a reference to the Credit Agreement as amended hereby. The execution, delivery and effectiveness of this Amendment shall not, except as expressly provided herein, operate as a waiver of any right, power or remedy of any Bank or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provisions of any of the Loan Documents. Except as expressly amended herein, all of the provisions and covenants of the Credit Agreement and the other Loan Documents are and shall continue to remain in full force and effect in accordance with the terms thereof and are hereby in all respects ratified and confirmed.

5. Representations and Warranties . The Borrower, as of the date hereof and after giving effect to this Amendment, hereby confirms, reaffirms and restates the representations and warranties made by it in Article VI of the Credit Agreement and otherwise in the Loan Documents to which it is a party (except for those representations or warranties or parts thereof that, by their terms, expressly relate solely to a specific date, in which case such representations and warranties shall be true and correct in all material respects as of such specific date); provided that each reference to the Credit Agreement therein shall be deemed to be a reference to the Credit Agreement after giving effect to this Amendment.

6. Costs and Expenses . The Borrower agrees to reimburse the Administrative Agent for its reasonable out-of-pocket expenses in connection with this Amendment, including the reasonable fees, charges and disbursements of counsel for the Administrative Agent.

7. Counterparts . This Amendment may be executed by one or more of the parties hereto in any number of separate counterparts (which may include counterparts delivered by facsimile transmission) and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Any executed counterpart delivered by facsimile transmission shall be effective as an original for all purposes hereof. The execution and delivery of this Amendment by any Bank shall be binding upon each of its successors and assigns (including Transferees of its Commitments and Loans in whole or in part prior to effectiveness hereof) and binding in respect of all of its Commitments and Loans, including any acquired subsequent to its execution and delivery hereof and prior to the effectiveness hereof.

8. GOVERNING LAW . THIS AMENDMENT SHALL BE GOVERNED BY, AND CONSTRUED AND INTERPRETED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

HOU03:1176555.1

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be executed and delivered by their duly authorized officers as of the date first written above.

	CENTERPOINT ENERGY, INC.
By:	/s/ Marc Kilbride
	Name: Marc Kilbride
	Title: Vice President & Treasurer
	JPMORGAN CHASE BANK, N.A., as Administrative Agent and as a Bank

By:	/s/ Rob Traband
	Name: Rob Traband
	Title: Executive Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	Bank of America, N.A., as a Bank

By:	/s/ Richard L. Stein
	Name: Richard L. Stein
	Title: Senior Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	BARCLAYS BANK PLC, as a Bank

By:	/s/ Alicia Borys
	Name: Alicia Borys
	Title: Manager

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	DEUTSCHE BANK AG NEW YORK BRANCH, as a Bank

By:	/s/ Ming K. Chu
	Name: Ming K. Chu
	Title: Vice President

By:	/s/ Heidi Sandquist
	Name: Heidi Sandquist
	Title: Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	WACHOVIA BANK, N.A as a Bank

By:	/s/ Henry R. Biedrzycki
	Name: Henry R. Biedrzycki
	Title: Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	ABN AMRO Bank, N.V., as a Bank

By:	/s/ James L. Moyes
	Name: James L. Moyes
	Title: Managing Director

By:	/s/ R. Scott Donaldson
	Name: R. Scott Donaldson
	Title: Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	The Bank of Nova Scotia , as a Bank

By:	/s/ Gordon Eadon
	Name: Gordon Eadon
	Title: Managing Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	CREDIT SUISSE, CAYMAN ISLANDS BRANCH, as a Bank

By:	/s/ James Moran
	Name: James Moran
	Title: Managing Director

By:	/s/ Nupur Kumar
	Name: Nupur Kumar
	Title: Associate

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	The Royal Bank of Scotland, plc ,as a Bank

By:	/s/ Belinda Tucker
	Name: Belinda Tucker
	Title: Senior Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	UBS Loan Finance LLC, as a Bank

By:	/s/ Irja R. Otsa
	Name: Irja R. Otsa
	Title: Associate Director

By:	/s/ Richard L. Tavrow
	Name: Richard L. Tavrow
	Title: Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	CITIBANK, N.A , as a Bank

By:	/s/ Nietzsche Rodricks
	Name: Nietzsche Rodricks
	Title: Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	LEHMAN BROTHERS BANK, FSB , as a Bank

By:	/s/ Janine M. Shugan
	Name: Janine M. Shugan
	Title: Authorized Signatory

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	Bank of Tokyo-Mitsubishi UFJ, Ltd. , as a Bank

By:	/s/ Kevin Cullen
	Name: Kevin Cullen
	Title: Authorized Signatory

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	HSBC BANK USA, NATIONAL ASSOCIATION , as a Bank

By:	/s/ Jennifer Diedzic
	Name: Jennifer Diedzic
	Title: Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	Royal Bank of Canada , as a Bank

By:	/s/ Linda M. Stephens
	Name: Linda M. Stephens
	Title: Authorized Signatory

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	Wells Fargo Bank, National Association , as a Bank

By:	/s/ Scott D. Bjelde
	Name: Scott D. Bjelde
	Title: Senior Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	First Commercial Bank, New York Agency , as a Bank

By:	/s/ Yu-Mei Hsiao
	Name: Yu-Mei Hsiao
	Title: Assistant General Manager

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	Comercia Bank , as a Bank

By:	/s/ Joey Powell
	Name: Joey Powell
	Title: Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	THE NORTHERN TRUST COMPANY , as a Bank

By:	/s/ Keith Burson
	Name: Keith Burson
	Title: Vice President

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	SUNTRUST BANK , as a Bank

By:	/s/ Andrew Johnson
	Name: Andrew Johnson
	Title: Director

HOU03:1176555.1

	Signature Page
	First Amendment to CenterPoint Credit Agreement

	MORGAN STANLEY BANK , as a Bank

By:	/s/ Daniel Twenge
	Name: Daniel Twenge
	Title: Authorized Signatory

HOU03:1176555.1

Exhibit 10.1

CENTERPOINT ENERGY

2005 DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2009)

CENTERPOINT ENERGY

2005 DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2009)

TABLE OF CONTENTS

		Page
ARTICLE I PURPOSES OF PLAN; DEFINITIONS; DURATION		2
1.1	Purposes	2
1.2	Definitions	2
1.3	Term	4

ARTICLE II ADMINISTRATION		4

ARTICLE III PARTICIPATION		5

3.1	Eligibility of Employees and Directors	5
3.2	Designation of Participants	5
3.3	Election to Participate	5
3.4	Salary Deferral	5
3.5	Bonus Deferral	5
3.6	Director Fees Deferral	6

ARTICLE IV BENEFICIARY DESIGNATIONS; WITHHOLDING		6

4.1	Beneficiary Designations	6
4.2	Withholding of Taxes	7

ARTICLE V BENEFITS		7

5.1	Benefit Payments	7
5.2	Death	8
5.3	Separation from Service During Participation Year	8
5.4	Delay of Payments to Certain Participants	9
5.5	Crediting of Interest	9

ARTICLE VI RIGHTS OF PARTICIPANTS		10

6.1	Limitation of Rights	10
6.2	Non-Alienation of Benefits	10
6.3	Prerequisites to Benefits	11
6.4	Nature of Employer’s Obligation	11
6.5	Claims and Review Procedures	12

-i-


ARTICLE VII MISCELLANEOUS .		13

7.1	Amendment or Termination of the Plan	13
7.2	Reliance Upon Information	13
7.3	Effective Date	13
7.4	Code Section 409A	13
7.5	Governing Law	13
7.6	Severability	13
7.7	Notice	14

-ii-

CENTERPOINT ENERGY

2005 DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2009)

RECITALS:

WHEREAS , CenterPoint Energy, Inc. (the “Company”), established and maintains the CenterPoint Energy 2005 Deferred Compensation Plan, effective as of January 1, 2008 (the “Plan”), in response to the enactment of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), to provide deferred compensation benefits earned or vested after December 31, 2004, with all earnings attributable thereto, for the benefit of its eligible employees; and

WHEREAS , the Company has operated the Plan at all times in accordance with the “reasonable, good faith” compliance standard prescribed by Code Section 409A, which is applicable until the effective date of the final regulations issued under Code Section 409A; and

WHEREAS , the Company desires to amend and restate the Plan to comply with the applicable requirements under the final regulations issued under Code Section 409A, which regulations are effective as of January 1, 2009;

NOW, THEREFORE , effective as of January 1, 2009, the Company hereby amends, restates and continues the Plan as herein set forth:

ARTICLE I

PURPOSES OF PLAN; DEFINITIONS; DURATION

1.1 Purposes . This CenterPoint Energy 2005 Deferred Compensation Plan, as amended and restated effective January 1, 2009, for selected management and highly compensated employees is intended to aid certain of its employees in making more adequate provision for their retirement and is intended to be a “top-hat” plan under sections 201(2), 301(a)(3) and 401(a)(1) of the Employee Retirement Income Security Act of 1974 (“ERISA”).

1.2 Definitions . Each term below shall have the meaning assigned thereto for all purposes of this Plan unless the context requires a different construction.

“Beneficiary” means a person or persons, a trustee or trustees of a trust, or a partnership, corporation, limited liability partnership, limited liability company, or other entity designated by the Participant, as provided in Section 4.1, to receive any amounts distributed under the Plan after a Participant’s death.

“Board” means the Board of Directors of the Company.

“Bonus” means a formula or discretionary bonus or incentive compensation paid under a short-term or annual incentive plan maintained by the Company or a Subsidiary.

“Code” means the Internal Revenue Code of 1986, as amended.

“Company” means CenterPoint Energy, Inc., a Texas corporation, or a successor to CenterPoint Energy, Inc., in the ownership of substantially all of its assets.

“Commencement Date” means the first day of the Participation Year, with respect to which a Compensation deferral occurs.

“Committee” means the Benefits Committee or such other committee, which shall consist of five or fewer persons, as shall be appointed by the Board of Directors of the Company to administer the Plan pursuant to Article II hereof.

“Compensation” means the Salary and Bonus which an Employer pays its Employees, and the Director Fees paid to a Director.

“Director” means a non-Employee member of the Board.

“Director Fees” means the meeting attendance fees, retainer fees and committee chairman fees paid to a Director.

“Disability” means a physical or mental condition that qualifies as a total and permanent disability under the CenterPoint Energy, Inc. Long Term Disability Plan, as amended from time to time (or any successor plan thereto).

-2-

“Early Distribution” means the benefit payment option available to a Participant under Section 5.1(a) hereof.

“Employee” means any person, including an officer of any Employer (whether or not he or she is also a director thereof), who, at the time such person is designated a Participant hereunder, is employed by an Employer on a full-time basis, who is compensated for such employment by a regular Salary, and who, in the opinion of the Committee, is one of the officers or other key employees of the Employer in a position to contribute materially to the continued growth and development and to the future financial success of the Employer. Any Participant who is an Employee of a Subsidiary shall not be deemed to have terminated employment with an Employer for purposes of this Plan until the date upon which the Participant has a Separation from Service.

“Employer” means (i) the Company, (ii) each Subsidiary which has adopted the Plan with the consent of the Committee, and (iii) each other employing organization in which the Company has a direct or indirect ownership interest and which has been approved by the Committee as an Employer under the Plan, subject to the terms and conditions established by the Committee.

“Interest Crediting Rate” means, for a given Plan Year, a rate of interest equivalent to the average Moody’s Rate for such year plus two percentage points (2%).

“Moody’s Rate” means a rate of interest equal to the composite yield on Moody’s Long-Term Corporate Bond Yield Averages for the calendar month as determined from Moody’s monthly yield averages published by Moody’s Investor’s Service, Inc. (or any successor thereto), or, if such yield is no longer published, a substantially similar average selected by the Committee.

“Normal Distribution” means the benefit payment options available to a Participant under Section 5.1(b) hereof.

“Participant” means (i) a Director or an Employee who has been designated by the Committee to participate in the Plan pursuant to Section 3.2 hereof and (ii) who has elected to participate in the Plan pursuant to Section 3.3.

“Participation Year” means a Plan Year commencing on or after January 1, 2009 during which (i) with respect to Compensation in the form of a Bonus, the Bonus would have been paid to the Participant if not deferred; (ii) with respect to Compensation in the form of Salary, a Participant performs services for the Employer for a Salary; and (iii) with respect to Compensation in the form of Director Fees, a Participant performs services as a member of the Board for such fees.

“Plan” means the CenterPoint Energy 2005 Deferred Compensation Plan, as amended and restated effective January 1, 2009, as set forth herein, as the same may hereafter be amended from time to time.

“Plan Year” means a calendar year (January 1st through December 31st).

-3-

“Prior Plan” means the CenterPoint Energy 2005 Deferred Compensation Plan, effective as of January 1, 2008, as in effect on December 31, 2008.

“Salary” means a base salary or wages paid to a Participant by an Employer. The Salary of a Participant as reflected on the books and records of the Employer shall be conclusive.

“Separation from Service” means separation from service (including by reason of Disability) with the Company, all Employers and all Subsidiaries within the meaning of Treasury Regulation § 1.409A-1(h) (or any successor regulation) or, in the case of a Director, he or she ceases to be a member of the Board.

“Subsidiary” means a subsidiary corporation with respect to the Company as defined in Code Section 424(f).

Words used in this Plan in the singular shall include the plural and in the plural the singular, and the gender of words used shall be construed to include whichever may be appropriate under any particular circumstances of the masculine, feminine or neuter genders.

1.3 Term . The effective date of the Plan, as amended and restated, is January 1, 2009. The Plan shall continue until terminated by the Board. The Committee, in its sole discretion, may or may not authorize deferral of Compensation during the term of the Plan.

ARTICLE II

ADMINISTRATION

The Plan shall be administered by the Committee, which shall represent the Company and other Employers in all matters concerning the administration of the Plan. Members of the Committee may be Participants under the Plan, but no member may vote on any matter relating to his or her benefits under the Plan. The Committee shall have primary responsibility for the administration and operation of the Plan and shall have all powers necessary to carry out the provisions of the Plan, including the power to determine which Employees shall be Participants under the Plan. The determination of the Committee as to the construction, interpretation, or application of any terms and provisions of the Plan, including whether and when there has been a Separation from Service, shall be final, binding, and conclusive upon all persons.

-4-

ARTICLE III

PARTICIPATION

3.1 Eligibility of Employees and Directors . An Employee must be a manager or a highly compensated (within the meaning of Code Section 414(q)) salaried employee of an Employer to be eligible to participate in the Plan. All Directors shall be eligible to participate in the Plan. The Committee may from time to time establish additional eligibility requirements for participation in the Plan.

3.2 Designation of Participants . Prior to the commencement of any Participation Year, the Committee shall designate and notify in writing the Employees and/or Directors who are eligible to defer Compensation under this Plan. A designation of an Employee or Director to participate with respect to Compensation for a particular Participation Year shall not automatically entitle such Participant to participate with respect to any other Participation Year.

3.3 Election to Participate . After an Employee or Director has been notified by the Committee, in the form and manner prescribed by the Committee, that he or she is eligible to participate in the Plan, he or she must notify the Committee, in the form and manner prescribed by the Committee, that he or she chooses to participate in the Plan. Such election to participate in the Plan shall be effective upon its receipt by the Committee (or its delegate) within the time periods and manner prescribed by the Committee or the Plan. A Participant’s election (i) shall specify the type or types and the amount or amounts of Compensation that he or she wishes to defer and the manner of such deferral pursuant to Sections 3.4 through 3.6 hereof; (ii) shall specify, if the Participant so elects, that he or she wishes to receive an Early Distribution of benefits with respect to some or all deferrals for such Participation Year under Section 5.1(a) hereof; and (iii) shall specify the manner of Normal Distribution the Participant chooses with respect to such deferrals under Section 5.1(b) hereof.

3.4 Salary Deferral . A Participant’s election to defer the payment of Salary must be made prior to the first day of the Plan Year in which the Salary is earned by the Participant. Such election will be irrevocable as of December 31 of the calendar year preceding the calendar year in which the Salary is earned.

A Participant may elect to defer up to 90% (or such lesser percentage designated by the Committee, in its sole discretion) of his or her annual Salary, stated as a percentage of his or her Salary, with respect to a particular Participation Year. The amount of Compensation elected to be deferred under this Section 3.4 shall be withheld from the Participant’s Salary during a Plan Year in equal amounts.

3.5 Bonus Deferral . A Participant’s election to defer the payment of a Bonus that qualifies as “performance-based compensation” under Code Section 409A(4)(B) must be made no later than six months prior to the end of the performance period. Such election will be irrevocable as of the date that is six months prior to the end of the performance period in which the Bonus is earned.

-5-

A Participant’s election to defer the payment of a Bonus that does not qualify as “performance-based compensation” under Code Section 409A(4)(B) must be made prior to the first day of the Plan Year in which the services are performed for which the Bonus is earned. Such election will be irrevocable as of December 31 of the calendar year preceding the calendar year in which the services are performed for which the Bonus is earned.

A Participant may elect to defer up to 90% of his or her annual cash Bonus award, stated as a percentage of his or her Bonus or a flat-dollar amount, with respect to a particular Participation Year. The amount of Compensation elected to be deferred under this Section 3.5 shall be withheld from the Participant’s Bonus otherwise payable during the Plan Year. If the Participant’s election is a flat-dollar amount and the amount of the Bonus awarded to the Participant with respect to a Participation Year is less than the amount of the Bonus which the Participant had elected to defer for such Participation Year, then such election shall be deemed to be an election to defer the maximum deferral percentage permitted under this Section 3.5 of the Bonus awarded.

3.6 Director Fees Deferral . A Participant’s election to defer the payment of Director Fees must be made prior to the first day of the Plan Year in which the Director Fees are earned by the Participant. Such election will be irrevocable as of December 31 of the Plan Year preceding the Participation Year with respect to which the Director Fees are earned.

A Participant may elect to defer up to 100% (or such lesser percentage designated by the Committee in its sole discretion) of each type of his or her Director Fees, stated as a percentage of his or her Director Fees or a flat-dollar amount, with respect to a particular Participation Year. The amount of Compensation elected to be deferred under this Section 3.6 shall not be paid but shall be withheld from the Participant’s Director Fees otherwise earned and payable during the Plan Year. If the Participant’s election is a flat-dollar amount and the amount of the Director Fees awarded to the Participant with respect to a Participation Year is less than the amount of the Director Fees which the Participant had elected to defer for such Participation Year, then such election shall be deemed to be an election to defer the maximum deferral percentage permitted under this Section 3.6 of the Director Fees awarded.

ARTICLE IV

BENEFICIARY DESIGNATIONS; WITHHOLDING

4.1 Beneficiary Designations . Each person becoming a Participant shall file with the Committee (or its delegate), in the form and manner prescribed by the Committee, a designation of one or more Beneficiaries to whom distributions otherwise due the Participant shall be made in the event of his or her death while in the employ of the Company or serving on the Board or after Separation from Service but prior to the complete distribution of the benefits payable with respect to the Participant. Such designation shall be effective when received by the Committee. The Participant may from time to time revoke or change any such designation of a Beneficiary by notifying the Committee in the form and manner prescribed by the Committee. If there is no valid designation of the Beneficiary on file with the Committee at the time of the Participant’s death, or if all of the Beneficiaries designated therein shall have predeceased the Participant or otherwise ceased to exist, the Beneficiary shall be, and any payment hereunder shall be made

-6-

to, the Participant’s spouse, if he or she survives the Participant, or otherwise to the executor or legal representative of the Participant’s estate. If the Beneficiary, whether under a valid beneficiary designation or under the preceding sentence, shall survive the Participant but die before receiving all payments hereunder, the balance of the benefits which would have been paid to the Beneficiary had he or she lived shall, unless the Participant’s designation provided otherwise, be distributed to the executor or legal representative of the Beneficiary’s estate.

4.2 Withholding of Taxes . The Company may withhold from a payment any federal, state, or local employment and income taxes required by law to be withheld with respect to such payment and such sum as the Company may reasonably estimate as necessary to cover any taxes for which the Company may be liable and which may be assessed with regard to such payment.

ARTICLE V

BENEFITS

5.1 Benefit Payments . The benefit payments with respect to deferrals of Compensation for a specific Participation Year will be determined as set forth below:

(a) Early Distribution . At the time a Participant elects to defer Compensation for a Participation Year pursuant to Article III hereof, if the Participant has not attained, or will not attain, age 65 during the Participation Year, he or she may elect to receive an in-service Early Distribution of benefits attributable to such Compensation as provided in this Section 5.1(a) (a Participant who has attained, or will attain, age 65 during the Participation Year is not permitted to elect to receive an Early Distribution). The Early Distribution, as elected by the Participant, will represent either (i) 50% or (ii) 100% of the Compensation deferred for that Participation Year. The Early Distribution shall be paid to the Participant during the Plan Year elected by the Participant, which is at least four years after the Participation Year in which the Compensation was deferred or, if earlier (and notwithstanding the Participant’s election to the contrary), the year the Participant attains age 65. A Participant may make only one Early Distribution election under this Plan for each Participation Year for each type of Compensation deferred under Sections 3.4, 3.5 or 3.6 hereof. The foregoing notwithstanding, if a Participant’s Separation from Service or death occurs prior to the payment of an Early Distribution, such Early Distribution benefits shall be paid in accordance with Sections 5.1(b), 5.1(c) or 5.2, as applicable, in lieu of an election under this Section 5.1(a).

(b) Normal Distribution . A Participant who has a Separation from Service on or after the date such Participant attains age 55 may be entitled to a Normal Distribution. At the time a Participant elects to defer Compensation for a Participation Year pursuant to Article III hereof, he or she must elect the form of payment of his or her potential Normal Distribution of benefits attributable to such Compensation, taking into account any Early Distributions paid to him or her under Section 5.1(a) prior to his or her Separation from Service. The Participant may elect to receive a Normal Distribution in:

-7-

(i)	a lump-sum distribution of the amounts of Compensation deferred, minus any Early Distributions; or

(ii)	15 annual installment payments of such Compensation, minus any Early Distributions.

If payable in a lump-sum distribution, the Normal Distribution will be made in the January following the Plan Year during which occurs the date of the Participant’s Separation from Service. If payable in 15 annual installments, payment of a Normal Distribution will commence in the month coincident with or next following the month in which the Participant has a Separation from Service, and the remaining annual installments will be paid in that same month in each of the remaining 14 years. For purposes of Code Section 409A, each installment payment is a separate, independent payment. If a Participant fails to make an election as to the manner in which a Normal Distribution will be paid, such Normal Distribution will be made in the form of a lump-sum distribution in accordance with this Section 5.1(b) as if the Participant had specifically so elected.

(c) Separation from Service Prior to Attaining Age 55 . Notwithstanding any provision of this Article V or a Participant’s distribution election to the contrary, a Participant who has a Separation from Service prior to attaining age 55 shall be paid his or her entire Plan benefit, less any Early Distributions paid to him or her under Section 5.1(a) prior to his or her Separation from Service, if any, in the form of a lump-sum distribution. The lump sum distribution shall be paid within 90 days following the date of the Participant’s Separation from Service.

5.2 Death

(a) Death Prior to Payment or Commencement of Distribution . If a Participant dies prior to receiving or commencing his or her benefit under the Plan, the Employer shall pay Participant’s Beneficiary the sum or sums of Compensation actually deferred, less an amount equal to any Early Distributions paid to the Participant under Section 5.1(a) prior to the Participant’s death. A payment made pursuant to this Section 5.2(a) shall be made within 90 days following the date of the Participant’s death.

(b) Death After Commencement of Installment Distribution . If the Participant dies after commencement of a Normal Distribution in the form of 15 annual installment payments pursuant to Section 5.1(b), but prior to completion of all such payments, then the Company shall continue to make such installment payments as provided in Section 5.1(b) to the Participant’s Beneficiary.

5.3 Separation from Service During Participation Year . If a Participant has a Separation from Service for any reason during the Participation Year for which Compensation that is in the form of Salary or Director Fees is to be deferred, no further deferrals shall be made for that Participation Year on and after the date of such Separation from Service. If a Participant has a Separation from Service for any reason during the Participation Year for which he or she has elected to defer the payment of a Bonus, such election shall become null and void with respect to any Bonus which has not become payable to the Participant as of the date of his or her Separation from Service.

-8-

5.4 Delay of Payments to Certain Participants . Notwithstanding any provision to the contrary in the Plan, if as of the date of the Participant’s Separation from Service (other than by reason of death) the Participant has been identified by the Committee or its delegate as a “Specified Employee” (within the meaning of that term under Code Section 409A(a)(2)(B)), then the payment specified under Article V on account of Separation from Service shall not be paid to the Participant until the later of (a) the date specified in Article V or (b) the earlier of (i) the second day following the expiration of the 6-month period measured from the date of the Participant’s Separation from Service or (ii) the date of the Participant’s death. In the event that a payment is delayed under this Section 5.4, the Company shall pay to the Participant, as of the date it pays the delayed payment, simple interest on the payment amount at the applicable interest rate (as determined under Section 5.5(b)) for such payment, based on the period the payment was delayed beyond the payment date specified in Article V.

5.5 Crediting of Interest . With respect to any distribution pursuant to Section 5.1(b), Section 5.1(c) or Section 5.2 of the Plan, interest shall be credited upon the Participant’s Compensation in accordance with this Section 5.5.

(a) Applicable Compensation Balance for Crediting of Interest . Prior to distribution of a Participant’s account under the Plan, a Participant’s Compensation shall be credited with interest, compounded annually from the Participant’s Commencement Date through the date immediately prior to the first payment to the Participant (or the Participant’s Beneficiary in the case of death), at the applicable interest rate as determined pursuant to subsection (b) hereof. For the purposes of crediting interest all deferrals of Compensation shall earn interest as if such amounts were contributed to the Plan on the first day of the Plan Year in which such Compensation is deferred by the Participant; provided, however , that interest shall not be credited on the amount of the Early Distribution, if any, for the Plan Year in which the Early Distribution is paid to the Participant.

(b) Applicable Interest Rate . The applicable interest rate shall be the Interest Crediting Rate; provided, however , that the applicable interest rate with respect to a distribution pursuant to Section 5.1(c) as a result of the Participant’s Separation from Service for any reason other than due to Disability shall be the Moody’s Rate (in lieu of the higher Interest Crediting Rate).

(c) Interest During Installment Period . For purposes of determining a benefit payable in the form of 15 installment payments under Section 5.1(b), the Interest Crediting Rate shall be the Interest Crediting Rate in effect for the Plan Year immediately prior to which a Participant has a Separation from Service. The Interest Crediting Rate as determined under this Section 5.5(c) will constitute the applicable Interest Crediting Rate with respect to the installment payments for all years after the initial installment payment.

-9-

ARTICLE VI

RIGHTS OF PARTICIPANTS

6.1 Limitation of Rights . Nothing in this Plan shall be construed to:

(a) Give any Employee of an Employer or any Director any right to be designated a Participant in the Plan other than in the sole discretion of the Committee;

(b) Limit in any way the right of the Employer to terminate a Participant’s employment at any time; or

(c) Be evidence of any agreement or understanding, express or implied, that the Company or any other Employer will employ a Participant in any particular position or at any particular rate of remuneration.

6.2 Non-Alienation of Benefits . No right or benefit under this Plan shall be subject to anticipation, alienation, transfer, sale, assignment, pledge, encumbrance or charge, whether voluntary, involuntary, direct or indirect, by operation of law or otherwise, including, without limitation, a change in beneficial interest of any trust and a change in ownership of a corporation or partnership, but not including a change of legal and beneficial title of a right or benefit resulting from the death of any Participant or the spouse of any Participant (any such proscribed transaction hereinafter a “Disposition”) and any attempted Disposition will be null and void. No right or benefit hereunder shall in any manner be liable for or subject to any debts, contracts, liabilities, or torts of any Participant or other person entitled to such benefits. Notwithstanding any provision of the Plan to the contrary, a benefit under the Plan may be paid to an alternate payee as required under a domestic relations order (as defined in Code Section 414(p)(1)(B)), approved by the Committee, consistent with the requirements of Code Section 409A and the Treasury regulations issued thereunder. The foregoing provisions of this Section 6.2 shall also not apply to an irrevocable Disposition of a right or benefit under this Plan to a “Permitted Assignee,” as defined below, by (i) a Participant age 55 or older (an “Eligible Participant”), or (ii) a “Permitted Assignee,” as defined below, who has received an assignment from an Eligible Participant pursuant to this sentence.

(a) Permitted Assignee . The term “Permitted Assignee” shall mean:

(i) The Eligible Participant;

(ii) A spouse of the Eligible Participant;

(iii) Any person who is a lineal ascendant or descendant of the Eligible Participant or the Eligible Participant’s spouse;

(iv) Any brother or sister of the Eligible Participant;

(v) Any spouse of any individual described in subparagraph (iii) or (iv);

-10-

(vi) A trustee of any trust which, at the applicable time, is 100% actuarially held for a Permitted Assignee or Assignees (as defined in Section 6.2(c));

(vii) Any corporation in which, at the applicable time, each class of stock is 100% owned by a Permitted Assignee or Permitted Assignees;

(viii) Any partnership in which, at the applicable time, each class of partnership interest is 100% owned by a Permitted Assignee or Permitted Assignees; or

(ix) Any limited liability company or other form of incorporated or unincorporated business organization in which each class of stock, membership or other equity interest is 100% owned by a Permitted Assignee or Assignees.

(b) Subsequent Assignees . This Section 6.2 shall be fully applicable to all Permitted Assignees, and the provisions of this Section 6.2 shall be fully applicable to any right or benefit transferred by an Eligible Participant to any Permitted Assignee as if such Permitted Assignee were an Eligible Participant; provided, however , that no Permitted Assignee shall be deemed an Eligible Participant for determining the persons who constitute Permitted Assignees under Section 6.2(a). Any Permitted Assignee acquiring a right or benefit under this Plan shall execute and deliver to the Committee an agreement pursuant to which such Permitted Assignee agrees to be bound by all of the terms and provisions of the Plan, provided that the failure to execute and deliver such an agreement shall not be deemed to relieve such Permitted Assignee of the restrictions imposed by the Plan. Any attempted Disposition of a right or benefit under this Plan in breach of this Section 6.2, whether voluntary, involuntary, by operation of law or otherwise shall be null and void.

(c) Actuarially Held . In making the determination whether a trust is 100% actuarially held for Permitted Assignee(s), a trust, at the applicable point in time, is 100% actuarially held for Permitted Assignee or Assignees when 100% of the actuarial value of the beneficial interests of the trust, except as provided in the following sentence, are held for a Permitted Assignee or Permitted Assignees. For purposes of making the determination described above, the possibility that an interest in a trust may be appointed pursuant to a special or general power of appointment shall be ignored; provided, that the actual exercise of any such power of appointment shall not be ignored.

6.3 Prerequisites to Benefits . No Participant, nor any Beneficiary or other person claiming through a Participant, shall have any right or interest in the Plan, or any benefits hereunder, unless and until all the terms, conditions, and provisions of the Plan which affect such Participant or such other person shall have been complied with as specified herein.

-11-

6.4 Nature of Employer’s Obligation . This Plan is intended to be, and shall be construed as, an unfunded plan maintained by each Employer primarily for the purpose of providing deferred compensation for a select group of its management or highly compensated salaried employees. The benefits provided under this Plan shall be a general, unsecured obligation of the Employer payable solely from the general assets of the Employer, and neither the Participant nor the Participant’s Beneficiary or estate shall have any interest in any assets of the Employer by virtue of this Plan. Except as may be provided under a “rabbi trust,” no fund or other assets will ever be set aside or segregated for the benefit of the Participant or the Participant’s Beneficiary under this Plan. The adoption of the Plan and any setting aside of amounts by an Employer with which to discharge its obligations hereunder shall not be deemed to create a trust; legal and equitable title to any funds so set aside shall remain in the Employer and any funds so set aside shall remain subject to the general creditors of the Employer.

6.5 Claims and Review Procedures

(a) Claims Procedure . If any person believes he or she is entitled to any rights or benefits under the Plan, such person may file a claim in writing with the Committee. If any such claim is wholly or partially denied, the Committee will notify such person of its decision in writing. Such notification will contain (i) specific reasons for the denial, (ii) specific reference to pertinent Plan provisions, (iii) a description of any additional material or information necessary for such person to perfect such claim and an explanation of why such material or information is necessary, and (iv) information as to the steps to be taken if the person wishes to submit a request for review, the time limits applicable to such procedures, and a statement of the person’s rights following an adverse benefit determination on review, including a statement of his or her right to file a lawsuit under ERISA if the claim is denied on appeal. Such notification will be given within 90 days after the claim is received by the Committee (or within 180 days, if special circumstances require an extension of time for processing the claim, and if written notice of such extension and circumstances is given to such person within the initial 90-day period).

(b) Claim Review Procedure . Within 60 days after the date on which a person receives a notice of denial, such person or his or her duly authorized representative (“Applicant”) may (i) file a written request with the Committee for a review of his or her denied claim; (ii) review pertinent documents; and (iii) submit issues and comments in writing. The Committee shall render a decision no later than the date of its regularly scheduled meeting next following receipt of a request for review, except that a decision may be rendered no later than the second such meeting if the request is received within 30 days of the first meeting. The Applicant may request a formal hearing before the Committee which the Committee may grant in its discretion. Notwithstanding the foregoing, under special circumstances that require an extension of time for rendering a decision (including, but not limited to, the need to hold a hearing), the decision may be rendered not later than the date of the third regularly scheduled Committee meeting following the receipt of the request for review. If such an extension is required, the Applicant will be advised in writing before the extension begins. If the claim is denied in whole or part, such notice, which shall be in a manner calculated to be understood by the person receiving such notice, shall include (i) the specific reasons for the decision, (ii) the specific references to the pertinent Plan provisions on which the decision is based, (iii) that the Applicant is entitled to receive, upon request and free of charge, reasonable access to, and copies of, all documents, records, and other information relevant to the claim for benefits, and (iv) a statement of the Applicant’s right to file a lawsuit under ERISA. Benefits under this Plan will only be paid if the Committee decides, in its discretion, that an Applicant is entitled to them.

(c) Exhaustion of Administrative Remedies . The decision of the Committee on review of the claim denial shall be binding on all parties when the Participant has exhausted the claims procedure under this Section 6.5. Moreover, no action at law or in equity shall be brought to recover benefits under this Plan prior to the date the Applicant has exhausted the administrative remedies under this Section 6.5.

-12-

ARTICLE VII

MISCELLANEOUS

7.1 Amendment or Termination of the Plan . The Board may amend or terminate this Plan at any time. Any such amendment or termination shall not, however, without the written consent of the affected Participant, reduce the interest rate applicable to, or otherwise adversely affect the rights of a Participant for Compensation with respect to which a Participant made an irrevocable deferral election before the later of the date that such amendment is executed or effective.

7.2 Reliance Upon Information . The Committee shall not be liable for any decision or action taken in good faith in connection with the administration of this Plan. Without limiting the generality of the foregoing, any such decision or action taken by the Committee in reliance upon any information supplied to it by an officer of the Company, the Company’s legal counsel, or the Company’s independent accountants in connection with the administration of this Plan shall be deemed to have been taken in good faith.

7.3 Effective Date . The Plan, as amended and restated, shall become effective as of January 1, 2009, for benefits accrued under the Plan (including under the Prior Plan) on and after January 1, 2005 for Participants who are Employees as of January 1, 2009.

7.4 Code Section 409A . It is intended that the provisions of this Plan to comply with and satisfy the requirements of Code Section 409A. The Plan shall be operated and the Plan provisions interpreted in a manner consistent with such requirements to the extent applicable.

7.5 Governing Law . This Plan shall be construed, administered and governed in all respects in accordance with ERISA and other applicable federal law and, to the extent not preempted by federal law, in accordance with the laws of the State of Texas. If any provisions of the Plan shall be held by a court of competent jurisdiction to be invalid or unenforceable, the remaining provisions hereof shall continue to be fully effective.

7.6 Severability . If any term, provision, covenant, or condition of the Plan is held to be invalid, void, or otherwise unenforceable, the rest of the Plan shall remain in full force and effect and shall in no way be affected, impaired, or invalidated.

7.7 Notice . Any notice or filing required or permitted to be given to the Committee under this Plan shall be sufficient if in writing and hand delivered, or sent by registered or certified mail, to the principal office of the Company. Such notice shall be deemed given as of the date of delivery or, if delivery is made by mail, as of the dates shown on the postmark on the receipt for registration or certification.

[Signature Page To Follow]

-13-

IN WITNESS WHEREOF , CenterPoint Energy, Inc. has caused these presents to be executed by its duly authorized officer in a number of copies, all of which shall constitute one and the same instrument, which may be sufficiently evidenced by any executed copy hereof, this 17th day of October, 2008, but effective as of January 1, 2009.

	CENTERPOINT ENERGY, INC.


By:	/s/ David M. McClanahan
	David M. McClanahan
	President and Chief Executive Officer

ATTEST :
/s/ Richard Dauphin
Richard Dauphin
Assistant Corporate Secretary

-14-

Exhibit 10.2

HOUSTON LIGHTING & POWER COMPANY

Executive Incentive Compensation Plan

(As Amended and Restated as of January 1, 1985)

Houston Lighting & Power Company, a Texas corporation (the “Company” herein), hereby establishes and adopts the following Executive Incentive Compensation Plan (the “Plan”):

Purpose.

The purpose of the Plan is to encourage a high level of corporate performance through the establishment of specific corporate and individual goals, the obtainment of which will require a high degree of competence and diligence on the part of the executive employees of the Company selected to participate in the Plan, and which will be beneficial to the owners and customers of the Company.

2.	Definitions.

The following definitions are applicable to the Plan:

“Award” means a payment made in accordance with the provisions of the Plan.

“Board of Directors” means the Board of Directors of the Company.

“Committee” means the Personnel Committee referred to in Section 3 hereof.

“Management” means the senior officers of the Company responsible for determining business and strategic policies.

“Maximum Incentive Award Opportunity” means the maximum Award which possibly could be made to a Participant during a Plan Year.

“Participant” means an employee who is selected to participate in the Plan.

“Performance Goals” means the annual performance objectives of the Company and individual Participants established for the purpose of determining the level of Awards, if any, earned during a Plan Year.

“Plan Year” means the calendar year.

3.	Administration.

The Plan shall be administered by the Personnel Committee (the “Committee”) of the Board of Directors, which Committee shall in no event have as a member a person entitled to receive an Award under the Plan. All decisions of the Committee shall be binding and conclusive on the Participants. Subject to the provisions of the Plan the Committee shall have the authority to:

(i) Select the Participants;

(ii) Approve Performance Goals for the Company and for each Participant;

(iii) Approve the level of the Maximum Incentive Award Opportunity and actual Award that may be made to each Participant; and

(iv) Establish from time to time policies and regulations for the administration of the Plan, interpret the Plan, and make all determinations necessary or advisable for the administration of the Plan .

4.	Participation.

Participants in the Plan shall be selected for each Plan Year from those employees of the Company whose decisions contribute directly to the annual success of the Company. No employee shall at any time have the right (i) to be selected as a Participant in the Plan for any Plan Year, (ii) if so selected, to be entitled automatically to an Award, nor, (iii) having been

selected as a Participant for one Plan Year, to be selected as a Participant in any subsequent Plan Year.

5.	Performance Goals.

The Committee, upon recommendation by Management, shall establish for each Plan Year Corporate Performance Goals designed to accomplish such financial and strategic objectives as it may from time to time determine appropriate. The Committee shall have the authority to adjust the Corporate Performance Goals for any Plan Year as it deems equitable in recognition of extraordinary or non-recurring events experienced by the Company during the Plan Year or in the event of changes in applicable accounting rules or principles or changes in the Company’s methods of accounting during the Plan Year.

6.	Maximum Amount Available For Awards.

For each Plan Year, the Committee shall establish a Maximum Incentive Award Opportunity that may be made to each Participant. The maximum amount which may be paid as Awards for any Plan Year shall be limited to the lesser of (i) the sum of the Maximum Incentive Award Opportunities for all Participants for that Plan Year, or (ii) 3/4 of 1% of the Company’s net income for that Plan Year. If the net income limit is applicable, all Awards shall be proportionately reduced to comply with the net income limit.

7.	Determination of Awards.

Subject to the provisions of Sections 5 and 6 hereof, the Committee shall approve the Awards for each Plan Year taking into consideration actual performance of the Company for such Plan Year in relation to the established corporate goals.

8.	Payment of Awards.

(a) Awards for 1982 . Each Award granted for the 1982 Award Year (i.e., the 1982 Plan Year for which a 1982 Award is earned) shall be a Contingent Award subject to the further provisions of this paragraph 8.

(b) Awards for 1983 and Subsequent Award Years . Each Award granted for the 1983 Award Year or any subsequent Award Year shall be divided into two equal portions, to be known as the 50% vested portion and the 50% contingent portion, respectively, of the Award.

(c) Payment of Vested Portions of Award . The payment of the 50% vested portion of each Award granted for the 1983 Award Year or for any subsequent Award Year shall be made in cash to the Participant as soon as practicable after the close of the Award Year, unless the Participant has irrevocably elected, with respect to an Award for 1984 or an earlier Award Year, to defer payment of such vested portion of such Award as provided in subparagraph (g) below by filing a written election form with the Committee prior to the beginning of such Award Year.

(d) Contingent Accounts of Participants . Each Participant’s 1982 Contingent Award and the 50% contingent portion of his Award for 1983 or for any subsequent Award Year shall be converted into a fixed dollar amount as of the close of the applicable Award Year and shall be credited to such Participants’ Contingent Account on the Company’s records of this Plan; subject, however, to the forfeiture provisions of subparagraph (f) below and other provisions of this paragraph 8. Each such Contingent Account shall be credited with interest at the end of each Plan Year as provided in subparagraph (h) below.

(e) Payment of Participant’s Contingent Account and Portion of Current Award upon his Retirement, Death or Disability . If a Participant’s employment with the

Company terminates because of retirement after attainment of age 60, death, or total and permanent disability (i.e., disability resulting in a disability benefit under the Company’s Long-Term Disability Plan), such Participant, or his Beneficiary or estate in the event of his death, shall be entitled to receive payment, in 15 substantially equal annual installments commencing as soon as practicable after the close of the Plan Year during which such termination of employment occurs, of (i) the entire balance of such Participant’s Contingent Account at the close of the Plan Year during which the termination of his employment occurs, plus interest credited in accordance with subparagraph (h) on the unpaid balance during the payment period, and (ii) a pro-rata portion of his Award, if any, for the current Award Year, determined by reference to the portion of the current Award Year during which the Participant was employed. In its sole discretion, the Committee may commute the value to be paid in installments and make payment in a single lump sum or in monthly, quarterly or annual installments over a period of time of less than 15 years, in any of which events the amounts to be paid are to be determined by reference to the annual interest rate credited as provided in subparagraph (h) of this paragraph 8. For purposes of this subparagraph (e) and other provisions of paragraph 8, a Participant shall be deemed to be employed by the Company during any period of time he is employed by Houston Industries Incorporated or any other wholly-owned subsidiary of Houston Industries Incorporated or the Company. Any amount payable after a Participant’s death shall be paid to the Beneficiary or Beneficiaries designated by such Participant in accordance with the procedures established by the Committee, or in the absence of such designation or the failure of any designated Beneficiary to survive the Participant, to the Participant’s estate.

(f) Forfeiture of Contingent Account . If a participant’s employment with the Company is terminated for any reason other than retirement, death or disability, as more fully

described in subparagraph (e) above, such Participant shall forfeit the entire amount in his Contingent Account and his entire interest in his Award, if any, for the current Award Year. All such forfeited amounts shall be cancelled and the Company shall have no obligation whatsoever to pay such forfeited amounts to the Participant or to any other person.

(g) Payment of Deferred Vested Awards . Each Deferred Vested Award for 1984 or an earlier Award Year shall be credited to the Participant’s Deferred Vested Account, which shall not be subject to forfeiture, and shall be paid to the Participant, or his Beneficiary or estate in the event of his death, at the end of the deferral period designated in the written election form, or at the time of Participant’s earlier termination of employment. Such Deferred Vested Account shall be credited with interest, as provided in subparagraph (h) of this paragraph 8, from the end of the Award Year during which any Deferred Vested Award is earned to the end of the Plan Year preceding payment. Notwithstanding any contrary provisions in the Participant’s written election form, the balance in the Participant’s Deferred Vested Account shall be paid in 15 substantially equal annual installments commencing on the earlier of (i) the deferral date designated in the written election form, or (ii) the first day of the month next following the month during which the Participant terminates employment with the Company for any reason. In its sole discretion, the Committee may commute the value to be paid in installments and make payment in a single lump sum or in monthly, quarterly or annual installments over a period of time of less than 15 years, in any of which events the amounts to be paid are to be determined by reference to the annual interest rate credited to the Deferred Vested Accounts of Participant, as provided in subparagraph (h) of this Paragraph 8.

(h) Interest Computation . Interest to be credited prior to January 1, 1985 to the Contingent Accounts of Participants, as provided in subparagraph (c) above, and to the

Deferred Vested Accounts of Participants, as provided in subparagraph (g) above, and interest to be credited to new Contingent Awards for Award Years beginning on or after January 1, 1985 shall be computed at the end of each Plan Year by using the weighted average interest rate incurred by the Company for short-term borrowings having maturities of less than one year, during such applicable Plan Year, and such interest shall be compounded annually. Interest to be credited from and after January 1, 1985 to the Contingent Accounts of Participants attributable to contingent awards for Plan Years prior to 1985 and the interest to be credited to the Deferred Vested Accounts of Participants attributable to Deferred Vested Awards for Plan Years prior to 1985, shall be computed at the end of each Plan Year at an annual interest rate, compounded annually, determined by reference to the Participant’s Age, as of October 1, 1985, in accordance with the following schedule:

AGE	INTEREST RATE
49 or less	Moody’s Rate + 4%
50 to 54	22% per year until payment
55 to 59	23% per year until payment
60 or older	24% per year until payment

For purposes of this subparagraph (h) of paragraph 8, the following terms shall have the following meanings:

(i) “Moody’s Rate” means a rate of interest equal to the twelve month average of the composite yield of Moody’s Seasoned Corporate Bond Yield Index for the twelve calendar months in a calendar year as determined from Moody’s Bond Record published by Moody’s Investors Service, Inc. (or any successor thereto), or, if such yield is no longer published, a substantially similar average selected by the Committee.

(ii) “Age” means a Participant’s age on his birthday nearest to October 1, 1985.

9.	Assignments and Transfers.

A Participant shall not assign, encumber or transfer his rights and interests under the Plan and any attempt to do so shall render those rights and interests null and void.

10.	Employee Rights Under the Plan.

No employee or other person shall have any claim or right to be granted an Award under this Plan. Neither the Plan nor any action taken thereunder shall be construed as giving any employee any right to be retained in the employ of the Company.

11.	Withholding Taxes.

The Company shall withhold the amount of any Federal, state or local taxes attributable to any amounts payable under the Plan.

12.	Other Plans.

The payments and benefits under this Plan shall be excluded from considered compensation under the Houston Industries Incorporated Retirement Plan. Such payments however shall be included in considered compensation under the Houston Industries Incorporated Employee Savings Plan and the Houston Industries Incorporated Employee Stock Ownership Plan.

13.

Term.

Subject to earlier termination pursuant to the provisions of this Section 13, the Plan shall have a term of five years from its effective date, January 1, 1982; provided, however, the Board or terminate the Plan or any of Directors may amend, suspend portion thereof at any time.

IN WITNESS WHEREOF, the Company has executed this Plan this 16th day of August, 1985, but effective as of January 1, 1985.

	HOUSTON LIGHTING & POWER
	COMPANY

By:	/s/ Don D. Jordan
	Don D. Jordan, Chairman
	& Chief Executive Officer

ATTEST :
/s/ Hugh Rice Kelly
Secretary

Exhibit 10.3

HOUSTON LIGHTING & POWER COMPANY

EXECUTIVE INCENTIVE COMPENSATION PLAN

(As Amended and Restated Effective as of January 1, 1985)

First Amendment

WHEREAS , Houston Industries Incorporated, a Texas corporation (“HI”), maintained the Houston Lighting & Power Company Executive Incentive Compensation Plan, established effective as of January 1, 1982, and as amended and restated effective as of January 1, 1985, (the “Plan”), which made awards to eligible employees of HI in 1982, 1983, and 1984, subject to the vesting and other terms and conditions of the Plan; and

WHEREAS , CenterPoint Energy, Inc. (the “Company”), as successor to HI, became the sponsor of the Plan, effective as of August 31, 2002, and currently maintains the Plan; and

WHEREAS , as of January 1, 2005, only one participant in the Plan was an active employee of the Company who had not vested in the Plan benefits as of December 31, 2004 (with all such other Plan participants having either terminated and forfeited their Plan benefit or their Plan benefit being fully vested, earned and commenced as of December 31, 2004); and

WHEREAS , the Company desires to amend the Plan to comply with the requirements of Section 409A of the Internal Revenue Code of 1986, as amended (the “Code”), with respect to benefits, and the earnings thereon, that vest after December 31, 2004 and to reflect the change in the name of the plan sponsor and make certain related non-substantive changes;

NOW, THEREFORE , the Company, having reserved the right to amend the Plan in Section 13 thereof, does hereby amend the Plan, effective as of the dates indicated below, as follows:

1. Effective as of August 31, 2002, the term “Houston Lighting & Power Company” in the first paragraph of the Plan is hereby deleted and replaced with “CenterPoint Energy, Inc.”

2. Effective as of August 31, 2002, (i) the term “Personnel Committee” in the first sentence in Section 3 of the Plan is hereby deleted and replaced with the term “Compensation Committee” and (ii) the definition of “Committee” in Section 2 of the Plan is hereby amended to read as follows:

“‘Committee’ means the Compensation Committee referred to in Section 3 hereof.”

3. Effective as of January 1, 2008, (i) the Plan is hereby renamed the “CenterPoint Energy, Inc. 1982 Executive Incentive Compensation Plan,” and the Plan is hereby amended accordingly to reflect such change, and (ii) the term “Executive Incentive Compensation Plan” in the first paragraph of the Plan is hereby deleted and replaced with “CenterPoint Energy, Inc. 1982 Executive Incentive Compensation Plan, as amended and restated effective as of January 1, 1985, and as thereafter amended.”

4. Effective as of January 1, 2008, Section 8(e) of the Plan is hereby amended to read as follows:

“(e) Payment of Participant’s Contingent Account and Portion of Current Award upon his Retirement, Death or Disability . If a Participant’s employment with the Company terminates because of retirement after attainment of age 60, death, or total and permanent disability ( i.e. , disability resulting in a disability benefit under the Company’s Long-Term Disability Plan), such Participant, or his Beneficiary or estate in the event of his death, shall receive payment, in 15 substantially equal annual installments after January 1st, but prior to March 1st, of each Plan Year commencing with the Plan Year immediately following the Plan Year during which such termination of employment occurs, calculated on the entire balance of such Participant’s Contingent Account at the close of the Plan Year during which the termination of his employment occurs, plus interest credited in accordance with subparagraph (h) on the unpaid balance during the payment period. For purposes of this subparagraph (e) and other provisions of Section 8, a Participant shall be deemed to be employed by the Company during any period of time he is employed by the Company or any other wholly-owned subsidiary of the Company. Any amount payable after a Participant’s death shall be paid to the Beneficiary or Beneficiaries designated by such Participant in accordance with the procedures established by the Committee, or in the absence of such designation or the failure of any designated Beneficiary to survive the Participant, to the Participant’s estate.”

5. Effective as of January 1, 2008, the last sentence in Section 8(g) of the Plan is hereby deleted.

-2-

6. Effective as of January 1, 2008, Section 8 of the Plan is hereby amended to add the following new subsection (i) thereto:

“(i) Delay of Payments to Certain Participants . Notwithstanding any provision to the contrary in the Plan, with respect to Plan benefits that vest after December 31, 2004, including interest credited thereon (and thus subject to Section 409A of the Internal Revenue Code of 1986, as amended (‘Section 409A’)), if as of the date of the Participant’s ‘Separation from Service’ (within the meaning of that term under Section 409A), other than by reason of death, the Participant has been identified by the Committee or its delegate as a ‘Specified Employee’ (within the meaning of that term under Section 409A), then the payment provided under Section 8 of the Plan shall be made on the later of (i) the payment date provided in the applicable provision of Section 8 or (ii) the earlier of (A) the expiration of the 6-month period measured from the date of the Participant’s Separation from Service or (B) the Participant’s date of death. In the event a payment is delayed under this Section 8(i) (‘delayed amount’), the Company shall pay to the Participant, in a lump sum payment on the date it pays the delayed amount, interest on such delayed amount at the Moody’s Rate plus 4% based on the number of days the payment was delayed.”

7. Effective as of January 1, 2008, Section 12 of the Plan is hereby amended to read as follows:

“12. Other Plans . The payments and benefits under this Plan shall be excluded from considered compensation under the CenterPoint Energy, Inc. Retirement Plan (formerly known as the Houston Industries Incorporated Retirement Plan), as amended from time to time. Such payments however shall be included in considered compensation under the CenterPoint Energy Savings Plan (formerly known as the Houston Industries Incorporated Employee Savings Plan and which include the former Houston Industries Incorporated Employee Stock Ownership Plan), as amended from time to time.”

8. Effective as of January 1, 2008, the Plan is hereby amended to add the following new Section 14 to read as follows:

“14. Grandfathered Section 409A Benefits . Notwithstanding any provision of this Plan to the contrary, Awards that are earned and vested as of December 31, 2004, along with all interest earned thereon (“Grandfathered Section 409A Benefits”), and which are segregated from benefits that vest or are earned after December 31, 2004, shall be subject to the terms and conditions of the Plan as in effect on October 3, 2004. Such Grandfathered Section 409A Benefits shall not be subject to any amendment to the terms and conditions of the Plan that are made or effective after October 3, 2004 and are not subject to Section 409A.”

-3-

	CENTERPOINT ENERGY, INC.


By:	/s/ David M. McClanahan
	David M. McClanahan
	President and Chief Executive Officer

ATTEST :
/s/ Richard Dauphin
Richard Dauphin
Assistant Corporate Secretary

-4-

Exhibit 12

CENTERPOINT ENERGY, INCORPORATED AND SUBSIDIARIES

COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES

(Millions of Dollars)

	Nine Months Ended September 30,
	2007			2008

Net Income	$	291		$	360
Income tax expense		154			213
Capitalized interest		(18	)		(10	)
		427			563

Fixed charges, as defined:

Interest		461			446
Capitalized interest		18			10
Interest component of rentals charged to operating expense		12			11
Total fixed charges		491			467

Earnings, as defined	$	918		$	1,030

Ratio of earnings to fixed charges		1.87			2.21

________

(1)

Excluded from the computation of fixed charges for the nine months ended September 30, 2007 and 2008 is interest expense of $5 million and $10 million, respectively, which is included in income tax expense. The ratio of earnings to fixed charges would be 1.85 and 2.16, respectively, for the nine months ended September 30, 2007 and 2008, if the interest expense included in income tax expense were included in the computation of fixed charges.

Exhibit 31.1

CERTIFICATIONS

I, David M. McClanahan, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

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

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

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

(a)

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

(b)

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

(c)

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

(d)

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

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

(a)

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

(b)

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

Date: November 5, 2008

	/s/ David M. McClanahan
	David M. McClanahan
	President and Chief Executive Officer

Exhibit 31.2

CERTIFICATIONS

I, Gary L. Whitlock, certify that:

1. I have reviewed this quarterly report on Form 10-Q of CenterPoint Energy, Inc.;

(a)

(b)

(c)

(d)

(a)

(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: November 5, 2008

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

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 Quarterly Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2008 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, David M. McClanahan, Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ David M. McClanahan
David M. McClanahan
President and Chief Executive Officer
November 5, 2008

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 Quarterly Report of CenterPoint Energy, Inc. (the “Company”) on Form 10-Q for the quarter ended September 30, 2008 (the “Report”), as filed with the Securities and Exchange Commission on the date hereof, I, Gary L. Whitlock, Chief Financial Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, to the best of my knowledge, that:

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

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

/s/ Gary L. Whitlock
Gary L. Whitlock
Executive Vice President and Chief Financial Officer
November 5, 2008

Exhibit 99.1


Item 1A.	Risk Factors

We are a holding company that conducts all of our business operations through subsidiaries, primarily CenterPoint Houston and CERC. The following, along with any additional legal proceedings identified or incorporated by reference in Item 3 of this report, summarizes the principal risk factors associated with the businesses conducted by each of these subsidiaries:

Risk Factors Affecting Our Electric Transmission & Distribution Business

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

In March 2004, CenterPoint Houston filed its true-up application with the Texas Utility Commission, requesting recovery of $3.7 billion, excluding interest, as allowed under the Texas electric restructuring law. In December 2004, the Texas Utility Commission issued the True-Up Order allowing CenterPoint Houston to recover a true-up balance of approximately $2.3 billion, which included interest through August 31, 2004, and provided for adjustment of the amount to be recovered to include interest on the balance until recovery, along with the principal portion of additional EMCs returned to customers after August 31, 2004 and in certain other respects.

•	reversed the Texas Utility Commission’s ruling that had denied recovery of a portion of the capacity auction true-up amounts;

•	reversed the Texas Utility Commission’s ruling that precluded CenterPoint Houston from recovering the interest component of the EMCs paid to REPs; and

•	affirmed the True-Up Order in all other respects.

CenterPoint Houston and other parties appealed the district court’s judgment to the Texas Third Court of Appeals, which issued its decision in December 2007. In its decision, the court of appeals:

•	reversed the district court’s judgment to the extent it restored the capacity auction true-up amounts;

•	reversed the district court’s judgment to the extent it upheld the Texas Utility Commission’s decision to allow CenterPoint Houston to recover EMCs paid to RRI;

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

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

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

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

In the True-Up Order the Texas Utility Commission reduced CenterPoint Houston’s stranded cost recovery by approximately $146 million, which was included in the extraordinary loss discussed above, for the present value of certain deferred tax benefits associated with its former electric generation assets. We believe that the Texas Utility Commission based its order on proposed regulations issued by the IRS in March 2003 which would have allowed utilities owning assets that were deregulated before March 4, 2003 to make a retroactive election to pass the benefits of ADITC and EDFIT back to customers. However, 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. We subsequently requested a PLR asking the IRS whether the Texas Utility Commission’s order reducing CenterPoint Houston’s stranded cost recovery by $146 million for ADITC and EDFIT would cause normalization violations. In that ruling, which was received in August 2007, the IRS concluded that such reductions would cause normalization violations with respect to the ADITC and EDFIT. As in a similar PLR issued in May 2006 to another Texas utility, the IRS did not reference its proposed regulations.

The district court affirmed the Texas Utility Commission’s ruling on the tax normalization issue, but in response to a request from the Texas Utility Commission, the court of appeals ordered that the tax normalization issue be remanded for further consideration. If the Texas Utility Commission’s order relating to the ADITC reduction is not reversed or otherwise modified on remand so as to eliminate the normalization violation, the IRS could require us to pay an amount equal to CenterPoint Houston’s unamortized ADITC balance as of the date that the normalization violation is deemed to have occurred. In addition, the IRS could deny CenterPoint Houston the ability to elect accelerated tax depreciation benefits beginning in the taxable year that the normalization violation is deemed to have occurred. Such treatment if required by the IRS, could have a material adverse impact on our results of operations, financial condition and cash flows in addition to any potential loss resulting from final resolution of the True-Up Order. However, we and CenterPoint Houston will continue to pursue a favorable resolution of this issue through the appellate or administrative process. Although the Texas Utility Commission has not previously required a company subject to its jurisdiction to take action that would result in a normalization violation, no prediction can be made as to the ultimate action the Texas Utility Commission may take on this issue on remand.

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

CenterPoint Houston’s receivables from the distribution of electricity are collected from REPs that supply the electricity CenterPoint Houston distributes to their customers. Currently, CenterPoint Houston does business with 74 REPs. Adverse economic conditions, structural problems in the market served by ERCOT or financial difficulties of one or more REPs could impair the ability of these retail providers to pay for CenterPoint Houston’s services or could cause them to delay such payments. CenterPoint Houston depends on these REPs to remit payments on a timely basis. Applicable regulatory provisions require that customers be shifted to a provider of last resort if a retail electric provider cannot make timely payments. Applicable Texas Utility Commission regulations limit the extent to which CenterPoint Houston can demand security from REPs for payment of its delivery charges. RRI, through its subsidiaries, is CenterPoint Houston’s largest customer. Approximately 48% of CenterPoint Houston’s $141 million in billed receivables from REPs at December 31, 2007 was owed by subsidiaries of RRI.

Any delay or default in payment could adversely affect CenterPoint Houston’s cash flows, financial condition and results of operations.

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

CenterPoint Houston’s rates are regulated by certain municipalities and the Texas Utility Commission based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CenterPoint Houston is allowed to charge may not match its expenses at any given time. In this connection, pursuant to the Settlement Agreement, discussed in “Business — Regulation — State and Local Regulation — Electric Transmission & Distribution — CenterPoint Houston Rate Agreement” in Item 1 of this report, until June 30, 2010 CenterPoint Houston is limited in its 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 CenterPoint Houston’s costs and enable CenterPoint Houston to earn a reasonable return on its invested capital.

Disruptions at power generation facilities owned by third parties could interrupt CenterPoint Houston’s sales of transmission and distribution services.

CenterPoint Houston transmits and distributes to customers of REPs electric power that the REPs obtain from power generation facilities owned by third parties. CenterPoint Houston does not own or operate any power generation facilities. If power generation is disrupted or if power generation capacity is inadequate, CenterPoint Houston’s sales of transmission and distribution services may be diminished or interrupted, and its results of operations, financial condition and cash flows may be adversely affected.

CenterPoint Houston’s revenues and results of operations are seasonal.

A significant portion of CenterPoint Houston’s revenues is derived from rates that it collects from each retail electric provider based on the amount of electricity it distributes on behalf of such retail electric provider. Thus, CenterPoint Houston’s revenues and results of operations are subject to seasonality, weather conditions and other changes in electricity usage, with revenues being higher during the warmer months.

Risk Factors Affecting Our Natural Gas Distribution, Competitive Natural Gas Sales and Services, Interstate Pipelines and Field Services Businesses

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

CERC’s rates for its Gas Operations are regulated by certain municipalities and state commissions, and for its interstate pipelines by the FERC, based on an analysis of its invested capital and its expenses in a test year. Thus, the rates that CERC is allowed to charge may not match its expenses at any given time. The regulatory process in which rates are determined may not always result in rates that will produce full recovery of CERC’s costs and enable CERC to earn a reasonable return on its invested capital.

CERC’s businesses must compete with alternative energy sources, which could result in CERC marketing less natural gas, and its interstate pipelines and field services businesses must compete directly with others in the transportation, storage, gathering, treating and processing of natural gas, which could lead to lower prices, either of which could have an adverse impact on CERC’s results of operations, financial condition and cash flows.

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

natural gas directly to commercial and industrial customers. Any reduction in the amount of natural gas marketed, sold or transported by CERC as a result of competition may have an adverse impact on CERC’s results of operations, financial condition and cash flows.

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

CERC’s natural gas distribution and competitive natural gas sales and services businesses are subject to fluctuations in natural gas pricing levels, which could affect the ability of CERC’s suppliers and customers to meet their obligations or otherwise adversely affect CERC’s liquidity.

CERC is subject to risk associated with increases in the price of natural gas. Increases in natural gas prices might affect CERC’s ability to collect balances due from its customers and, for Gas Operations, could create the potential for uncollectible accounts expense to exceed the recoverable levels built into CERC’s tariff rates. In addition, a sustained period of high natural gas prices could apply downward demand pressure on natural gas consumption in the areas in which CERC operates and increase the risk that CERC’s suppliers or customers fail or are unable to meet their obligations. Additionally, increasing natural gas prices could create the need for CERC to provide collateral in order to purchase natural gas.

If CERC were to fail to renegotiate a contract with one of its significant pipeline customers or if CERC renegotiates the contract on less favorable terms, there could be an adverse impact on its operations.

Since October 31, 2006, CERC’s contract with Laclede, one of its pipeline customers, has been terminable upon one year’s prior notice. CERC has not received a termination notice and is currently negotiating a long-term contract with Laclede. If Laclede were to terminate this contract or if CERC were to renegotiate this contract at rates substantially lower than the rates provided in the current contract, there could be an adverse effect on CERC’s results of operations, financial condition and cash flows.

A decline in CERC’s credit rating could result in CERC’s having to provide collateral in order to purchase gas.

If CERC’s credit rating were to decline, it might be required to post cash collateral in order to purchase natural gas. If a credit rating downgrade and the resultant cash collateral requirement were to occur at a time when CERC was experiencing significant working capital requirements or otherwise lacked liquidity, CERC might be unable to obtain the necessary natural gas to meet its obligations to customers, and its results of operations, financial condition and cash flows would be adversely affected.

The revenues and results of operations of CERC’s interstate pipelines and field services businesses are subject to fluctuations in the supply of natural gas.

CERC’s interstate pipelines and field services businesses largely rely on natural gas sourced in the various supply basins located in the Mid-continent region of the United States. To the extent the availability of this supply is substantially reduced, it could have an adverse effect on CERC’s results of operations, financial condition and cash flows.

CERC’s revenues and results of operations are seasonal.

A substantial portion of CERC’s revenues is derived from natural gas sales and transportation. Thus, CERC’s revenues and results of operations are subject to seasonality, weather conditions and other changes in natural gas usage, with revenues being higher during the winter months.

The actual cost of pipelines under construction and related compression facilities may be significantly higher than CERC’s current estimates.

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

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

The Public Utility Holding Company Act of 1935, to which the Company was subject prior to its repeal in the Energy Act, provided a comprehensive regulatory structure governing the organization, capital structure, intracompany relationships and lines of business that could be pursued by registered holding companies and their member companies. Following repeal of that Act, some states in which CERC does business have sought to expand their own regulatory frameworks to give their regulatory authorities increased jurisdiction and scrutiny over similar aspects of the utilities that operate in their states. Some of these frameworks attempt to regulate financing activities, acquisitions and divestitures, and arrangements between the utilities and their affiliates, and to restrict the level of non-utility businesses that can be conducted within the holding company structure. Additionally they may impose record keeping, record access, employee training and reporting requirements related to affiliate transactions and reporting in the event of certain downgrading of the utility’s bond rating.

These regulatory frameworks could have adverse effects on CERC’s ability to operate its utility operations, to finance its business and to provide cost-effective utility service. In addition, if more than one state adopts restrictions over similar activities, it may be difficult for CERC and us to comply with competing regulatory requirements.

Risk Factors Associated with Our Consolidated Financial Condition

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

As of December 31, 2007, we had $9.7 billion of outstanding indebtedness on a consolidated basis, which includes $2.3 billion of non-recourse transition bonds. As of December 31, 2007, approximately $842 million principal amount of this debt is required to be paid through 2010. This amount excludes principal repayments of approximately $525 million on transition bonds, for which a dedicated revenue stream exists. In addition, as of December 31, 2007, we had $535 million of outstanding 3.75% convertible notes on which holders could exercise their conversion rights during the first quarter of 2008 and in subsequent quarters in which our common stock price causes such notes to be convertible. In January and February 2008, holders of our 3.75% convertible senior notes converted approximately $123 million principal amount of such notes. In February 2008, we issued approximately $488 million of additional non-recourse transition bonds. Our future financing activities may depend, at least in part, on:

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

•	general economic and capital market conditions;

•	credit availability from financial institutions and other lenders;

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

•	maintenance of acceptable credit ratings;

•	market expectations regarding our future earnings and cash flows;

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

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

•	provisions of relevant tax and securities laws.

As of December 31, 2007, CenterPoint Houston 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 we are obligated and approximately $229 million held in trust to secure pollution control bonds for which CenterPoint Houston is obligated. Additionally, CenterPoint Houston had outstanding approximately $253 million aggregate principal amount of first mortgage bonds, including approximately $151 million held in trust to secure certain pollution control bonds for which we are obligated. CenterPoint Houston may issue additional general mortgage bonds on the basis of retired bonds, 70% of property additions or cash deposited with the trustee. Approximately $2.3 billion of additional first mortgage bonds and general mortgage bonds in the aggregate could be issued on the basis of retired bonds and 70% of property additions as of December 31, 2007. However, CenterPoint Houston has contractually agreed that it will not issue additional first mortgage bonds, subject to certain exceptions.

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

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

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

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

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

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

Risks Common to Our Businesses and Other Risks

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

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety and the environment, as discussed in “Business — Environmental Matters” in Item 1 of this report. As an owner or operator of natural gas pipelines and distribution systems, gas gathering and processing systems, and electric transmission and distribution systems, we must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or impact our business activities in many ways, such as:

•	restricting the way we can handle or dispose of wastes;

•	limiting or prohibiting construction activities in sensitive areas such as wetlands, coastal regions, or areas inhabited by endangered species;

•	requiring remedial action to mitigate pollution conditions caused by our operations, or attributable to former operations; and

•	enjoining the operations of facilities deemed in non-compliance with permits issued pursuant to such environmental laws and regulations.

In order to comply with these requirements, we may need to spend substantial amounts and devote other resources from time to time to:

•	construct or acquire new equipment;

•	acquire permits for facility operations;

•	modify or replace existing and proposed equipment; and

•	clean up or decommission waste disposal areas, fuel storage and management facilities and other locations and facilities.

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

Our insurance coverage may not be sufficient. Insufficient insurance coverage and increased insurance costs could adversely impact our results of operations, financial condition and cash flows.

commercially reasonable terms, and the insurance proceeds received for any loss of, or any damage to, any of our facilities may not be sufficient to restore the loss or damage without negative impact on our results of operations, financial condition and cash flows.

In common with other companies in its line of business that serve coastal regions, CenterPoint Houston does not have insurance covering its transmission and distribution system because CenterPoint Houston believes it to be cost prohibitive. If CenterPoint Houston were to sustain any loss of, or damage to, its transmission and distribution properties, it may not be able to recover such loss or damage through a change in its regulated rates, and any such recovery may not be timely granted. Therefore, CenterPoint Houston may not be able to restore any loss of, or damage to, any of its transmission and distribution properties without negative impact on its results of operations, financial condition and cash flows.

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

Under some circumstances, we, CenterPoint Houston and CERC could incur liabilities associated with assets and businesses we, CenterPoint Houston and CERC no longer own. These assets and businesses were previously owned by Reliant Energy, a predecessor of CenterPoint Houston, 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, us and our subsidiaries, including CenterPoint Houston and CERC, with respect to liabilities associated with the transferred assets and businesses. These indemnity provisions were intended to place sole financial responsibility on RRI and its subsidiaries for all liabilities associated with the current and historical businesses and operations of RRI, regardless of the time those liabilities arose. If RRI were unable to satisfy a liability that has been so assumed in circumstances in which Reliant Energy and its subsidiaries were not released from the liability in connection with the transfer, we, CenterPoint Houston or CERC could be responsible for satisfying the liability.

Prior to the distribution of our ownership in RRI to our shareholders, CERC had guaranteed certain contractual obligations of what became RRI’s trading subsidiary. Under the terms of the separation agreement between the companies, RRI agreed to extinguish all such guaranty obligations prior to separation, but at the time of separation in September 2002, RRI had been unable to extinguish all obligations. To secure CERC against obligations under the remaining guaranties, RRI agreed to provide cash or letters of credit for the benefit of CERC, and undertook to use commercially reasonable efforts to extinguish the remaining guaranties. In February 2007, we and CERC made a formal demand on RRI in connection with one of the two remaining guaranties under procedures provided by the Master Separation Agreement, dated December 31, 2000, between Reliant Energy and RRI. That demand sought to resolve a disagreement with RRI over the amount of security RRI is obligated to provide with respect to this guaranty. In December 2007, we, CERC and RRI amended the agreement relating to the security to be provided by RRI for these guaranties, pursuant to which CERC released the $29.3 million in letters of credit RRI had provided as security, and RRI agreed to provide cash or new letters of credit to secure CERC against exposure under the remaining guaranties as calculated under the new agreement if and to the extent changes in market conditions exposed CERC to a risk of loss on those guaranties.

The remaining exposure to CERC under the guaranties relates to payment of demand charges related to transportation contracts. The present value of the demand charges under those transportation contracts, which will be effective until 2018, was approximately $135 million as of December 31, 2007. RRI continues to meet its obligations under the contracts, and we believe current market conditions make those contracts valuable in the near term and that additional security is not needed at this time. However, changes in market conditions could affect the value of those contracts. If RRI should fail to perform its obligations under the contracts or if RRI should fail to

provide security in the event market conditions change adversely, our exposure to the counterparty under the guaranty could exceed the security provided by RRI.

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 Houston could incur liability if claims in one or more of these lawsuits were successfully asserted against us or CenterPoint Houston and indemnification from RRI were determined to be unavailable or if RRI were unable to satisfy indemnification obligations owed with respect to those claims.

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

We or our subsidiaries have been named, along with numerous others, as a defendant in lawsuits filed by a 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 we own, but most existing claims relate to facilities previously owned by our 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 us 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 we have agreed to continue to defend such claims to the extent they are covered by insurance maintained by us, subject to reimbursement of the costs of such defense by Texas Genco LLC.